Friday, 

March 26, 2010 

Book 2 of 2 Books 

Pages 14669–15320 

Part II 

Environmental 

Protection Agency 

40 CFR Part 80 

Regulation of Fuels and Fuel Additives: 

Changes to Renewable Fuel Standard 

Program; Final Rule 

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14670 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 80 

[EPA–HQ–OAR–2005–0161; FRL–9112–3] 

RIN 2060–A081 

Regulation of Fuels and Fuel 

Additives: Changes to Renewable Fuel 

Standard Program 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: Under the Clean Air Act 

Section 211(o), as amended by the 

Energy Independence and Security Act 

of 2007 (EISA), 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. This action finalizes the 

regulations that implement the 

requirements of EISA, including the 

cellulosic, biomass-based diesel, 

advanced biofuel, and renewable fuel 

standards that will apply to all gasoline 

and diesel produced or imported in 

2010. The final 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. This final rule also implements 

the revised statutory definitions and 

criteria, most notably the new 

greenhouse gas emission thresholds for 

renewable fuels and new limits on 

renewable biomass feedstocks. This 

rulemaking marks the first time that 

greenhouse gas emission performance is 

being applied in a regulatory context for 

a nationwide program. As mandated by 

the statute, our greenhouse gas emission 

assessments consider the full lifecycle 

emission impacts of fuel production 

from both direct and indirect emissions, 

including significant emissions from 

land use changes. In carrying out our 

lifecycle analysis we have taken steps to 

ensure that the lifecycle estimates are 

based on the latest and most up-to-date 

science. The lifecycle greenhouse gas 

assessments reflected in this rulemaking 

represent significant improvements in 

analysis based on information and data 

received since the proposal. However, 

we also recognize that lifecycle GHG 

assessment of biofuels is an evolving 

discipline and will continue to revisit 

our lifecycle analyses in the future as 

new information becomes available. 

EPA plans to ask the National Academy 

of Sciences for assistance as we move 

forward. Based on current analyses we 

have determined that ethanol from corn 

starch will be able to comply with the 

required greenhouse gas (GHG) 

threshold for renewable fuel. Similarly, 

biodiesel can be produced to comply 

with the 50% threshold for biomassbased diesel, sugarcane with the 50% 

threshold for advanced biofuel and 

multiple cellulosic-based fuels with 

their 60% threshold. Additional fuel 

pathways have also been determined to 

comply with their thresholds. The 

assessment for this rulemaking also 

indicates the increased use of renewable 

fuels will have important 

environmental, energy and economic 

impacts for our Nation. 

DATES: This final rule is effective on July 

1, 2010, and the percentage standards 

apply to all gasoline and diesel 

produced or imported in 2010. The 

incorporation by reference of certain 

publications listed in the rule is 

approved by the Director of the Federal 

Register as of July 1, 2010. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–OAR–2005–0161. All 

documents in the docket are listed in 

the http://www.regulations.gov Web 

site. Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically through 

http://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. 

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 

I. Does This Final Rule Apply to Me? 

Entities potentially affected by this 

final rule 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) 

2Standard 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 final action. This table 

lists the types of entities that EPA is 

now aware could potentially be 

regulated by this final action. Other 

types of entities not listed in the table 

could also be regulated. To determine 

whether your activities would be 

regulated by this final action, you 

should carefully examine the 

applicability criteria in 40 CFR part 80. 

If you have any questions regarding the 

applicability of this final action to a 

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particular entity, consult the person 

listed in the preceding section. 

Outline of This Preamble 

I. Executive Summary 

A. Summary of New Provisions of the RFS 

Program 

1. Required Volumes of Renewable Fuel 

2. Standards for 2010 and Effective Date for 

New Requirements 

a. 2010 Standards 

b. Effective Date 

3. Analysis of Lifecycle Greenhouse Gas 

Emissions and Thresholds for Renewable 

Fuels 

a. Background and Conclusions 

b. Fuel Pathways Considered and Key 

Model Updates Since the Proposal 

c. Consideration of Fuel Pathways Not Yet 

Modeled 

4. Compliance with Renewable Biomass 

Provision 

5. EPA-Moderated Transaction System 

6. Other Changes to the RFS Program 

B. Impacts of Increasing Volume 

Requirements in the RFS2 Program 

II. Description of the Regulatory Provisions 

A. Renewable Identification Numbers 

(RINs) 

B. New Eligibility Requirements for 

Renewable Fuels 

1. Changes in Renewable Fuel Definitions 

a. Renewable Fuel 

b. Advanced Biofuel 

c. Cellulosic Biofuel 

d. Biomass-Based Diesel 

e. Additional Renewable Fuel 

f. Cellulosic Diesel 

2. Lifecycle GHG Thresholds 

3. Renewable Fuel Exempt From 20 

Percent GHG Threshold 

a. General Background of the Exemption 

Requirement 

b. Definition of Commenced Construction 

c. Definition of Facility Boundary 

d. Proposed Approaches and Consideration 

of Comments 

i. Comments on the Proposed Basic 

Approach 

ii. Comments on the Expiration of 

Grandfathered Status 

e. Final Grandfathering Provisions 

i. Increases in Volume of Renewable Fuel 

Produced at Grandfathered Facilities Due 

to Expansion 

ii. Replacements of Equipment 

iii. Registration, Recordkeeping and 

Reporting 

4. New Renewable Biomass Definition and 

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 

v. Algae 

b. Implementation of Renewable Biomass 

Requirements 

i. Ensuring That RINs Are Generated Only 

For Fuels Made From Renewable 

Biomass 

ii. Whether RINs Must Be Generated For 

All Qualifying Renewable Fuel 

c. Implementation Approaches for 

Domestic Renewable Fuel 

i. Recordkeeping and Reporting for 

Feedstocks 

ii. Approaches for Foreign Producers of 

Renewable Fuel 

(1) RIN-Generating importers 

(2) RIN-Generating foreign producers 

iii. Aggregate Compliance Approach for 

Planted Crops and Crop Residue From 

Agricultural Land 

(1) Analysis of Total Agricultural Land in 

2007 

(2) Aggregate Agricultural Land Trends 

Over Time 

(3) Aggregate Compliance Determination 

d. Treatment of Municipal Solid Waste 

(MSW) 

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. Producers 

b. Importers 

c. Additional Provisions for Foreign 

Producers 

3. Facilities With Multiple Applicable 

Pathways 

4. Facilities That Co-Process Renewable 

Biomass and Fossil Fuels 

5. Facilities That Process Municipal Solid 

Waste 

6. RINless Biofuel 

E. Applicable Standards 

1. Calculation of Standards 

a. How Are the Standards Calculated? 

b. Standards for 2010 

2. Treatment of Biomass-Based Diesel in 

2009 and 2010 

a. Shift in 2009 Biomass-Based Diesel 

Compliance Demonstration to 2010 

b. Treatment of Deficit Carryovers, RIN 

Rollover, and RIN Valid Life For 

Adjusted 2010 Biomass-Based Diesel 

Requirement 

3. Future Standards 

F. Fuels That Are Subject to the Standards 

1. Gasoline 

2. Diesel 

3. Other Transportation Fuels 

G. Renewable Volume Obligations (RVOs) 

1. Designation of Obligated Parties 

2. Determination of RVOs Corresponding to 

the Four Standards 

3. RINs Eligible To Meet Each RVO 

4. Treatment of RFS1 RINs Under RFS2 

a. Use of RFS1 RINs To Meet Standards 

Under RFS2 

b. Deficit Carryovers From the RFS1 

Program to RFS2 

H. Separation of RINs 

1. Nonroad 

2. Heating Oil and Jet Fuel 

3. Exporters 

4. Requirement to Transfer RINs With 

Volume 

5. Neat Renewable Fuel and Renewable 

Fuel Blends Designated as 

Transportation Fuel, Heating Oil, or Jet 

Fuel 

I. Treatment of Cellulosic Biofuel 

1. Cellulosic Biofuel Standard 

2. EPA Cellulosic Biofuel Waiver Credits 

for Cellulosic Biofuel 

3. Application of Cellulosic Biofuel Waiver 

Credits 

J. Changes to Recordkeeping and Reporting 

Requirements 

1. Recordkeeping 

2. Reporting 

3. Additional Requirements for Producers 

of Renewable Natural Gas, Electricity, 

and Propane 

4. Attest Engagements 

K. Production Outlook Reports 

L. What Acts Are Prohibited and Who Is 

Liable for Violations? 

III. Other Program Changes 

A. The EPA Moderated Transaction System 

(EMTS) 

1. Need for the EPA Moderated Transaction 

System 

2. Implementation of the EPA Moderated 

Transaction System 

3. How EMTS Will Work 

4. A Sample EMTS Transaction 

B. Upward Delegation of RIN-Separating 

Responsibilities 

C. Small Producer Exemption 

D. 20% Rollover Cap 

E. Small Refinery and Small Refiner 

Flexibilities 

1. Background—RFS1 

a. Small Refinery Exemption 

b. Small Refiner Exemption 

2. Statutory Options for Extending Relief 

3. The DOE Study/DOE Study Results 

4. Ability To Grant Relief Beyond 211(o)(9) 

5. Congress-Requested Revised DOE Study 

6. What We’re Finalizing 

a. Small Refinery and Small Refiner 

Temporary Exemptions 

b. Case-by-Case Hardship for Small 

Refineries and Small Refiners 

c. Program Review 

7. Other Flexibilities Considered for Small 

Refiners 

a. Extensions of the RFS1 Temporary 

Exemption for Small Refiners 

b. Phase-in 

c. RIN-Related Flexibilities 

F. Retail Dispenser Labeling for Gasoline 

With Greater Than 10 Percent Ethanol 

G. Biodiesel Temperature Standardization 

IV. Renewable Fuel Production and Use 

A. Overview of Renewable Fuel Volumes 

1. Reference Cases 

2. Primary Control Case 

a. Cellulosic Biofuel 

b. Biomass-Based Diesel 

c. Other Advanced Biofuel 

d. Other Renewable Fuel 

3. Additional Control Cases Considered 

B. Renewable Fuel Production 

1. Corn/Starch Ethanol 

a. Historic/Current Production 

b. Forecasted Production Under RFS2 

2. Imported Ethanol 

3. Cellulosic Biofuel 

a. Current State of the Industry 

b. Setting the 2010 Cellulosic Biofuel 

Standard 

c. Current Production Outlook for 2011 and 

Beyond 

d. Feedstock Availability 

i. Urban Waste 

ii. Agricultural and Forestry Residues 

iii. Dedicated Energy Crops 

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iv. Summary of Cellulosic Feedstocks for 

2022 

4. Biodiesel & Renewable Diesel 

a. Historic and Projected Production 

i. Biodiesel 

ii. Renewable Diesel 

b. Feedstock Availability 

C. Biofuel Distribution 

1. Biofuel Shipment to Petroleum 

Terminals 

2. Petroleum Terminal Accommodations 

3. Potential Need for Special Blendstocks 

at Petroleum Terminals for E85 

4. 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. Consideration of >10% Ethanol Blends 

V. Lifecycle Analysis of Greenhouse Gas 

Emissions 

A. Introduction 

1. Open and Science-Based Approach to 

EPA’s Analysis 

2. Addressing Uncertainty 

B. Methodology 

1. Scope of Analysis 

a. Inclusion of Indirect Land Use Change 

b. Models Used 

c. Scenarios Modeled 

2. Biofuel Modeling Framework & 

Methodology for Lifecycle Analysis 

Components 

a. Feedstock Production 

i. Domestic Agricultural Sector Impacts 

ii. International Agricultural Sector 

Impacts 

b. Land Use Change 

i. Amount of Land Area Converted and 

Where 

ii. Type of Land Converted 

iii. GHG Emissions Associated With 

Conversion 

(1) Domestic Emissions 

(2) International Emissions 

iv. Timeframe of Emission Analysis 

v. GTAP and Other Models 

c. Feedstock Transport 

d. Biofuel Processing 

e. Fuel Transportation 

f. Vehicle Tailpipe Emissions 

3. Petroleum Baseline 

C. Threshold Determination and 

Assignment of Pathways 

D. Total GHG Reductions 

E. Effects of GHG Emission Reductions and 

Changes in Global Temperature and Sea 

Level 

VI. 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. Particulate Matter 

a. Current Levels 

b. Projected Levels Without RFS2 Volumes 

c. Projected Levels With RFS2 Volumes 

2. Ozone 

a. Current Levels 

b. Projected Levels Without RFS2 Volumes 

c. Projected Levels With RFS2 Volumes 

3. Air Toxics 

a. Current Levels 

b. Projected Levels 

i. Acetaldehyde 

ii. Formaldehyde 

iii. Ethanol 

iv. Benzene 

v. 1,3-Butadiene 

vi. Acrolein 

vii. Population Metrics 

4. Nitrogen and Sulfur Deposition 

a. Current Levels 

b. Projected Levels 

E. Health Effects of Criteria and Air Toxics 

Pollutants 

1. Particulate Matter 

a. Background 

b. Health Effects of PM 

2. Ozone 

a. Background 

b. Health Effects of Ozone 

3. NOX and SOX

a. Background 

b. Health Effects of NOX

c. Health Effects of SOX

4. Carbon Monoxide 

5. Air Toxics 

a. Acetaldehyde 

b. Acrolein 

c. Benzene 

d. 1,3-Butadiene 

e. Ethanol 

f. Formaldehyde 

g. Peroxyacetyl Nitrate (PAN) 

h. Naphthalene 

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. Environmental Effects of Air Toxics 

VII. 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 for Cellulosic Biofuels 

c. Imported Sugarcane Ethanol 

2. Biodiesel and Renewable Diesel 

Production Costs 

a. Biodiesel 

b. Renewable Diesel 

B. Biofuel Distribution Costs 

1. Ethanol Distribution Costs 

2. Cellulosic Distillate and Renewable 

Diesel Distribution Costs 

3. Biodiesel Distribution Costs 

C. Reduced U.S. Refining Demand 

D. Total Estimated Cost Impacts 

1. Refinery Modeling Methodology 

2. Overall Impact on Fuel Cost 

VIII. Economic Impacts and Benefits 

A. Agricultural and Forestry Impacts 

1. Biofuel Volumes Modeled 

2. Commodity Price Changes 

3. Impacts on U.S. Farm Income 

4. Commodity Use Changes 

5. U.S. Land Use Changes 

6. Impact on U.S. Food Prices 

7. 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 

3. Combining Energy Security and Other 

Benefits 

4. Total Energy Security Benefits 

C. Benefits of Reducing GHG Emissions 

1. Introduction 

2. Derivation of Interim Social Cost of 

Carbon Values 

3. Application of Interim SCC Estimates to 

GHG Emissions Reductions 

D. Criteria Pollutant Health and 

Environmental Impacts 

1. Overview 

2. Quantified Human Health Impacts 

3. Monetized Impacts 

4. What Are the Limitations of the Health 

Impacts Analysis? 

E. Summary of Costs and Benefits 

IX. Impacts on Water 

A. Background 

1. Agriculture and Water Quality 

2. Ecological Impacts 

3. Impacts to the Gulf of Mexico 

B. Upper Mississippi River Basin Analysis 

1. SWAT Model 

2. AEO 2007 Reference Case 

3. Reference Cases and RFS2 Control Case 

4. Case Study 

5. Sensitivity Analysis 

C. Additional Water Issues 

1. Chesapeake Bay Watershed 

2. Ethanol Production and Distribution 

a. Production 

b. Distillers Grain With Solubles 

c. Ethanol Leaks and Spills From Fueling 

Stations 

3. Biodiesel Plants 

4. Water Quantity 

5. Drinking Water 

X. Public Participation 

XI. 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. Reporting, Recordkeeping, and 

Compliance 

5. Related Federal Rules 

6. Steps Taken To Minimize the Significant 

Economic Impact on Small Entities 

a. Significant Panel Findings 

b. Outreach With Small Entities (and the 

Panel Process) 

c. Panel Recommendations, Proposed 

Provisions, and Provisions Being 

Finalized 

i. Delay in Standards 

ii. Phase-in 

iii. RIN-Related Flexibilities 

iv. Program Review 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14673 

1To 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. 

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 

7. Conclusions 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

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 

K. Congressional Review Act 

XII. Statutory Provisions and Legal Authority 

I. Executive Summary 

Through this final rule, the U.S. 

Environmental Protection Agency is 

revising the National Renewable Fuel 

Standard program to implement the 

requirements of the Energy 

Independence and Security Act of 2007 

(EISA). EISA made significant changes 

to both the structure and the magnitude 

of the renewable fuel program created 

by the Energy Policy Act of 2005 

(EPAct). The EISA fuel program, 

hereafter referred to as RFS2, mandates 

the use of 36 billion gallons of 

renewable fuel by 2022—a nearly fivefold increase over the highest volume 

specified by EPAct. EISA also 

established four separate categories of 

renewable fuels, each with a separate 

volume mandate and each with a 

specific lifecycle greenhouse gas 

emission threshold. 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 to 16 billion gallons by 

2022, representing the bulk of the 

increase in the renewable fuels 

mandate. 

EPA’s proposed rule sought comment 

on a multitude of issues, ranging from 

how to interpret the new definitions for 

renewable biomass to the Agency’s 

proposed methodology for conducting 

the greenhouse gas lifecycle assessments 

required by EISA. The decisions 

presented in this final rule are heavily 

informed by the many public comments 

we received on the proposed rule. In 

addition, and as with the proposal, we 

sought input from a wide variety of 

stakeholders. 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. We 

also have worked closely with other 

Federal agencies and in particular with 

the Departments of Energy and 

Agriculture. 

This section provides an executive 

summary of the final RFS2 program 

requirements that EPA is implementing 

as a result of EISA. The RFS2 program 

will replace the RFS1 program 

promulgated on May 1, 2007 (72 FR 

23900).1 Details of the final 

requirements can be found in Sections 

II and III, with certain lifecycle aspects 

detailed in Section V. 

This section also provides a summary 

of EPA’s assessment of the 

environmental and economic impacts of 

the use of higher renewable fuel 

volumes. Details of these analyses can 

be found in Sections IV through IX and 

in the Regulatory Impact Analysis (RIA). 

A. Summary of New Provisions of the 

RFS Program 

Today’s notice establishes new 

regulatory requirements for the RFS 

program that will be implemented 

through a new subpart M to 40 CFR part 

80. EPA is maintaining several elements 

of the RFS1 program such as regulations 

governing the generation, transfer, and 

use of Renewable Identification 

Numbers (RINs). At the same time, we 

are making a number of updates to 

reflect the changes brought about by 

EISA 

1. Required Volumes of Renewable Fuel 

The RFS program is intended to 

require a minimum volume of 

renewable fuel to be used each year in 

the transportation sector. In response to 

EPAct 2005, under RFS1 the required 

volume was 4.0 billion gallons in 2006, 

ramping up to 7.5 billion gallons by 

2012. Starting in 2013, the program also 

required that the total volume of 

renewable fuel contain at least 250 

million gallons of fuel derived from 

cellulosic biomass. 

In response to EISA, today’s action 

makes four 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, with 

certain exceptions applicable to existing 

facilities, that each of these mandated 

volumes of renewable fuels achieve 

certain minimum thresholds of GHG 

emission performance. Fourth, it 

requires that all renewable fuel be made 

from feedstocks that meet the new 

definition of renewable biomass 

including certain land use restrictions. 

The volume requirements in EISA are 

shown in Table I.A.1–1. 

BILLING CODE 6560–50–P 

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BILLING CODE 6560–50–C 


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2 73 FR 70643, November 21, 2008 

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 V.C for further 

discussion of which specific types of 

fuel may qualify for the four categories 

shown in Table I.A.1–1. 

2. Standards for 2010 and Effective Date 

for New Requirements 

While EISA established the renewable 

fuel volumes shown in Table I.A.1–1, it 

also requires that the Administrator set 

the standards based on these volumes 

each November for the following year 

based in part on information provided 

from the Energy Information Agency 

(EIA). In the case of the cellulosic 

biofuel standard, section 211(o)(7)(D) of 

EISA specifically requires that the 

standard be set based on the volume 

projected to be available during the 

following year. If the volume is lower 

than the level shown in Table I.A.1–1, 

then EISA allows the Administrator to 

also lower the advanced biofuel and 

total renewable fuel standards each year 

accordingly. Given the implications of 

these standards and the necessary 

judgment that can’t be reduced to a 

formula akin to the RFS1 regulations, 

we believe it is appropriate to set the 

standards through a notice-andcomment rulemaking process. Thus, for 

future standards, we intend to issue an 

NPRM by summer and a final rule by 

November 30 of each year in order to 

determine the appropriate standards 

applicable in the following year. 

However, in the case of the 2010 

standards, we are finalizing them as part 

of today’s action. 

a. 2010 Standards 

While we proposed that the cellulosic 

biofuel standard would be set at the 

EISA-specified level of 100 million 

gallons for 2010, based on analysis of 

information available at this time, we no 

longer believe the full volume can be 

met. Since the proposal, we have had 

detailed discussions with over 30 

companies that are in the business of 

developing cellulosic biofuels and 

cellulosic biofuel technology. Based on 

these discussions, we have found that 

many of the projects that served as the 

basis for the proposal have been put on 

hold, delayed, or scaled back. At the 

same time, there have been a number of 

additional projects that have developed 

and are moving forward. As discussed 

in Section IV.B.3, the timing for many 

of the projects indicates that while few 

will be able to provide commercial 

volumes for 2010, an increasing number 

will come on line in 2011, 2012, and 

2013. The success of these projects is 

then expected to accelerate growth of 

the cellulosic biofuel industry out into 

the future. EIA provided us with a 

projection on October 29, 2009 of 5.04 

million gallons (6.5 million ethanolequivalent gallons) of cellulosic biofuel 

production for 2010. While our 

company-by-company assessment varies 

from EIA’s, as described in Section 

IV.B.3., and actual cellulosic production 

volume during 2010 will be a function 

of developments over the course of 

2010, we nevertheless believe that 5 

million gallons (6.5 million ethanol 

equivalent) represents a reasonable, yet 

achievable level for the cellulosic 

standard for 2010. While this is lower 

than the level specified in EISA, no 

change to the advanced biofuel and total 

renewable fuel standards is warranted. 

With the inclusion of an energy-based 

Equivalence Value for biodiesel and 

renewable diesel, 2010 compliance with 

the biomass-based diesel standard will 

be more than enough to ensure 

compliance with the advanced biofuel 

standard for 2010. 

Today’s rule also includes special 

provisions to account for the 2009 

biomass-based diesel volume 

requirements in EISA. As described in 

the NPRM, in November 2008 we used 

the new total renewable fuel volume of 

11.1 billion gallons from EISA as the 

basis for the 2009 total renewable fuel 

standard that we issued under the RFS1 

regulations.2 While this approach 

ensured that the total mandated 

renewable fuel volume required by EISA 

for 2009 was used, the RFS1 regulatory 

structure did 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 we proposed, 

and as is described in more detail in 

Section II.E.2, we are addressing this 

issue in today’s rule by combining the 

2010 biomass-based diesel requirement 

of 0.65 billion gallons with the 2009 

biomass based diesel requirement of 0.5 

billion gallons to require that obligated 

parties meet a combined 2009/2010 

requirement of 1.15 billion gallons by 

the end of the 2010 compliance year. No 

similar provisions are required in order 

to fulfill the 2009 advanced biofuel 

volume mandate. 

The resulting 2010 standards are 

shown in Table I.A.2–1. These 

standards represent the fraction of a 

refiner’s or importer’s gasoline and 

diesel volume which must be renewable 

fuel. Additional discussion of the 2010 

standards can be found in Section 

II.E.1.b. 

TABLE I.A.2–1—STANDARDS FOR

2010 

Cellulosic biofuel ....................... 0.004% 

Biomass-based diesel .............. 1.10% 

Advanced biofuel ...................... 0.61% 

Renewable fuel ......................... 8.25% 

b. Effective Date 

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 

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

categories of renewable fuel. As 

described in the NPRM, we were not 

able to promulgate final RFS2 program 

requirements by December 19, 2008. 

Under today’s rule, the transition 

from using the RFS1 regulatory 

provisions regarding registration, RIN 

generation, reporting, and 

recordkeeping to using comparable 

provisions in this RFS2 rule will occur 

on July 1, 2010. This is the start of the 

1st quarter following completion of the 

statutorily required 60-day 

Congressional Review period for such a 

rulemaking as this. This will provide 

adequate lead time for all parties to 

transition to the new regulatory 

requirements, including additional time 

to prepare for RFS2 implementation for 

those entities who may find it helpful, 

especially those covered by the RFS 

program for the first time. In addition, 

making the transition at the end of the 

quarter will help simplify the 

recordkeeping and reporting transition 

to RFS2. To facilitate the volume 

obligations being based on the full 

year’s gasoline and diesel production, 

and to enable the smooth transition 

from the RFS1 to RFS2 regulatory 

provisions, Renewable Identification 

Numbers (RINs—which are used in the 

program for both credit trading and for 

compliance demonstration) that were 

generated under the RFS1 regulations 

will continue to be valid for compliance 

with the RFS2 obligations. Further 

discussion of transition issues can be 

found in Sections II.A and II.G.4, 

respectively. 

According to EISA, the renewable fuel 

obligations applicable under RFS2 

apply on a calendar basis. That is, 

obligated parties must determine their 

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renewable volume obligations (RVOs) at 

the end of a calendar year based on the 

volume of gasoline or diesel fuel they 

produce during the year, and they must 

demonstrate compliance with their 

RVOs in an annual report that is due 

two months after the end of the calendar 

year. 

For 2010, today’s rule will follow this 

same general approach. The four RFS2 

RVOs for each obligated party will be 

calculated on the basis of all gasoline 

and diesel produced or imported on and 

after January 1, 2010, through December 

31, 2010. Obligated parties will be 

required to demonstrate by February 28 

of 2011 that they obtained sufficient 

RINs to satisfy their 2010 RVOs. We 

believe this is an appropriate approach 

as it is more consistent with Congress’ 

provisions in EISA for 2010, and there 

is adequate lead time for the obligated 

parties to achieve compliance. 

The issue for EPA to resolve is how 

to apply the four volume mandates 

under EISA for calendar year 2010. 

These volume mandates are translated 

into applicable percentages that 

obligated parties then use to determine 

their renewable fuel volume obligations 

based on the gasoline and diesel they 

produce or import in 2010. There are 

three basic approaches that EPA has 

considered, based on comments on the 

proposal. The first is the approach 

adopted in this rule—the four RFS2 

applicable percentages are determined 

based on the four volume mandates 

covered by this rule, and the renewable 

volume obligation for a refiner or 

importer will be determined by 

applying these percentages to the 

volume of gasoline and diesel fuel they 

produce during calendar year 2010. 

Under this approach, there is no 

separate applicable percentage under 

RFS1 for 2010, however RINs generated 

in 2009 and 2010 under RFS1 can be 

used to meet the four volume 

obligations for 2010 under the RFS2 

regulations. Another option, which was 

considered and rejected by EPA, is 

much more complicated—(1) determine 

an RFS1 applicable percentage based on 

just the total renewable fuel volume 

mandate, using the same total volume 

for renewable fuel as used in the first 

approach, and require obligated parties 

to apply that percentage to the gasoline 

produced from January 1, 2010 until the 

effective date of the RFS2 regulations, 

and (2) determine the four RFS2 

applicable percentages as discussed 

above, but require obligated parties to 

apply them to only the gasoline and 

diesel in 2010 after the effective date of 

the RFS2 regulations. Of greater concern 

than its complexity, the second 

approach fails to ensure that the total 

volumes for three of the volume 

mandates are met for 2010. In effect EPA 

would be requiring that obligated 

parties use enough cellulosic biofuel, 

biomass-based diesel, and advanced 

biofuel to meet approximately 75% of 

the total volumes required for these 

fuels under EISA. While the total 

volume mandate under EISA for 

renewable fuel would likely be met, the 

other three volumes mandates would 

only be met in part. The final option 

would involve delaying the RFS2 

requirements until January 1, 2011, 

which would avoid the complexity of 

the second approach, but would be even 

less consistent with EISA’s 

requirements. 

The approach adopted in this rule is 

clearly the most consistent with EISA’s 

requirement of four different volume 

mandates for all of calendar year 2010. 

In addition, EPA is confident that 

obligated parties have adequate leadtime to comply with the four volume 

requirements under the approach 

adopted in this rule. The volume 

requirements are achieved by obtaining 

the appropriate number of RINs from 

producers of the renewable fuel. The 

obligated parties do not need lead time 

for construction or investment purposes, 

as they are not changing the way they 

produce gasoline or diesel, do not need 

to design to install new equipment, or 

take other actions that require longer 

lead time. Obtaining the appropriate 

amount of RINs involves contractual or 

other arrangements with renewable fuel 

producers or other holders of RINs. 

Obligated parties now have experience 

implementing RFS1, and the actions 

needed to comply under the RFS2 

regulations are a continuation of these 

kinds of RFS1 activities. In addition, an 

adequate supply of RINs is expected to 

be available for compliance by obligated 

parties. RFS1 RINs have been produced 

throughout 2009 and continue to be 

produced since the beginning of 2010. 

There has been and will be no gap or lag 

in the production of RINS, as the RFS1 

regulations continue in effect and 

require that renewable fuel producers 

generate RINs for the renewable fuel 

they produce. These 2009 and 2010 

RFS1 RINs will be available and can be 

used towards the volume requirements 

of obligated parties for 2010. These 

RFS1 RINS combined with the RFS2 

RINs that will be generated by 

renewable fuel producers are expected 

to provide an adequate supply of RINs 

to ensure compliance for all of the 

renewable volume mandates. For further 

discussion of the expected supply of 

renewable fuel, see section IV. 

In addition, obligated parties have 

received adequate notice of this 

obligation. The proposed rule called for 

obligated parties to meet the full volume 

mandates for all four volume mandates, 

and to base their volume obligation on 

the volume of gasoline and diesel 

produced starting January 1, 2010. 

While the RFS2 regulations are not 

effective until after January 1, 2010, the 

same full year approach is being taken 

for the 2010 volumes of gasoline and 

diesel. Obligated parties have been on 

notice based on EPA’s proposal, 

discussions with many stakeholders 

during the rulemaking, the issuance of 

the final rule itself, and publication of 

this rule in the Federal Register. As 

discussed above, there is adequate time 

for obligated parties to meet their 2010 

volume obligations by the spring of 

2011. 

This approach does not impose any 

retroactive requirements. The obligation 

that is imposed under the RFS2 

regulations is forward looking—by the 

spring of 2011, when compliance is 

determined, obligated parties must 

satisfy certain volume obligations. 

These future requirements are 

calculated in part based on volumes of 

gasoline and diesel produced prior to 

the effective date of the RFS2 

regulations, but this does not make the 

RFS2 requirement retroactive in nature. 

The RFS2 regulations do not change in 

any way the legal obligations or 

requirements that apply prior to the 

effective date of the RFS2 regulations. 

Instead, the RFS2 requirements impose 

new requirements that must be met in 

the future. There is adequate lead time 

to comply with these RFS2 

requirements, and they achieve a result 

that is more consistent with Congress’ 

goals in establishing 4 volume mandates 

for calendar year 2010, and for these 

reasons EPA is adopting this approach 

for calendar year 2010. 

Parties that intend to generate RINs, 

own and/or transfer them, or use them 

for compliance purposes after July 1, 

2010 will need to register or re-register 

under the RFS2 provisions and modify 

their information technology (IT) 

systems to accommodate the changes we 

are finalizing today. As described more 

fully in Section II, these changes 

include redefining the D code within 

the RIN that identifies which standard 

a fuel qualifies for, adding a process for 

verifying that feedstocks meet the 

renewable biomass definition, and 

calculating compliance with four 

standards instead of one. EPA’s 

registration system is available now for 

parties to complete the registration 

process. Further details on this process 

can be found elsewhere in today’s 

preamble as well as at http:// 

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

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fuelsregistration.htm. Parties that 

produce motor vehicle, nonroad, 

locomotive, and marine (MVNRLM) 

diesel fuel but not gasoline will be 

newly obligated parties and may be 

establishing IT systems for the RFS 

program for the first time. 

3. Analysis of Lifecycle Greenhouse Gas 

Emissions and Thresholds for 

Renewable Fuels 

a. Background and Conclusions 

A significant aspect of the RFS2 

program is the requirement that the 

lifecycle GHG emissions of a qualifying 

renewable fuel must be less than the 

lifecycle GHG emissions of the 2005 

baseline average gasoline or diesel fuel 

that it replaces; four different levels of 

reductions are required for the four 

different renewable fuel standards. 

These lifecycle performance 

improvement thresholds are listed in 

Table I.A.3–1. Compliance with each 

threshold requires a comprehensive 

evaluation of renewable fuels, as well as 

the baseline for gasoline and diesel, on 

the basis of their lifecycle emissions. As 

mandated by EISA, the greenhouse gas 

emissions assessments must evaluate 

the aggregate quantity of greenhouse gas 

emissions (including direct emissions 

and significant indirect emissions such 

as significant emissions form land use 

changes) related to the full lifecycle, 

including all stages of fuel and 

feedstock production, distribution and 

use by the ultimate consumer. 

TABLE I.A.3–1—LIFECYCLE GHG 

THRESHOLDS SPECIFIED IN EISA 

[Percent Reduction from Baseline] 

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

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

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

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

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

2007. 

It is important to recognize that fuel 

from the existing capacity of current 

facilities and the capacity of all new 

facilities that commenced construction 

prior to December 19, 2007 (and in some 

cases prior to December 31, 2009) are 

exempt, or grandfathered, from the 20% 

lifecycle requirement for the Renewable 

Fuel category. Therefore, EPA has in the 

discussion below emphasized its 

analysis on those plants and fuels that 

are likely to be used for compliance 

with the rule and would be subject to 

the lifecycle thresholds. Based on the 

analyses and approach described in 

Section V of this preamble, EPA is 

determining that ethanol produced from 

corn starch at a new facility (or 

expanded capacity from an existing) 

using natural gas, biomass or biogas for 

process energy and using advanced 

efficient technologies that we expect 

will be most typical of new production 

facilities will meet the 20% GHG 

emission reduction threshold compared 

to the 2005 baseline gasoline. We are 

also determining that biobutanol from 

corn starch meets the 20% threshold. 

Similarly, EPA is making the 

determination that biodiesel and 

renewable diesel from soy oil or waste 

oils, fats and greases will exceed the 

50% GHG threshold for biomass-based 

diesel compared to the 2005 petroleum 

diesel baseline. In addition, we have 

now modeled biodiesel and renewable 

diesel produced from algal oils as 

complying with the 50% threshold for 

biomass-based diesel. EPA is also 

determining that ethanol from sugarcane 

complies with the applicable 50% GHG 

reduction threshold for advanced 

biofuels. The modeled pathways 

(feedstock and production technology) 

for cellulosic ethanol and cellulosic 

diesel would also comply with the 60% 

GHG reduction threshold applicable to 

cellulosic biofuels. As discussed later in 

section V, there are also other fuels and 

fuel pathways that we are determining 

will comply with the GHG thresholds. 

Under EISA, EPA is allowed to adjust 

the GHG reduction thresholds 

downward by up to 10% if necessary 

based on lifecycle GHG assessment of 

biofuels likely to be available. Based on 

the results summarized above, we are 

not finalizing any adjustments to the 

lifecycle GHG thresholds for the four 

renewable fuel standard categories. 

EPA recognizes that as the state of 

scientific knowledge continues to 

evolve in this area, the lifecycle GHG 

assessments for a variety of fuel 

pathways are likely to be updated. 

Therefore, while EPA is using its 

current lifecycle assessments to inform 

the regulatory determinations for fuel 

pathways in this final rule, as required 

by the statute, the Agency is also 

committing to further reassess these 

determinations and lifecycle estimates. 

As part of this ongoing effort, we will 

ask for the expert advice of the National 

Academy of Sciences, as well as other 

experts, and incorporate their advice 

and any updated information we receive 

into a new assessment of the lifecycle 

GHG emissions performance of the 

biofuels being evaluated in this final 

rule. EPA will request that the National 

Academy of Sciences evaluate the 

approach taken in this rule, the 

underlying science of lifecycle 

assessment, and in particular indirect 

land use change, and make 

recommendations for subsequent 

lifecycle GHG assessments on this 

subject. At this time we are estimating 

this review by the National Academy of 

Sciences may take up to two years. As 

specified by EISA, if EPA revises the 

analytical methodology for determining 

lifecycle greenhouse gas emissions, any 

such revision will apply to renewable 

fuel from new facilities that commence 

construction after the effective date of 

the revision. 

b. Fuel Pathways Considered and Key 

Model Updates Since the Proposal 

EPA is making the GHG threshold 

determination based on a methodology 

that includes an analysis of the full 

lifecycle, including significant 

emissions related to international landuse change. As described in more detail 

below and in Section V of this 

preamble, EPA has used the best 

available models for this purpose, and 

has incorporated many modifications to 

its proposed approach based on 

comments from the public and peer 

reviewers and developing science. EPA 

has also quantified the uncertainty 

associated with significant components 

of its analyses, including important 

factors affecting GHG emissions 

associated with international land use 

change. As discussed below, EPA has 

updated and refined its modeling 

approach since proposal in several 

important ways, and EPA is confident 

that its modeling of GHG emissions 

associated with international land use is 

comprehensive and provides a 

reasonable and scientifically robust 

basis for making the threshold 

determinations described above. As 

discussed below, EPA plans to continue 

to improve upon its analyses, and will 

update it in the future as appropriate. 

Through technical outreach, the peer 

review process, and the public comment 

period, EPA received and reviewed a 

significant amount of data, studies, and 

information on our proposed lifecycle 

analysis approach. We incorporated a 

number of new, updated, and peerreviewed data sources in our final 

rulemaking analysis including better 

satellite data for tracking land use 

changes and improved assessments of 

N2O impacts from agriculture. The new 

and updated data sources are discussed 

further in this section, and in more 

detail in Section V. 

We also performed dozens of new 

modeling runs, uncertainty analyses, 

and sensitivity analyses which are 

leading to greater confidence in our 

results. We have updated our analyses 

in conjunction with, and based on, 

advice from experts from government, 

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academia, industry, and not for profit 

institutions. 

The new studies, data, and analysis 

performed for the final rulemaking 

impacted the lifecycle GHG results for 

biofuels in a number of different ways. 

In some cases, updates caused the 

modeled analysis of lifecycle GHG 

emissions from biofuels to increase, 

while other updates caused the modeled 

emissions to be reduced. Overall, the 

revisions since our proposed rule have 

led to a reduction in modeled lifecycle 

GHG emissions as compared to the 

values in the proposal. The following 

highlights the most significant revisions. 

Section V details all of the changes 

made and their relative impacts on the 

results. 

Corn Ethanol: The final rule analysis 

found less overall indirect land use 

change (less land needed), thereby 

improving the lifecycle GHG 

performance of corn ethanol. The main 

reasons for this decrease are: 

• Based on new studies that show the 

rate of improvement in crop yields as a 

function of price, crop yields are now 

modeled to increase in response to 

higher crop prices. When higher crop 

yields are used in the models, less land 

is needed domestically and globally for 

crops as biofuels expand. 

• New research available since the 

proposal indicates that the corn ethanol 

production co-product, distillers grains 

and solubles (DGS), is more efficient as 

an animal feed (meaning less corn is 

needed for animal feed) than we had 

assumed in the proposal. Therefore, in 

our analyses for the final rule, domestic 

corn exports are not impacted as much 

by increased biofuel production as they 

were in the proposal analysis. 

• Improved satellite data allowed us 

to more finely assess the types of land 

converted when international land use 

changes occur, and this more precise 

assessment led to a lowering of modeled 

GHG impacts. Based on previous 

satellite data, the proposal assumed 

cropland expansion onto grassland 

would require an amount of pasture to 

be replaced through deforestation. For 

the final rulemaking analysis we 

incorporated improved economic 

modeling of demand for pasture area 

and satellite data which indicates that 

pasture is also likely to expand onto 

existing grasslands. This reduced the 

GHG emissions associated with an 

amount of land use change. 

However, we note that not all 

modeling updates necessarily reduced 

predicted GHG emissions from land use 

change. As one example, since the 

proposal a new version of the GREET 

model (Version 1.8C) has been released. 

EPA reviewed the new version and 

concluded that this was an 

improvement over the previous GREET 

release that was used in the proposal 

analysis (Version 1.8B). Therefore, EPA 

updated the GHG emission factors for 

fertilizer production used in our 

analysis to the values from the new 

GREET version. This had the result of 

slightly increasing the GHG emissions 

associated with fertilizer production 

and thus slightly increasing the GHG 

emission impacts of domestic 

agriculture. 

For the final rule, EPA has analyzed 

a variety of corn ethanol pathways 

including ethanol made from corn 

starch using natural gas, coal, and 

biomass as process energy sources in 

production facilities utilizing both dry 

mill and wet mill processes. For corn 

starch ethanol, we also considered the 

technology enhancements likely to 

occur in the future such as the addition 

of corn oil fractionation or extraction 

technology, membrane separation 

technology, combined heat and power 

and raw starch hydrolysis. 

Biobutanol from corn starch: In 

addition to ethanol from corn starch, for 

this final rule, we have also analyzed 

bio-butanol from corn starch. Since the 

feedstock impacts are the same as for 

ethanol from corn starch, the assessment 

for biobutanol reflects the differing 

impacts due to the production process 

and energy content of biobutanol 

compared to that of ethanol. 

Soybean Biodiesel: The new 

information described above for corn 

ethanol also leads to lower modeled 

GHG impacts associated with soybean 

biodiesel. The revised assessment 

predicts less overall indirect land use 

change (less land needed) and less 

impact from the land use changed that 

does occur (due to updates in types of 

converted land assumed). In addition, 

the latest IPCC guidance indicates 

reduced domestic soybean N2O 

emissions, and updated USDA and 

industry data show reductions in 

biodiesel processing energy use and a 

higher co-product credit, all of which 

further reduced the modeled soybean 

biodiesel lifecycle GHG emissions. This 

has resulted in a significant 

improvement in our assessment of the 

lifecycle performance of soybean 

biodiesel as compared to the estimate in 

the proposal. 

Biodiesel and Renewable Diesel from 

Algal Oil and Waste Fats and Greases: 

In addition to biodiesel from soy oil, 

biodiesel and renewable diesel from 

algal oil (should it reach commercial 

production) and biodiesel from waste 

oils, fats and greases have been 

modeled. These feedstock sources have 

little or no land use impact so the GHG 

impacts associate with their use in 

biofuel production are largely the result 

of energy required to produce the 

feedstock (in the case of algal oil) and 

the energy required to turn that 

feedstock into a biofuel. 

Sugarcane Ethanol: Sugarcane 

ethanol was analyzed considering a 

range of technologies and assuming 

alternative pathways for dehydrating the 

ethanol prior to its use as a biofuel in 

the U.S. For the final rule, our analysis 

also shows less overall indirect land use 

change (less land needed) associated 

with sugarcane ethanol production. For 

the proposal, we assumed sugarcane 

expansion in Brazil would result in 

cropland expansion into grassland and 

lost pasture being replaced through 

deforestation. Based on newly available 

regional specific data from Brazil, 

historic trends, and higher resolution 

satellite data, in the final rule, sugarcane 

expansion onto grassland is coupled 

with greater pasture intensification, 

such that there is less projected impact 

on forests. Furthermore, new data 

provided by commenters showed 

reduced sugarcane ethanol process 

energy, which also reduced the 

estimated lifecycle GHG impact of 

sugarcane ethanol production. 

Cellulosic Ethanol: We analyzed 

cellulosic ethanol production using both 

biochemical (enzymatic) and thermochemical processes with corn stover, 

switchgrass, and forestry thinnings and 

waste as feedstocks. For cellulosic 

diesel, we analyzed production using 

the Fischer-Tropsch process. For the 

final rule, we updated the cellulosic 

ethanol conversion rates based on new 

data provided by the National 

Renewable Energy Laboratory (NREL.) 

As a result of this update, the gallons 

per ton yields for switchgrass and 

several other feedstock sources 

increased in our analysis for the final 

rule, while the predicted yields from 

corn residue and several other feedstock 

sources decreased slightly from the 

NPRM values. In addition, we also 

updated our feedstock production yields 

based on new work conducted by the 

Pacific Northwest National Laboratory 

(PNNL). This analysis increased the tons 

per acre yields for several dedicated 

energy crops. These updates increased 

the amount of cellulosic ethanol 

projected to come from energy crops. 

While the increase in crop yields and 

conversion efficiency reduced the GHG 

emissions associated with cellulosic 

ethanol, there remains an increased 

demand for land to grow dedicated 

energy crops; this land use impact 

resulted in increased GHG emissions 

with the net result varying by the type 

of cellulosic feedstock source. 

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We note that several of the renewable 

fuel pathways modeled are still in early 

stages of development or 

commercialization and are likely to 

continue to develop as the industry 

moves toward commercial production. 

Therefore, it will be necessary to 

reanalyze several pathways using 

updated data and information as the 

technologies develop. For example, 

biofuel derived from algae is undergoing 

wide ranging development. Therefore 

for now, our algae analyses presume 

particular processes and energy 

requirements which will need to be 

reviewed and updated as this fuel 

source moves toward commercial 

production. 

For this final rule we have 

incorporated a statistical analysis of 

uncertainty about critical variables in 

our pathway analysis. This uncertainty 

analysis is explained in detail in Section 

V and is consistent with the specific 

recommendations received through our 

peer review and public comments on 

the proposal. The uncertainty analysis 

focused on two aspects of indirect land 

use change—the types of land converted 

and the GHG emission associated with 

different types of land converted. In 

particular, our uncertainty analysis 

focused on such specific sources of 

information as the satellite imaging used 

to inform our assessment of land use 

trends and the specific changes in 

carbon storage expected from a change 

in land use in each geographic area of 

the world modeled. We have also 

performed additional sensitivity 

analyses including analysis of two yield 

scenarios for corn and soy beans to 

assess the impact of changes in yield 

assumptions. 

This uncertainty analysis provides 

information on both the range of 

possible outcomes for the parameters 

analyzed, an estimate of the degree of 

confidence that the actual result will be 

within a particular range (in our case, 

we estimated a 95% confidence 

interval) and an estimate of the central 

tendency or midpoint of the GHG 

performance estimate. 

In the proposal, we considered several 

options for the timeframe over which to 

measure lifecycle GHG impacts and the 

possibility of discounting those impacts. 

Based on peer review recommendations 

and other comments received, EPA is 

finalizing its assessments based on an 

analysis assuming 30 years of continued 

emission impacts after the program is 

fully phased in by 2022 and without 

discounting those impacts. 

EPA also notes that it received 

significant comment on our proposed 

baseline lifecycle greenhouse gas 

assessment of gasoline and diesel 

(‘‘petroleum baseline’’). While EPA has 

made several updates to the petroleum 

analysis in response to comments (see 

Section V for further discussion), we are 

finalizing the approach based on our 

interpretation of the definition in the 

Act as requiring that the petroleum 

baseline represent an average of the 

gasoline and diesel fuel (whichever is 

being replaced by the renewable fuel) 

sold as transportation fuel in 2005. 

As discussed in more detail later, the 

modeling results developed for 

purposes of the final rule provide a rich 

and comprehensive base of information 

for making the threshold 

determinations. There are numerous 

modeling runs, reflecting updated 

inputs to the model, sensitivity 

analyses, and uncertainty analyses. The 

results for different scenarios include a 

range and a best estimate or mid-point. 

Given the potentially conservative 

nature of the base crop yield 

assumption, EPA believes the actual 

crop yield in 2022 may be above the 

base yield; however we are not in a 

position to characterize how much 

above it might be. To the extent actual 

yields are higher, the base yield 

modeling results would underestimate 

to some degree the actual GHG 

emissions reductions compared to the 

baseline. 

In making the threshold 

determinations for this rule, EPA 

weighed all of the evidence available to 

it, while placing the greatest weight on 

the best estimate value for the base yield 

scenario. In those cases where the best 

estimate for the base yield scenario 

exceeds the reduction threshold, EPA 

judges that there is a good basis to be 

confident that the threshold will be 

achieved and is determining that the 

bio-fuel pathway complies with the 

applicable threshold. To the extent the 

midpoint of the scenarios analyzed lies 

further above a threshold for a particular 

biofuel pathway, we have increasingly 

greater confidence that the biofuel 

exceeds the threshold. 

EPA recognizes that certain 

commenters suggest that there is a very 

high degree of uncertainty associated in 

particular with determining 

international indirect land use changes 

and their emissions impacts, and 

because of this EPA should exclude any 

calculation of international indirect 

land use changes in its lifecycle 

analysis. Commenters say EPA should 

make the threshold determinations 

based solely on modeling of other 

sources of lifecycle emissions. In effect, 

commenters argue that the uncertainty 

of the modeling associated with 

international indirect land use change 

means we should use our modeling 

results but exclude that part of the 

results associated with international 

land use change. 

For the reasons discussed above and 

in more detail in Section V, EPA rejects 

the view that the modeling relied upon 

in the final rule, which includes 

emissions associated with international 

indirect land use change, is too 

uncertain to provide a credible and 

reasonable scientific basis for 

determining whether the aggregate 

lifecycle emissions exceed the 

thresholds. In addition, as discussed 

elsewhere, the definition of lifecycle 

emissions includes significant indirect 

emissions associated with land use 

change. In deciding whether a bio-fuel 

pathway meets the threshold, EPA has 

to consider what it knows about all 

aspects of the lifecycle emissions, and 

decide whether there is a valid basis to 

find that the aggregate lifecycle 

emissions of the fuel, taking into 

account significant indirect emissions 

from land use change meets the 

threshold. Based on the analyses 

conducted for this rule, EPA has 

determined international indirect land 

use impacts are significant and therefore 

must be included in threshold 

compliance assessment. 

If the international land use impacts 

were so uncertain that their impact on 

lifecycle GHG emissions could not be 

adequately determined, as claimed by 

commenters, this does not mean EPA 

could assume the international land use 

change emissions are zero, as 

commenters suggest. High uncertainty 

would not mean that emissions are 

small and can be ignored; rather it could 

mean that we could not tell whether 

they are large or small. If high 

uncertainty meant that EPA were not 

able to determine that indirect 

emissions from international land use 

change are small enough that the total 

lifecycle emissions meet the threshold, 

then that fuel could not be determined 

to meet the GHG thresholds of EISA and 

the fuel would necessarily have to be 

excluded from the program. 

In any case, that is not the situation 

here as EPA rejects commenters’ 

suggestion and does not agree that the 

uncertainty over the indirect emissions 

from land use change is too high to 

make a reasoned threshold 

determination. Therefore biofuels with a 

significant international land use impact 

are included within this program. 

c. Consideration of Fuel Pathways Not 

Yet Modeled 

Not all biofuel pathways have been 

directly modeled for this rule. For 

example, while we have modeled 

cellulosic biofuel produced from corn 

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stover, we have not modeled the 

specific GHG impact of cellulosic 

biofuel produced from other crop 

residues such as wheat straw or rice 

straw. Today, in addition to finalizing a 

threshold compliance determination for 

those pathways we specifically 

modeled, in some cases, our technical 

judgment indicates other pathways are 

likely to be similar enough to modeled 

pathways that we are also assured these 

similar pathways qualify. These 

pathways include fuels produced from 

the same feedstock and using the same 

production process but produced in 

countries other than those modeled. The 

agricultural sector modeling used for 

our lifecycle analysis does not predict 

any soybean biodiesel or corn ethanol 

will be imported into the U.S., or any 

imported sugarcane ethanol from 

production in countries other than 

Brazil. However, these rules do not 

prohibit the use in the U.S. of these 

fuels produced in countries not 

modeled if they are also expected to 

comply with the eligibility requirements 

including meeting the thresholds for 

GHG performance. Although the GHG 

emissions of producing these fuels from 

feedstock grown or biofuel produced in 

other countries has not been specifically 

modeled, we do not anticipate their use 

would impact our conclusions regarding 

these feedstock pathways. The 

emissions of producing these fuels in 

other countries could be slightly higher 

or lower than what was modeled 

depending on a number of factors. Our 

analyses indicate that crop yields for the 

crops in other countries where these 

fuels are also most likely to be produced 

are similar or lower than U.S. values 

indicating the same or slightly higher 

GHG impacts. Agricultural sector inputs 

for the crops in these other countries are 

roughly the same or lower than the U.S. 

pointing toward the same or slightly 

lower GHG impacts. If crop production 

were to expand due to biofuels in the 

countries where the models predict 

these biofuels might additionally be 

produced would tend to lower our 

assessment of international indirect 

impacts but could increase our 

assessment of the domestic (i.e., the 

country of origin) land use impacts. EPA 

believes, because of these offsetting 

factors along with the small amounts of 

fuel potentially coming from other 

countries, that incorporating fuels 

produced in other countries will not 

impact our threshold analysis. 

Therefore, fuels of the same fuel type, 

produced from the same feedstock using 

the same fuel production technology as 

modeled fuel pathways will be assessed 

the same GHG performance decisions 

regardless of country of origin. These 

pathways also include fuels that might 

be produced from similar feedstock 

sources to those already modeled and 

which are expected to have less or no 

indirect land use change. In such cases, 

we believe that in order to compete 

economically in the renewable fuel 

marketplace such pathways are likely to 

be at least as energy efficient as those 

modeled and thus have comparable 

lifecycle GHG performance. Based on 

these considerations, we are extending 

the lifecycle results for the fuel 

pathways already modeled to 5 broader 

categories of feedstocks. This extension 

of lifecycle modeling results is 

discussed further in Section V.C. 

We have established five categories of 

biofuel feedstock sources under which 

modeled feedstock sources and 

feedstock sources similar to those 

modeled are grouped and qualify on the 

basis of our existing modeling. These 

are: 

1. Crop residues such as corn stover, 

wheat straw, rice straw, citrus residue. 

2. Forest material including eligible 

forest thinnings and solid residue 

remaining from forest product 

production. 

3. Annual cover crops planted on 

existing crop land such as winter cover 

crops. 

4. Separated food and yard waste 

including biogenic waste from food 

processing. 

5. Perennial grasses including 

switchgrass and miscanthus. 

The full set of pathways for which we 

have been able to make a compliance 

decision are described in Section V. 

Threshold determinations for certain 

other pathways were not possible at this 

time because sufficient modeling or data 

is not yet available. In some of these 

cases, we recognize that a renewable 

fuel is already being produced from an 

alternative feedstock. Although we have 

the data needed for analysis, we did not 

have sufficient time to complete the 

necessary lifecycle GHG impact 

assessment for this final rule. We will 

model and evaluate additional pathways 

after this final rule on the basis of 

current or likely commercial production 

in the near-term and the status of 

current analysis at EPA. EPA anticipates 

modeling grain sorghum ethanol, woody 

pulp ethanol, and palm oil biodiesel 

after this final rule and including the 

determinations in a rulemaking within 6 

months. Our analyses project that they 

will be used in meeting the RFS2 

volume standard in the near-term. 

During the course of the NPRM 

comment period, EPA received detailed 

information on these pathways and is 

currently in the process of analyzing 

these pathways. We have received 

comments on several additional 

feedstock/fuel pathways, including 

rapeseed/canola, camelina, sweet 

sorghum, wheat, and mustard seed, and 

we welcome parties to utilize the 

petition process described in Section 

V.C to request EPA to examine 

additional pathways. 

We anticipate there could be 

additional cases where we currently do 

not have information on which to base 

a lifecycle GHG assessment perhaps 

because we are not yet aware of 

potential unique plant configurations or 

operations that could result in greater 

efficiencies than assumed in our 

analysis. In many cases, such alternative 

pathways could have been explicitly 

modeled as a reasonably straightforward 

extension of pathways we have modeled 

if the necessary information had been 

available. For example, while we have 

modeled specific enhancements to corn 

starch ethanol production such as 

membrane separation or corn oil 

extraction, there are likely other 

additional energy saving or co-product 

pathways available or under 

development by the industry. It is 

reasonable to also consider these 

alternative energy saving or co-product 

pathways based upon their technical 

merits. Other current or emerging 

pathways may require new analysis and 

modeling for EPA to fully evaluate 

compliance. For example, fuel pathways 

with feedstocks or fuel types not yet 

modeled by EPA may require additional 

modeling and, it follows, public 

comment before a determination of 

compliance can be made. 

Therefore, for those fuel pathways 

that are different than those pathways 

EPA has listed in today’s regulations, 

EPA is establishing a petition process 

whereby a party can petition the Agency 

to consider new pathways for GHG 

reduction threshold compliance. As 

described in Section V.C, the petition 

process is meant for parties with serious 

intention to move forward with 

production via the petitioned fuel 

pathway and who have moved 

sufficiently forward in the business 

process to show feasibility of the fuel 

pathway’s implementation. In addition, 

if the petition addresses a fuel pathway 

that already has been determined to 

qualify as one or more types of 

renewable fuel under RFS (e.g., 

renewable fuel, or advanced biofuel), 

the pathway must have the potential to 

result in qualifying for a renewable fuel 

type for which it was not previously 

qualified. Thus, for example, the 

Agency will not undertake any 

additional review for a party wishing to 

get a modified LCA value for a 

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previously approved fuel pathway if the 

desired new value would not change the 

overall pathway classification. 

The petition must contain all the 

necessary information on the fuel 

pathway to allow EPA to effectively 

assess the lifecycle performance of the 

new fuel pathway. See Section V.C for 

a full description. EPA will use the data 

supplied via the petition and other 

pertinent data available to the Agency to 

evaluate whether the information for 

that fuel pathway, combined with 

information developed in this 

rulemaking for other fuel pathways that 

have been determined to exceed the 

threshold, is sufficient to allow EPA to 

evaluate the pathway for a 

determination of compliance. We expect 

such a determination would be pathway 

specific. For some fuel pathways with 

unique modifications or enhancements 

to production technologies in pathways 

otherwise modeled for the regulations 

listed today, EPA may be able to 

evaluate the pathway as a reasonably 

straight-forward extension of our 

current assessments. In such cases, we 

would expect to make a decision for that 

specific pathway without conducting a 

full rulemaking process. We would 

expect to evaluate whether the pathway 

is consistent with the definitions of 

renewable fuel types in the regulations, 

generally without going through 

rulemaking, and issue an approval or 

disapproval that applies to the 

petitioner. We anticipate that we will 

subsequently propose to add the 

pathway to the regulations. Other 

current or emerging fuel pathways may 

require significant new analysis and/or 

modeling for EPA to conduct an 

adequate evaluation for a compliance 

determination (e.g., feedstocks or fuel 

types not yet included in EPA’s 

assessments for this regulation). For 

these pathways, EPA would give notice 

and seek public comment on a 

compliance determination under the 

annual rulemaking process established 

in today’s regulations. If we make a 

technical determination of compliance, 

then we anticipate the fuel producer 

will be able to generate RINs for fuel 

produced under the additional pathway 

following the next available quarterly 

update of the EPA Moderated 

Transaction System (EMTS). EPA will 

process those petitions as expeditiously 

as possible for those pathways which 

are closer to the commercial production 

stage than others. In all events, parties 

are expected to begin this process with 

ample lead time as compared to their 

commercial start dates. Further 

discussion of this petition process can 

be found in Section V.C. 

We note again that the continued 

work of EPA and others is expected to 

result in improved models and data 

sources, and that re-analysis based on 

such updated information could revise 

these determinations. Any such 

reassessment that would impact 

compliance would necessarily go 

through rulemaking and would only be 

applicable to production from future 

facilities after the revised rule was 

finalized, as required by EISA. 

4. Compliance With Renewable Biomass 

Provision 

EISA changed the definition of 

‘‘renewable fuel’’ to require that it be 

made from feedstocks that qualify as 

‘‘renewable biomass.’’ EISA’s definition 

of the term ‘‘renewable biomass’’ limits 

the types of biomass as well as the types 

of land from which the biomass may be 

harvested. The definition includes: 

• Planted crops and crop residue 

from agricultural land cleared prior to 

December 19, 2007 and actively 

managed or fallow on that date. 

• Planted trees and tree residue from 

tree plantations cleared prior to 

December 19, 2007 and actively 

managed on that date. 

• Animal waste material and 

byproducts. 

• Slash and pre-commercial thinnings 

from non-federal forestlands that are 

neither old-growth nor listed as 

critically imperiled or rare by a State 

Natural Heritage program. 

• Biomass cleared from the vicinity of 

buildings and other areas at risk of 

wildfire. 

• Algae. 

• Separated yard waste and food 

waste. 

In today’s rule, EPA is finalizing 

definitions for the many terms included 

within the definition of renewable 

biomass. Where possible, EPA has 

adhered to existing statutory, regulatory 

or industry definitions for these terms, 

although in some cases we have altered 

definitions to conform to EISA’s 

statutory language, to further the goals 

of EISA, or for ease of program 

implementation. For example, EPA is 

defining ‘‘agricultural land’’ from which 

crops and crop residue can be harvested 

for RIN-generating renewable fuel 

production as including cropland, 

pastureland, and land enrolled in the 

Conservation Reserve Program. An indepth discussion of the renewable 

biomass definitions can be found in 

Section II.B.4. 

In keeping with EISA, under today’s 

final rule, renewable fuel producers may 

only generate RINs for fuels made from 

feedstocks meeting the definition of 

renewable biomass. In order to 

implement this requirement, we are 

finalizing three potential mechanisms 

for domestic and foreign renewable fuel 

producers to verify that their feedstocks 

comply with this requirement. The first 

involves renewable biomass 

recordkeeping and reporting 

requirements by renewable fuel 

producers for their individual facilities. 

As an alternative to these individual 

recordkeeping and reporting 

requirements, the second allows 

renewable fuel producers to form a 

consortium to fund an independent 

third-party to conduct an annual 

renewable biomass quality-assurance 

survey, based on a plan approved by 

EPA. The third is an aggregate 

compliance approach applicable only to 

crops and crop residue from the U.S. It 

utilizes USDA’s publicly available 

agricultural land data as the basis for an 

EPA determination of compliance with 

the renewable biomass requirements for 

these particular feedstocks. This 

determination will be reviewed 

annually, and if EPA finds it is no 

longer warranted, then renewable fuel 

producers using domestically grown 

crops and crop residue will be required 

to conduct individual or consortiumbased verification processes to ensure 

that their feedstocks qualify as 

renewable biomass. These final 

provisions are described below, with a 

more in-depth discussion in Section 

II.B.4. 

For renewable fuel producers using 

feedstocks other than planted crops or 

crop residue from agricultural land that 

do not choose to participate in the thirdparty survey funded by an industry 

consortium, the final renewable biomass 

recordkeeping and reporting provisions 

require that individual 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. Specifically, 

EPA’s renewable biomass reporting 

requirements for producers who 

generate RINs include a certification on 

renewable fuel production reports that 

the feedstock used for each renewable 

fuel batch meets the definition of 

renewable biomass. Additionally, 

producers will be required to include 

with their quarterly reports a summary 

of the types and volumes of feedstocks 

used throughout the quarter, as well as 

maps of the land from which the 

feedstocks used in the quarter were 

harvested. EPA’s final renewable 

biomass recordkeeping provisions 

require renewable fuel producers to 

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maintain sufficient records to support 

their claims that their feedstocks meet 

the definition of renewable biomass, 

including maps or electronic data 

identifying the boundaries of the land 

where the feedstocks were produced, 

documents tracing the feedstocks from 

the land to the renewable fuel 

production facility, other written 

records from their feedstock suppliers 

that serve as evidence that the feedstock 

qualifies as renewable biomass, and for 

producers using planted trees or tree 

residue from tree plantations, written 

records that serve as evidence that the 

land from which the feedstocks were 

obtained was cleared prior to December 

19, 2007 and actively managed on that 

date. 

Based on USDA’s publicly available 

agricultural land data, EPA is able to 

establish a baseline of the aggregate 

amount of U.S. agricultural land 

(meaning cropland, pastureland and 

CRP land in the United States) that is 

available for the production of crops 

and crop residues for use in renewable 

fuel production consistent with the 

definition of renewable biomass. EPA 

has determined that, in the aggregate 

this amount of agricultural land (land 

cleared or cultivated prior to EISA’s 

enactment (December 19, 2007) and 

actively managed or fallow, and 

nonforested on that date) is expected to, 

at least in the near term, be sufficient to 

support EISA renewable fuel obligations 

and other foreseeable demands for crop 

products, without clearing and 

cultivating additional land. EPA also 

believes that economic factors will lead 

farmers to use the ‘‘agricultural land’’ 

available for crop production under 

EISA rather than bring new land into 

crop production. As a result, EPA is 

deeming renewable fuel producers using 

domestically-grown crops and crop 

residue as feedstock to be in compliance 

with the renewable biomass 

requirements, and those producers need 

not comply with the recordkeeping and 

quarterly reporting requirements as 

established for the non-crop-based 

biomass sector. However, EPA will 

annually review USDA data on lands in 

agricultural production to determine if 

these conclusions remain valid. If EPA 

determines that the 2007 baseline 

amount of eligible agricultural land has 

been exceeded, EPA will publish a 

notice of that finding in the Federal 

Register. At that point, renewable fuel 

producers using planted crops or crop 

residue from agricultural lands would 

be subject to the same recordkeeping 

and reporting requirements as other 

renewable fuel producers. 

5. EPA-Moderated Transaction System 

We introduced the EPA Moderated 

Transaction System (EMTS) in the 

NPRM as a new method for managing 

the generation of RINs and transactions 

involving RINs. EMTS is designed to 

resolve the RIN management issues of 

RFS1 that lead to widespread RIN 

errors, many times resulting in invalid 

RINs and often tedious remedial 

procedures to resolve those errors. It is 

also designed to address the added RIN 

categories, more complex RIN 

generation requirements, and additional 

volume of RINs associated with RFS2. 

Commenters broadly support EMTS and 

most stated that its use should coincide 

with the start of RFS2; however, many 

commenters expressed concerns over 

having sufficient time to implement the 

new system. In today’s action, we are 

requiring the use of EMTS for all RFS2 

RIN generations and transactions 

beginning July 1, 2010. EPA has utilized 

an open process for the development of 

EMTS since it was first introduced in 

the NPRM, conducting workshops and 

webinars, and soliciting stakeholder 

participation in its evaluation and 

testing. EPA pledges to work with the 

regulated community, as a group and 

individually, to ensure EMTS is 

successfully implemented. EPA 

anticipates that with this level of 

assistance, regulated parties will not 

experience significant difficulties in 

transitioning to the new system, and 

EPA believes that the many benefits of 

the new system warrant its immediate 

use. 

6. Other Changes to the RFS Program 

Today’s final rule also makes a 

number of other changes to the RFS 

program that are described in more 

detail in Sections II and III below, 

including: 

• Grandfathering provisions: 

Renewable fuel from existing facilities is 

exempt from the lifecycle GHG emission 

reduction threshold of 20% up to a 

baseline volume for that facility that 

will be established at the time of 

registration. As discussed in Section 

II.B.3, the exemption from the 20% GHG 

threshold applies only to renewable fuel 

that is produced from facilities which 

commenced construction on or before 

December 19, 2007, or in the case of 

ethanol plants that use natural gas or 

biodiesel for process heat, on or before 

December 31, 2009. 

• Renewable fuels produced from 

municipal solid waste (MSW): The new 

renewable biomass definition in EISA 

modified the ability for MSW-derived 

fuels to qualify under the RFS program 

by restricting it to ‘‘separated yard waste 

or food waste.’’ We are finalizing 

provisions that would allow certain 

portions of MSW to be included as 

renewable biomass, provided that 

reasonable separation has first occurred. 

• Equivalence Values: We are 

generally maintaining the provisions 

from RFS1 that the Equivalence Value 

for each renewable fuel will be based on 

its energy content in comparison to 

ethanol, adjusted for renewable content. 

The cellulosic biofuel, advanced 

biofuel, and renewable fuel standards 

can be met with ethanol-equivalent 

volumes of renewable fuel. However, 

since the biomass-based diesel standard 

is a ‘‘diesel’’ standard, its volume must 

be met on a biodiesel-equivalent energy 

basis. 

• Cellulosic biofuel waiver credits: If 

EPA reduces the required volume of 

cellulosic biofuel according to the 

waiver provisions in EISA, EPA will 

offer a number of credits to obligated 

parties no greater than the reduced 

cellulosic biofuel standard. These 

waiver credits are not allowed to be 

traded or banked for future use, and are 

only allowed to be used to meet the 

cellulosic biofuel standard for the year 

that they are offered. In response to 

concerns expressed in comments on the 

proposal, we are implementing certain 

restrictions on the use of these waiver 

credits. For example, unlike Cellulosic 

Biofuel RINs, waiver credits may not be 

used to meet either the advanced biofuel 

standard or the total renewable fuel 

standard. For the 2010 compliance 

period, since the cellulosic standard is 

lower than the level otherwise required 

by EISA, we are making cellulosic 

waiver credits available to obligated 

parties for end-of-year compliance 

should they need them at a price of 

$1.56 per gallon-RIN. 

• Obligated fuels: EISA expanded the 

program to cover ‘‘transportation fuel’’, 

not just gasoline. Therefore, under 

RFS2, obligated fuel volumes will 

include all gasoline and all MVNRLM 

diesel fuel. Other fuels such as jet fuel 

and fuel intended for use in ocean-going 

vessels are not obligated fuels under 

RFS2. However, renewable fuels used in 

jet fuel or heating oil are valid for 

meeting the renewable fuel volume 

mandates. Similarly, while we are not 

including natural gas, propane, or 

electricity used in transportation as 

obligated fuels at this time, we will 

allow renewable forms of these fuels to 

qualify under the program for generating 

RINs. 

B. Impacts of Increasing Volume 

Requirements in the RFS2 Program 

The displacement of gasoline and 

diesel with renewable fuels has a wide 

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range of environmental and economic 

impacts. As we describe in Sections IV– 

IX, we have assessed many of these 

impacts for the final rule. It is difficult 

to ascertain how much of these impacts 

might be due to the natural growth in 

renewable fuel use due to market forces 

as crude oil prices rise versus what 

might be forced by the RFS2 standards. 

Regardless, these assessments provide 

important information on the wider 

public policy considerations related to 

renewable fuel production and use, 

climate change, and national energy 

security. Where possible, we have tried 

to provide two perspectives on the 

impacts of the renewable fuel volumes 

mandated in EISA—both relative to the 

RFS1 mandated volumes, and relative to 

a projection from EIA (AEO 2007) of 

renewable fuel volumes that would have 

been expected without EISA. 

Based on the results of our analyses, 

when fully phased in by 2022, the 

increased volume of renewable fuel 

required by this final rule in comparison 

to the AEO 2007 forecast would result 

in 138 million metric tons fewer CO2- 

equivalent GHG emissions (annual 

average over 30 years), the equivalent of 

removing 27 million vehicles from the 

road today. 

At the same time, increases in 

emissions of hydrocarbons, nitrogen 

oxides, particulate matter, and other 

pollutants are projected to lead to 

increases in population-weighted 

annual average ambient PM and ozone 

concentrations, which in turn are 

anticipated to lead to up to 245 cases of 

adult premature mortality. The air 

quality impacts, however, are highly 

variable from region to region. Ambient 

PM2.5 is likely to increase in areas 

associated with biofuel production and 

transport and decrease in other areas; 

for ozone, many areas of the country 

will experience increases and a few 

areas will see decreases. Ethanol 

concentrations will increase 

substantially; for the other modeled air 

toxics there are some localized impacts, 

but relatively little impact on national 

average concentrations. We note that the 

air quality modeling results presented in 

this final rule do not constitute the 

‘‘anti-backsliding’’ analysis required by 

Clean Air Act section 211(v). EPA will 

be analyzing air quality impacts of 

increased renewable fuel use through 

that study and will promulgate 

appropriate mitigation measures under 

section 211(v), separate from this final 

action. 

In addition to air quality, there are 

also expected to be adverse impacts on 

both water quality and quantity as the 

production of biofuels and their 

feedstocks increase. 

In addition to environmental impacts, 

the increased volumes of renewable 

fuels required by this final rule are also 

projected to have a number of other 

energy and economic impacts. The 

increased renewable fuel use is 

estimated to reduce dependence on 

foreign sources of crude oil, increase 

domestic sources of energy, and 

diversify our energy portfolio to help in 

moving beyond a petroleum-based 

economy. The increased use of 

renewable fuels is also expected to have 

the added benefit of providing an 

expanded market for agricultural 

products such as corn and soybeans and 

open new markets for the development 

of cellulosic feedstock industries and 

conversion technologies. Overall, 

however, we estimate that the 

renewable fuel standards will result in 

significant net benefits, ranging between 

$16 and $29 billion in 2022. 

Table I.B–1 summarizes the results of 

our impacts analyses of the volumes of 

renewable fuels required by the RFS2 

standards in 2022 relative to the 

AEO2007 reference case and identifies 

the section where you can find further 

explanation of it. As we work to 

implement the requirements of EISA, 

we will continue to assess these 

impacts. These are the annual impacts 

projected in 2022 when the program is 

fully phased in. Impacts in earlier years 

would differ but in most cases were not 

able to be modeled or assessed for this 

final rule. 

TABLE I.B–1—IMPACT SUMMARY OF THE RFS2 STANDARDS IN 2022 RELATIVE TO THE AEO2007 REFERENCE CASE

(2007 DOLLARS) 

Category Impact in 2022 Section 

discussed 

Emissions and Air Quality 

GHG Emissions ......................................................... ¥138 million metric tons .................................................................................... V.D. 

Non-GHG Emissions (criteria and toxic pollutants) ... ¥1% to +10% depending on the pollutant ........................................................ VI.A. 

Nationwide Ozone ..................................................... +0.12 ppb population-weighted seasonal max 8 hr average ............................. VIII.D. 

Nationwide PM2.5 ....................................................... +0.002 μg/m3 population-weighted annual average PM2.5 ................................ VIII.D. 

Nationwide Ethanol .................................................... +0.409 μg/m3 population-weighted annual average .......................................... VI.D. 

Other Nationwide Air Toxics ...................................... ¥0.0001 to ¥0.023 μg/m3 population-weighted annual average depending 

on the pollutant.

VI.D. 

PM2.5-related Premature Mortality ............................. 33 to 85 additional cases of adult mortality (estimates vary by study) .............. VIII.D. 

Ozone-related Premature Mortality ........................... 36 to 160 additional cases of adult mortality (estimates vary by study) ............ VIII.D. 

Other Environmental Impacts 

Loadings to the Mississippi River from the Upper 

Mississippi River Basin.

Nitrogen: +1,430 million lbs. (1.2%) ...................................................................

Phosphorus: +132 million lbs. (0.7%) ................................................................

IX. 

Fuel Costs 

Gasoline Costs .......................................................... ¥2.4¢/gal ............................................................................................................ VII.D. 

Diesel Costs .............................................................. ¥12.1 ¢/gal ........................................................................................................ VII.D. 

Overall Fuel Cost ....................................................... ¥$11.8 Billion ..................................................................................................... VII.D. 

Gasoline and Diesel Consumption ............................ ¥13.6 Bgal ......................................................................................................... VII.C. 

Food Costs 

Corn ........................................................................... +8.2% .................................................................................................................. VIII.A. 

Soybeans ................................................................... +10.3% ................................................................................................................ VIII.A. 

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TABLE I.B–1—IMPACT SUMMARY OF THE RFS2 STANDARDS IN 2022 RELATIVE TO THE AEO2007 REFERENCE CASE

(2007 DOLLARS)—Continued 

Category Impact in 2022 Section 

discussed 

Food ........................................................................... +$10 per capita ................................................................................................... VIII.A. 

Economic Impacts 

Energy Security ......................................................... +$2.6 Billion ........................................................................................................ VIII.B. 

Monetized Health Impacts ......................................... ¥$0.63 to ¥$2.2 Billion ..................................................................................... VIII.D. 

GHG Impacts (SCC) a ................................................ +$0.6 to $12.2 Billion (estimates vary by SCC assumption) ............................. VIII.C. 

Oil Imports ................................................................. ¥$41.5 Billion ..................................................................................................... VIII.B 

Farm Gate Food ........................................................ +$3.6 Billion ........................................................................................................ VIII.A. 

Farm Income ............................................................. +$13 Billion (+36%) ............................................................................................ VIII.A. 

Corn Exports .............................................................. ¥$57 Million (¥8%) ........................................................................................... VIII.A. 

Soybean Exports ....................................................... ¥$453 Million (¥14%) ....................................................................................... VIII.A. 

Total Net Benefits b .................................................... +$13 to $26 Billion (estimates vary by SCC assumption) ................................. VIII.F. 

aThe models used to estimate SCC values have not been exercised in a systematic manner that would allow researchers to assess the probability of different values. Therefore, the interim SCC values should not be considered to form a range or distribution of possible or likely values. 

See Section VIII.D for a complete summary of the interim SCC values. bSum of Overall Fuel Costs, Energy Security, Monetized Health Impacts, and GHG Impacts (SCC). 

II. Description of the Regulatory 

Provisions 

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, many of the 

regulatory requirements of the RFS1 

program will remain largely or, in some 

cases, entirely unchanged. These 

provisions 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 are changing to 

implement the requirements in EISA fall 

primarily into the following seven 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) New definitions of renewable fuel, 

advanced biofuel, biomass-based diesel, 

and cellulosic biofuel. 

(4) New requirement that renewable 

fuels meet certain lifecycle emission 

reduction thresholds. 

(5) New definition of renewable 

biomass from which renewable fuels 

can be made, including certain land use 

restrictions. 

(6) Expansion of the types of fuels that 

are subject to the standards to include 

diesel. 

(7) Inclusion of specific types of 

waivers for different categories of 

renewable fuels and, in certain 

circumstances, 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 used as 

transportation fuel in the U.S. Since the 

RIN-based system generally has been 

successful in meeting the statutory 

goals, we are maintaining much of its 

structure under RFS2. 

This section describes the regulatory 

changes we are finalizing to implement 

the new EISA provisions. Section III 

describes other changes to the RFS 

program that we considered or are 

finalizing, including an EPA-moderated 

RIN trading system that provides a 

context within which all RIN transfers 

will occur. 

A. Renewable Identification Numbers 

(RINs) 

Under RFS2, each RIN will continue 

to represent one gallon of renewable 

fuel in the context of demonstrating 

compliance with Renewable Volume 

Obligations (RVO), consistent with our 

approach under RFS1, and the RIN will 

continue to have unique information 

similar to the 38 digits in RFS1. 

However in the EPA Moderated 

Transaction System (EMTS), RIN detail 

information will be available but 

generally hidden during transactions. In 

general the codes within the RIN will 

have the same meaning under RFS2 as 

they do under RFS1, with the exception 

of the D code which will be expanded 

to cover the four categories of renewable 

fuel defined in EISA. 

As described in Section I.A.2, the 

RFS2 regulatory program will go into 

effect on July 1, 2010, but the 2010 

percentage standards issued as part of 

today’s rule will apply to all gasoline 

and diesel produced or imported on or 

after January 1, 2010. As a result, some 

2010 RINs will be generated under the 

RFS1 requirements and others will be 

generated under the RFS2 requirements, 

but all RINs generated in 2010 will be 

valid for meeting the 2010 annual 

standards. Since RFS1 RINs and RFS2 

RINs will differ in the meaning of the D 

codes, we are implementing a 

mechanism for distinguishing between 

these two categories of RINs in order to 

appropriately apply them to the 

standards. In short, we are requiring the 

use of D codes under RFS2 that do not 

overlap the values for the D codes under 

RFS1. Table II.A–1 describes the D code 

definitions we are finalizing in today’s 

action. 

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TABLE II.A–1—FINAL 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. 

7 ............................................................ Not applicable ..................................................................................................... Cellulosic diesel. 

Under this approach, D code values of 

1 and 2 are only relevant for RINs 

generated under RFS1, and D code 

values of 3, 4, 5, 6, and 7 are only 

relevant for RINs generated under RFS2. 

As described in Section I.A.2, the RFS1 

regulations will apply in January 

through June of 2010, while the RFS2 

regulations will become effective on 

July 1, 2010. RINs generated under RFS1 

regulations in the first three months of 

2010 can be used for meeting the four 

2010 standards applicable under RFS2. 

To accomplish this, these RFS1 RINs 

will be subject to the RFS1/RFS2 

transition provisions wherein they will 

be deemed equivalent to one of the four 

RFS2 RIN categories using their RR and/ 

or D codes. See Section II.G.4 for further 

description of how RFS1 RINs will be 

used to meet standards under RFS2. The 

determination of which D code will be 

assigned to a given batch of renewable 

fuel is described in more detail in 

Section II.D.2 below. 

Table II.A–1 includes one D code 

corresponding to each of the four 

renewable fuel categories defined in 

EISA, and an additional D code of 7 

corresponding to the unique, additional 

type of renewable fuel called cellulosic 

diesel. As described in the NPRM, a 

diesel fuel product produced from 

cellulosic feedstocks that meets the 60% 

GHG threshold could qualify as either 

cellulosic biofuel or biomass-based 

diesel. The NPRM described two 

possible approaches to this unique 

category of renewable fuel: 

1. Have the producer of the cellulosic 

diesel designate their fuel up front as 

either cellulosic biofuel with a D code 

of 3, or biomass-based diesel with a D 

code of 4, limiting the subsequent 

potential in the marketplace for the RIN 

to be used for just one standard or the 

other. 

2. Have the producer of the cellulosic 

diesel designate their fuel with a new 

cellulosic D code of 7, allowing the 

subsequent use of the RIN in the 

marketplace interchangeably for either 

the cellulosic biofuel standard or the 

biomass-based diesel standard. 

We are finalizing the second option. 

By creating an additional D code of 7 to 

represent cellulosic diesel RINs, we 

believe its value in the marketplace will 

be maximized as it will be priced 

according to the relative demand for 

cellulosic biofuel and biomass-based 

diesel RINs. For instance, if demand for 

cellulosic biofuel RINs is higher than 

demand for biomass-based diesel RINs, 

then cellulosic diesel RINs will be 

priced as if they are cellulosic biofuel 

RINs. Not only does this approach 

benefit producers, but it allows 

obligated parties the flexibility to apply 

a RIN with a D code of 7 to either their 

cellulosic biofuel RVO or their biomassbased diesel RVO, depending on the 

number of RINs they have acquired to 

meet these two obligations. It also helps 

the functionality of the RIN program by 

helping protect against the potential for 

artificial RIN shortages in the 

marketplace for one standard or the 

other even though sufficient qualifying 

fuel was produced. 

Under RFS2, each batch-RIN 

generated will continue to uniquely 

identify not only a specific batch of 

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

will continue to be defined as follows: 

RIN: KYYYYCCCCFFFFFBBBBBRRDSS

SSSSSSEEEEEEEE 

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 is 

determined based on the types of 

feedstocks that are used, the land that is 

used to grow feedstocks for renewable 

fuel production, the processes that are 

used to convert those feedstocks into 

fuel, and the lifecycle greenhouse gas 

(GHG) emissions that are emitted in 

comparison to the gasoline or diesel that 

the renewable fuel displaces. This 

section describes these eligibility 

criteria and how we are implementing 

them for the RFS2 program. 

1. Changes in Renewable Fuel 

Definitions 

Under the previous Renewable Fuel 

Standards (RFS1), renewable fuel was 

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 included motor 

vehicle fuels produced from biomass 

material such as grain, starch, fats, 

greases, oils, and biogas. The definition 

specifically included cellulosic biomass 

ethanol, waste derived ethanol, and 

biodiesel, all of which were defined 

separately. (See 72 FR 23915). 

The definitions of renewable fuels 

under today’s rule (RFS2) are based on 

the new statutory definition in EISA. 

Like the previous 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 II.B.2. The 

specific definitions and how they differ 

from RFS1 follow below. 

a. Renewable Fuel 

‘‘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. 

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3The 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. 

‘‘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). Also renewable fuel now 

includes heating fuel and jet 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. However, we are 

allowing fuel producers, importers and 

end users to include electricity, natural 

gas, and propane made from renewable 

biomass as a RIN-generating renewable 

fuel in RFS only if they can identify the 

specific quantities of their product 

which are actually used as a 

transportation fuel,. This may be 

possible for some portion of renewable 

electricity and biogas 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 renewable 

electricity or biogas who documents the 

use of his product in a vehicle or engine 

through a contractual pathway would be 

allowed to generate RINs to represent 

that product, if it met the definition of 

renewable fuel. (This is also discussed 

in Section II.D.2.a) 

b. Advanced Biofuel 

‘‘Advanced Biofuel’’ is a renewable 

fuel other than ethanol derived from 

corn starch and for which lifecycle GHG 

emissions are at least 50% less than the 

gasoline or diesel fuel it displaces. 

Advanced biofuel would be assigned a 

D code of 5 as shown in Table II.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 50% GHG emission 

reduction threshold. Thus, even if corn 

starch-derived ethanol were made so 

that it met the 50% GHG reduction 

threshold, it will still be excluded from 

being defined as an advanced biofuel. 

Such ethanol while not an advanced 

biofuel will still qualify as a renewable 

fuel for purposes of meeting the 

standards. 

c. Cellulosic Biofuel 

Cellulosic biofuel is renewable fuel 

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 3 as shown in 

Table II.A–1. Cellulosic biofuel in 

general also qualifies as both ‘‘advanced 

biofuel’’ and ‘‘renewable fuel’’. 

The 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 

such as cellulosic gasoline or diesel 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 the 

final rule. 

d. Biomass-Based Diesel 

‘‘Biomass-based diesel’’ includes both 

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

cellulosic diesel). The definition of 

biodiesel is the same very broad 

definition of ‘‘biodiesel’’ that was in 

EPAct and in RFS1, and thus, it 

includes any diesel fuel made from 

biomass feedstocks. However, EISA 

added three restrictions. First, EISA 

requires that such fuel be made from 

renewable biomass. Second, its lifecycle 

GHG emissions must be at least 50% 

less than the diesel fuel it displaces. 

Third, the statutory definition of 

‘‘Biomass-based diesel’’ excludes 

renewable fuel derived from coprocessing biomass with a petroleum 

feedstock. In our proposed rule, we 

sought comment on two options for how 

co-processing could be treated. The first 

option considered co-processing to 

occur only if both petroleum and 

biomass feedstock are processed in the 

same unit simultaneously. The second 

option considered 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 selected the first option to be used 

in the final rule. Under this approach, 

a batch of fuel qualifying for the D code 

of 4 that is produced in a processing 

unit in which only renewable biomass 

is the feedstock for such batch, will 

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 will 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 rule, any fuel that does 

not satisfy the definition of biomassbased diesel only because it is coprocessed with petroleum will still meet 

the definition of ‘‘Advanced Biofuel’’ 

provided it meets the 50% GHG 

threshold and other criteria for the D 

code of 5. Similarly it will meet the 

definition of renewable fuel if it meets 

a GHG emission reduction threshold of 

20%. In neither case, however, will 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.3

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 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14687 

from renewable biomass that is used to 

replace or reduce fossil fuels used in 

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 (i.e., highway fuel) 

are valid for compliance purposes. We 

therefore 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 have modified the 

regulatory requirements to allow RINs 

assigned to renewable fuel blended into 

heating oil or jet fuel in addition to 

highway and nonroad transportation 

fuels to continue to be valid for 

compliance purposes. From a regulatory 

standpoint, there is no difference 

between renewable fuels used for 

transportation purposes, versus heating 

oil and jet fuels. 

EISA uses the term ‘‘home heating oil’’ 

in the definition of ‘‘additional 

renewable fuel.’’ The statute does not 

clarify whether the term should be 

interpreted to refer only to heating oil 

actually used in homes, or to all fuel of 

a type that can be used in homes. We 

note that the term ‘‘home heating oil’’ is 

typically used in industry in the latter 

manner, to refer to a type of fuel, rather 

than a particular use of it, and the term 

is typically used interchangeably in 

industry with heating oil, heating fuel, 

home heating fuel, and other terms 

depending on the region and market. 

We believe this broad interpretation 

based on typical industry usage best 

serves the goals and purposes of the 

statute. If EPA interpreted the term to 

apply only to heating oil actually used 

in homes, we would necessarily require 

tracking of individual gallons from 

production through ultimate use in use 

in homes in order to determine 

eligibility of the fuel for RINs. Given the 

fungible nature of the oil delivery 

market, this would likely be sufficiently 

difficult and potentially expensive so as 

to discourage the generation of RINs for 

renewable fuels used as home heating 

oil. This problem would be similar to 

that which arose under RFS1 for certain 

renewable fuels (in particular biodiesel) 

that were produced for the highway 

diesel market but were also suitable for 

other markets such as heating oil and 

non-road applications where it was 

unclear at the time of fuel production 

(when RINs are typically generated 

under the RFS program) whether the 

fuel would ultimately be eligible to 

generate RINs. Congress eliminated the 

complexity with regards to non-road 

applications in RFS2 by making all fuels 

used in both motor vehicle and nonroad 

applications subject to the renewable 

fuel standard program. We believe it 

best to interpret the Act so as to also 

avoid this type of complexity in the 

heating oil context. Thus, under today’s 

regulations, RINs may be generated for 

renewable fuel used as ‘‘heating oil,’’ as 

defined in existing EPA regulations at 

80.2(ccc). In addition to simplifying 

implementation and administration of 

the Act, this interpretation will best 

realize the intent of EISA to reduce or 

replace the use of fossil fuels, 

f. Cellulosic Diesel 

In the proposed rule, we sought 

comment on how diesel made from 

cellulosic feedstocks should be 

considered. Specifically, a diesel fuel 

product produced from cellulosic 

feedstocks that meets the 60% GHG 

threshold could qualify as either 

cellulosic biofuel or biomass-based 

diesel. Based on comments received, 

and as discussed previously in Section 

II.A, today’s rule requires the cellulosic 

diesel producer to categorize their 

product as cellulosic diesel with a D 

code of 7. It can then be traded in the 

marketplace and used for compliance 

with either the biomass-based diesel 

standard or the cellulosic biofuel 

standard. 

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 II.B.2–1 lists the 

thresholds established by EISA. 

TABLE II.B.2–1—LIFECYCLE GHG 

THRESHOLDS IN EISA 

[Percent reduction from a 2005 gasoline or 

diesel baseline] 

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

TABLE II.B.2–1—LIFECYCLE GHG 

THRESHOLDS IN EISA—Continued 

[Percent reduction from a 2005 gasoline or 

diesel baseline] 

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 are ‘‘grandfathered.’’ See 

Section II.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 

can be made only if it is determined that 

the 50% threshold is not commercially 

feasible for fuels made using a variety of 

feedstocks, technologies, and processes. 

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 can be made only if it is 

determined that the 60% threshold is 

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 

V, identified a range of fuel pathways 

that are capable of complying with the 

GHG performance thresholds for each of 

these separate fuel standards. Thus, we 

have determined that the GHG 

thresholds in Table II.B.2–1 should not 

be adjusted. Further discussion of this 

determination can be found in Section 

V.C. 

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3. Renewable Fuel Exempt From 20 

Percent GHG Threshold 

After considering comments received, 

the Agency has decided to implement 

the proposed option for interpreting the 

grandfathering provisions that provide 

an indefinite exemption from the 20 

percent GHG threshold for renewable 

fuel facilities which have commenced 

construction prior to December 19, 

2007. For these facilities, only the 

baseline volume of renewable fuel is 

exempted. For ethanol facilities which 

commenced construction after that date 

and which use natural gas, biofuels or 

a combination thereof, we proposed that 

such facilities would be ‘‘deemed 

compliant’’ with the 20 percent GHG 

threshold. The exemption for such 

facilities is conditioned on construction 

being commenced on or before 

December 31, 2009, and is specific only 

to facilities which produce ethanol only, 

per language in EISA. The exemption 

would continue indefinitely, provided 

the facility continues to use natural gas 

and/or biofuel. This section provides 

the background and summary of the 

original proposal, and the reasons for 

the selection of this option. 

a. General Background of the Exemption 

Requirement 

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. 

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.’’ 

Since all renewable fuel production 

facilities that commenced construction 

prior to the date of EISA enactment are 

covered by the more general 

grandfathering provision, this 

exemption can only apply to those 

facilities that commenced construction 

after enactment of EISA, and before the 

end of 2009. We proposed 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 on or 

before December 31, 2009, complete 

such construction in a reasonable 

amount of time, and continue to burn 

only natural gas, biomass, or a 

combination thereof. Most commenters 

generally agreed with our proposal, 

while other commenters argued that the 

exemption was only meant to last for a 

two-year period. As we noted in the 

NPRM, we believe that it would be a 

harsh result for investors in these new 

facilities, and would be generally 

inconsistent with the energy 

independence goals of EISA, to interpret 

the Act such that these facilities would 

only be guaranteed two years of 

participation in the RFS2 program. In 

light of these considerations, we 

continue to believe that it is an 

appropriate interpretation of the Act to 

allow the deemed compliant exemption 

to continue indefinitely with the 

limitations we proposed. Therefore we 

are making final this interpretation in 

today’s rule. 

b. Definition of Commenced 

Construction 

In defining ‘‘commence’’ and 

‘‘construction’’, we proposed to use the 

definitions of ‘‘commence’’ and ‘‘begin 

actual construction’’ from the Prevention 

of Significant Deterioration (PSD) 

regulations, which draws upon 

definitions in the Clean Air Act. (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 proposed adding 

language to the definition that is 

currently not in the PSD definition with 

respect to multi-phased projects. We 

proposed 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 

addressing 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 proposed that for RFS2 a 

reasonable time to complete 

construction of renewable fuel facilities 

be no greater than 3 years from initial 

commencement of construction. We 

sought comment on this time frame. 

Commenters generally agreed with 

our proposed definition of commenced 

construction. Some commenters felt that 

the 3 year time frame was not a 

‘‘reasonable time’’ to complete 

construction in light of the economic 

difficulties that businesses have been 

and will likely continue to be facing. We 

recognize that there have been extreme 

economic problems in the past year. 

Based on historical data which show 

construction of ethanol plants typically 

take about one year, we believe that the 

3-year time frame allows such 

conditions to be taken into account and 

that it is an appropriate and fair amount 

of time to allow for completion. 

Therefore, we are not extending the 

amount of time that constitutes 

‘‘reasonable’’ to five years as was 

suggested. 

c. Definition of Facility Boundary 

We proposed 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 proposed to modify the 

definition, however, to focus on the 

typical renewable fuel plant. We 

proposed 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. Commenters agreed with our 

proposed definition of ‘‘facility’’ and we 

are making that definition final today. 

d. Proposed Approaches and 

Consideration of Comments 

We proposed one basic approach to 

the exemption provisions and sought 

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 sought 

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comment were: (1) Expiration of 

exemption for grandfathered and 

‘‘deemed compliant’’ status when 

facilities undergo sufficient changes to 

be considered ‘‘reconstructed’’; (2) 

Expiration of exemption 15 years after 

EISA enactment, industry-wide; (3) 

Expiration of exemption 15 years after 

EISA enactment with limitation of 

exemption to baseline volume; (4) 

‘‘Significant’’ production components 

are treated as facilities and 

grandfathered or deemed compliant 

status ends when they are replaced; and 

(5) Indefinite exemption and no 

limitations placed on baseline volumes. 

i. Comments on the Proposed Basic 

Approach 

Generally, commenters supported the 

basic approach in which the volume of 

renewable fuel from grandfathered 

facilities exempt from the 20% GHG 

reduction threshold would be limited to 

baseline volume. One commenter 

objected to the basic approach and 

argued that the statute’s use of the word 

‘‘new’’ and the phrase ‘‘after December 

19, 2007’’ provided evidence that 

facilities which commenced 

construction prior to that date would 

not ever be subject to the threshold 

regardless of the volume produced from 

such facilities. In response, we note first 

that the statute does not provide a 

definition of the term ‘‘new facilities’’ for 

which the 20% GHG threshold applies. 

We believe that it would be reasonable 

to include within our interpretation of 

this term a volume limitation, such that 

a production plant is considered a new 

facility to the extent that it produces 

renewable fuel above baseline capacity. 

This approach also provides certainty in 

the marketplace in terms of the volumes 

of exempt fuel, and a relatively 

straightforward implementation and 

enforcement mechanism as compared to 

some of the other alternatives 

considered. Furthermore, EPA believes 

that the Act should not be interpreted as 

allowing unlimited expansion of exempt 

facilities for an indefinite time period, 

with all volumes exempt, as suggested 

by the commenter. Such an approach 

would likely lead to a substantial 

increase in production of fuel that is not 

subject to any GHG limitations, which 

EPA does not believe would be 

consistent with the objectives of the Act. 

We solicited comment on whether 

changes at a facility that resulted in an 

increase in GHG emissions, such as a 

change in fuel or feedstock, should 

terminate the facility’s exemption from 

the 20 percent GHG threshold. 

Generally, commenters did not support 

such a provision, pointing out that there 

are many variations within a plant that 

cannot be adequately captured in a table 

of fuel and feedstock pathways as we 

proposed (see 74 FR 24927). 

Implementing such a provision would 

create questions of accounting and 

tracking that would need to be 

evaluated on a time-consuming case-bycase basis. For example, if a switch to 

a different feedstock or production 

process resulted in less efficiency, 

facilities may argue that they are 

increasing energy efficiency elsewhere 

(e.g. purchasing waste heat instead of 

burning fuel onsite to generate steam). 

We would then need to assess such 

changes to track the net energy change 

a plant undergoes. Given the added 

complexity and difficulty in carrying 

out such an option, we have decided 

generally not to implement it. There is 

an exception, however, for ‘‘deemed 

compliant’’ facilities. These facilities 

achieve their status in part by being 

fired only by natural gas or biomass, or 

a combination thereof. Today’s rule 

provides, as proposed, that these 

facilities will lose their exemption if 

they switch to a fuel other than natural 

gas, biomass, or a combination thereof, 

since these were conditions that 

Congress deemed critical to granting 

them the exemption from the 20% GHG 

reduction requirement. 

We also solicited 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 to allow for increases in 

volume due to debottlenecking. Some 

favored this concept, while others 

argued that the tolerance should be set 

at 20 percent. After considering the 

comments received, we have decided 

that a 10% (and 20%) level is not 

appropriate for this regulation for the 

following reasons: (1) We have decided 

to interpret the exemption of the 

baseline volume of renewable fuel from 

the 20 percent requirement as extending 

indefinitely. Any tolerance provided 

could, therefore, be present in the 

marketplace for a considerable time 

period; (2) increases in volume of 10% 

or greater could be the result of 

modifications other than 

debottlenecking. Consistent with the 

basic approach we are taking today 

towards interpreting the grandfathering 

and deemed compliant provisions, we 

believe that the fuel produced as a result 

of such modifications comes from ‘‘new 

facilities’’ within the meaning of the 

statute, and should be subject to the 

20% GHG reduction requirement; (3) we 

are allowing baseline volume to be 

based on the maximum capacity that is 

allowed under state and federal air 

permits. With respect to the last reason, 

facilities that have been operating below 

the capacity allowed in their state 

permits would be able to claim a 

baseline volume based on the maximum 

capacity. As such, these facilities may 

indeed be able to increase their volume 

by 10 to 20 percent by virtue of how 

their baseline volume is defined. We 

believe this is appropriate, however, 

since their permits should reflect their 

design, and the fuel resulting from their 

original pre-EISA (or pre-2010, for 

deemed compliant facilities) design 

should be exempt from the 20% GHG 

reduction requirement. Nevertheless, we 

recognize and agree with commenters 

that some allowances should be made 

for minor changes brought about by 

normal maintenance which are 

consistent with the proper operation of 

a facility. EPA is not aware of a 

particular study or analysis that could 

be used as a basis for picking a tolerance 

level reflecting this concept, We believe, 

however, that the value should be 

relatively small, so as not to encourage 

plant expansions that are unrelated to 

debottlenecking. We believe that a 5% 

tolerance level is consistent with these 

considerations, and have incorporated 

that value in today’s rule. 

ii. Comments on the Expiration of 

Grandfathered Status 

Commenters who supported an 

expiration of the exemption did so 

because of concerns that the proposed 

approach of providing an indefinite 

exemption would not provide any 

incentives to bring these plants into 

compliance with current standards. 

They also objected to plants being 

allowed an indefinite period beyond the 

time period when it could be expected 

that they would have paid off their 

investors. The commenters argued that 

the cost of operation for such plants 

would be less than competing plants 

that do have to comply with current 

standards; as such, commenters 

opposed to the basic approach felt an 

indefinite exemption would be a 

subsidy to plants that will never comply 

with the 20 percent threshold level. The 

renewable fuels industry, on the other 

hand, viewed the options that would set 

an expiration date (either via 

cumulative reconstruction, or a 15-year 

period from date of enactment) as harsh, 

particularly if the lifecycle analysis 

results make it costly for existing 

facilities to meet the 20% threshold. 

Some also argued that no such temporal 

limitation appears in the statute. 

We considered such comments, but in 

light of recent lifecycle analyses we 

conducted in support of this rule we 

have concluded that many of the current 

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4 Volumes also include expansions to existing 

facilities, provided that the construction for such 

expansion commences prior to December 19, 2007. 

In such instances, the total volume from the original 

facility plus the additional volume due to 

expansion is grandfathered. 

technology corn ethanol plants may find 

it difficult if not impossible to retrofit 

existing plants to comply with the 20 

percent GHG reduction threshold. In 

addition, the renewable fuels industry 

viewed the alternative proposals that 

would set an expiration date (either via 

cumulative reconstruction, or a 15-year 

period from date of enactment) as harsh, 

particularly if the lifecycle analysis 

results make it costly for existing 

facilities to meet the 20% threshold. 

Given the difficulty of meeting such 

threshold, owners of such facilities 

could decide to shut down the plant. 

Given such implications of meeting the 

20 percent threshold level for existing 

facilities we have chosen not to finalize 

any expiration date. 

e. Final Grandfathering Provisions 

For the reasons discussed above, the 

Agency has decided to proceed with the 

proposed baseline volume approach, 

rather than the expiration options. We 

hold open the possibility, therefore, of 

revisiting and reproposing the 

exemption provision in a future 

rulemaking to take such advances into 

account. Ending the grandfathering 

exemption after its usefulness is over 

would help to streamline the ongoing 

implementation of the program. 

The final approach adopted today is 

summarized as follows: 

i. 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 defining the baseline 

volume of renewable fuel exempt from 

the 20% GHG threshold requirement to 

be the maximum volumetric capacity of 

the facility that is allowed in any 

applicable state air permit or Federal 

Title V operating permit.4 We had 

proposed in the NPRM that nameplate 

capacity be defined as permitted 

capacity, but that if the capacity was not 

stipulated in any federal, state or local 

air permit, then the actual peak output 

should be used. We have decided that 

since permitted capacity is the limiting 

condition, by virtue of it being an 

enforceable limit contained in air 

permits, that the term ‘‘nameplate 

capacity’’ is not needed. In addition, we 

are allowing a 5% tolerance as 

discussed earlier. Therefore, today’s rule 

defines permitted capacity as 105% of 

the maximum permissible volume 

output of renewable fuel allowed under 

operating conditions specified in all 

applicable preconstruction, construction 

and operating permits issued by 

regulatory authorities (including local, 

regional, state or a foreign equivalent of 

a state, and federal permits). If the 

capacity of a facility is not stipulated in 

such air permits, then the grandfathered 

volume is 105% of the maximum 

annual volume produced for any of the 

last five calendar years prior to 2008. 

Volumes greater than this amount 

which may typically be due to 

expansions of the facility which occur 

after December 19, 2007, will be subject 

to the 20% GHG reduction requirement 

if the facility wishes to generate RINs for 

the incremental expanded volume. The 

increased volume will 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 are 

irrelevant—they remain grandfathered 

as long as the overall volume falls 

within the baseline volume. Thus, for 

example, if an ethanol facility changed 

its operation to produce butanol, but the 

baseline volume remained the same, the 

fuel so produced would be exempt from 

the 20% GHG reduction requirement. 

The baseline volume will be defined 

as above for deemed compliant facilities 

(those ethanol facilities fired by natural 

gas or biomass or a combination thereof 

that commenced construction after 

December 19, 2007 but before January 1, 

2010) with the exception that if the 

maximum capacity is not stipulated in 

air permits, then the exempt volume is 

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, their status will be lost, 

and they will 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, if there are any changes in the 

mix of renewable fuels produced by the 

facility, only the ethanol volume 

remains grandfathered. We had solicited 

comment on whether fuels other than 

ethanol could also be deemed 

compliant. Based on comments received 

and additional consideration to this 

matter, we decided that because the Act 

does not authorize EPA to allow fuels 

other than ethanol, the deemed 

compliant provisions will apply only to 

facilities producing that fuel. 

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 will need to be converted to an 

annual rate. Because assumption of a 

24-hour per day production over 365 

days per year (8,760 production hours) 

may overstate the maximum annual 

capacity we are requiring a conversion 

rate of 95% of the total hours in a year 

(8,322 production hours) based on 

typical operating ‘‘uptime’’ of ethanol 

facilities. 

The facility registration process (see 

Section II.C) will be used to define the 

baseline volume for individual facilities. 

Owners and operators must submit 

information substantiating the permitted 

capacity of the plant, or the maximum 

annual peak capacity if the maximum 

capacity is not stipulated in a federal, 

state or local air permit, or EPA Title V 

operating permit. Copies of applicable 

air permits which stipulate the 

maximum annual capacity of the plant, 

must be provided as part of the 

registration process. Subsequent 

expansions at a grandfathered facility 

that results in an increase in volume 

above the baseline volume will subject 

the increase in volume to the 20% GHG 

emission reduction threshold (but not 

the original baseline volume). Thus, any 

new expansions will need to be 

designed to achieve the 20% GHG 

reduction threshold if the facility wants 

to generate RINs for that volume. Such 

determinations will be made on the 

basis of EPA-defined fuel pathway 

categories that are deemed to represent 

such 20% reduction. 

EPA enforcement personnel 

commented that claims for an 

exemption from the 20% GHG reduction 

requirement should be made promptly, 

so that they can be verified with recent 

supporting information. They were 

concerned, in particular, that claims for 

exempt status could be made many 

years into the future for facilities that 

may or may not have concluded 

construction within the required time 

period, but delayed actual production of 

renewable fuel due to market conditions 

or other reasons. EPA believes that this 

comment has merit, and has included a 

requirement in Section 80.1450(f) of the 

final rule for registration of facilities 

claiming an exemption from the 20% 

GHG reduction requirement by May 1, 

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2013. This provision does not require 

actual fuel production, but simply the 

filing of registration materials that assert 

a claim for exempt status. It will benefit 

both fuel producers, who will likely be 

able to more readily collect the required 

information if it is done promptly, and 

EPA enforcement personnel seeking to 

verify the information. However, given 

the potentially significant implications 

of this requirement for facilities that 

may qualify for the exemption but miss 

the registration deadline, the rule also 

provides that EPA may waive the 

requirement if it determines that the 

submission is verifiable to the same 

extent as a timely-submitted 

registration. 

ii. 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 final rule—the baseline volume 

of fuel would continue to be exempt 

from the 20% GHG threshold. We 

sought 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. Some commenters supported 

such an approach. We agreed, however, 

with other commenters who point out 

that the language in EISA provides for 

an indefinite exemption for 

grandfathered facilities. While we 

interpret the statute to limit the 

exemption to the baseline volume of a 

grandfathered facility, we do not 

interpret the language to allow EPA to 

require that replacements of coal fired 

units be natural gas or biofuel. Thus 

replacements of coal fired equipment 

will not affect the facility’s 

grandfathered status. 

iii. Registration, Recordkeeping and 

Reporting 

Facility owner/operators will be 

required to provide evidence and 

certification of commencement of 

construction. Such certification will 

require copies of all applicable air 

permits that apply to the construction 

and operation of the facility. 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 will be 

required to provide certification as well. 

Since the definition of commencement 

of construction includes having all 

necessary air permits, we will require 

that facilities outside the United States 

certify that such facilities have obtained 

all necessary permits for construction 

and operation required by the 

appropriate national and local 

environmental agencies. 

4. New Renewable Biomass Definition 

and Land Restrictions 

As explained in Section I, EISA lists 

seven types of feedstock that qualify as 

‘‘renewable biomass.’’ EISA limits not 

only the types of feedstocks that can be 

used to make renewable fuel, but also 

the land that 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 prohibits 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 describe EPA’s 

interpretation of several key terms 

related to the definition of renewable 

biomass, and the approach in today’s 

rule to implementing the renewable 

biomass requirements. 

a. Definitions of Terms 

EISA’s renewable biomass definition 

includes a number of terms that require 

definition. The following sections 

discuss EPA’s definitions for these 

terms, which were developed with ease 

of implementation and enforcement in 

mind. We have made every attempt to 

define these terms as consistently with 

other federal statutory and regulatory 

definitions as well as industry standards 

as possible, while keeping them 

workable for purposes of program 

implementation. 

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 proposed 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. 

We received numerous comments on 

our proposed definition of ‘‘planted 

crops,’’ largely in support of our 

proposed definition. However, some 

commenters noted that ‘‘microcrops,’’ 

such as duckweed, a flowering plant 

typically grown in ponds or tanks, are 

also being investigated for used as 

renewable fuel feedstocks. These 

microcrops are typically grown in a 

similar manner to algae, but cannot be 

categorized as algae since they are 

relatively more complex organisms. 

EPA’s proposed definition would have 

unintentionally excluded microcrops 

such as duckweed through the 

requirement that planted crops be 

‘‘applied to the ground.’’ After 

considering comments received, EPA 

does not believe that there is any basis 

under EISA for excluding from the 

definition of renewable biomass crops 

such as duckweed that are applied to a 

tank or pond for growth rather than to 

the soil. As with other planted crops, 

these ponds or tanks must be located on 

existing ‘‘agricultural land,’’ as described 

below, to qualify as renewable biomass 

under EISA. Therefore, including such 

microcrops within the definition of 

renewable biomass will not result in the 

direct loss of forestland or other 

ecologically sensitive land that Congress 

sought to protect through the land 

restrictions in the definition of 

renewable biomass. Doing so will 

further the objectives of the statute of 

promoting the development of emerging 

technologies to produce clean 

alternatives to petroleum-based fuels, 

and to further U.S. energy 

independence. 

For these reasons, we are finalizing 

our proposed definition of ‘‘planted 

crops,’’ with the inclusion of provisions 

allowing for the growth of ‘‘microcrops’’ 

in ponds or tanks that are located on 

agricultural land. Our final definition 

also includes a reference to ‘‘vegetative 

propagation,’’ in which a new plant is 

produced from an existing vegetative 

structure, as one means by which 

planted crops may reproduce, since this 

is an important method of reproduction 

for microcrops such as duckweed. The 

final definition of ‘‘planted crops’’ 

includes all annual or perennial 

agricultural crops from existing 

agricultural land 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, duckweed and other 

species (but not including algae species 

or planted trees), providing that they 

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were intentionally applied by humans 

to the ground, a growth medium, or a 

pond or tank, either by direct 

application as seed or plant, or through 

intentional natural seeding or vegetative 

propagation by mature plants 

introduced or left undisturbed for that 

purpose. We note that because EISA 

contains specific provisions for planted 

trees and tree residue from tree 

plantations, our final definition of 

planted crops in EISA excludes planted 

trees, even if they may be considered 

planted crops under some 

circumstances. 

We proposed that ‘‘crop residue’’ be 

limited to the residue, such as corn 

stover and sugarcane bagasse, left over 

from the harvesting of planted crops. 

We sought comment on including 

biomass from agricultural land removed 

for purposes of invasive species control 

or fire management. We received many 

comments supporting the inclusion of 

biomass removed from agricultural land 

for purposes of invasive species control 

and/or fire management. We believe that 

such biomass is typically removed from 

agricultural land for the purpose of 

preserving or enhancing its value in 

agricultural crop production. It may be 

removed at the time crops are harvested, 

post harvest, periodically (e.g., for 

pastureland) or during extended fallow 

periods. We agree with the commenters 

that this material is a form of biomass 

residue related to crop production, 

whether or not derived from a crop 

itself, and, therefore, are modifying the 

proposed definition of ‘‘crop residue’’ to 

include it. We also received comments 

encouraging us to expand the definition 

of crop residue to include materials left 

over after the processing of the crop into 

a useable resource, such as husks, seeds, 

bagasse and roots. EPA agrees with 

these comments and has altered the 

final definition to cover such materials. 

Based on comments received, our final 

definition of ‘‘crop residue’’ is the 

biomass left over from the harvesting or 

processing of planted crops from 

existing agricultural land and any 

biomass removed from existing 

agricultural land that facilitates crop 

management (including biomass 

removed from such lands in relation to 

invasive species control or fire 

management), whether or not the 

biomass includes any portion of a crop 

or crop plant. 

Our proposed regulations restricted 

planted crops and crop residue to that 

harvested from existing agricultural 

land, which, under our proposed 

definition, includes three land 

categories—cropland, pastureland, and 

Conservation Reserve Program (CRP) 

land. We proposed 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. We proposed 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. We also proposed that CRP land, 

which is administered by USDA’s Farm 

Service Agency, qualify as ‘‘agricultural 

land’’ under RFS2. 

EPA received numerous comments on 

our proposed definition of existing 

agricultural land. Generally, 

commenters were in support of our 

definition of ‘‘cropland’’ and its 

inclusion in the definition of existing 

agricultural land. Additionally, 

commenters generally did not object to 

CRP lands or pastureland being 

included in the definition of agricultural 

land. Based on our consideration of 

comments received on the proposed 

rule, EPA is including cropland, 

pastureland and CRP land in the 

definition of existing agricultural land, 

as proposed. 

We sought comment in the proposal 

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. EPA received a number of 

comments concerning whether 

rangeland should be included in the 

definition of existing agricultural land 

under RFS2. Some commenters urged 

EPA to expand the definition of existing 

agricultural land to include rangeland, 

arguing that rangelands could serve as 

important sources of renewable fuel 

feedstocks. Many of these commenters 

argued that, although it is generally less 

intensively managed than cropland, 

rangeland is nonetheless actively 

managed through control of brush or 

weed species, among other practices. In 

contrast, other commenters argued 

against the inclusion of rangeland, 

contending that the potential conversion 

of rangeland into cropland for growing 

renewable biomass would lead to losses 

of carbon, soil, water quality, and 

biodiversity. 

Under EISA, renewable biomass 

includes crops and crop residue from 

agricultural land cleared or cultivated at 

any time prior to the enactment of EISA 

that is either ‘‘actively managed of 

fallow’’ and nonforested. In determining 

whether rangeland should be 

considered existing agricultural land 

under this provision, EPA must decide 

if rangeland qualifies as ‘‘actively 

managed or fallow.’’ EPA believes that 

the term ‘‘actively managed’’ is best 

interpreted by reference to the type of 

material and practices that this 

provision addresses—namely crops and 

residue associated with growing crops. 

We think it is appropriate to inquire 

whether the type of management 

involved in a land type is consistent 

with that which would occur on land 

where crops are harvested. Thus, while 

we acknowledge that some types of 

rangeland are managed to a certain 

degree, the level of ‘‘active management’’ 

that is typically associated with land 

dedicated to growing agricultural crops 

is far more intensive than the types of 

management associated with rangeland. 

For example, rangeland is rarely tilled, 

fertilized or irrigated as croplands and, 

to a lesser degree, pasturelands, are. 

Furthermore, since rangeland 

encompasses a wide variety of 

ecosystems, including native grasslands 

or shrublands, savannas, wetlands, 

deserts and tundra, including it in the 

definition of agricultural land would 

increase the risk that these sensitive 

ecosystems would become available 

under EISA for conversion into 

intensively managed mono-culture 

cropland. Finally, the conversion of 

relatively undisturbed rangeland to the 

production of annual crops could in 

some cases lead to large releases of 

GHGs stored in the soil, as well as a loss 

of biodiversity, both of which would be 

contrary to EISA’s stated goals. For 

these reasons, EPA is not including 

rangeland in the definition of ‘‘existing 

agricultural land’’ in today’s final rule. 

We proposed 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 proposed 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 received extensive 

comments on this interpretation. Many 

commenters suggested an interpretation 

of the requirement that agricultural land 

be ‘‘actively managed’’ to mean that the 

land had to be ‘‘actively managed’’ at the 

time EISA was passed on December 17, 

2007, such that the amount of land 

available for biofuel feedstock 

production was established at that point 

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and would not diminish over time. 

Other commenters supported our 

proposed interpretation, which would 

mean that the amount of land available 

for biofuel feedstock production could 

diminish over time if parcels of land 

cease to be actively managed at any 

point, thus taking them out of 

contention for biofuel feedstock 

cultivation. Some commenters argued 

that this interpretation is contrary to 

Congress’ intent and the basic premise 

of the RFS program since, over time, it 

could lead to a reduction in the amount 

of renewable biomass available for use 

as renewable fuel feedstocks, while the 

statutorily required volumes of 

renewable fuel increase over time. 

These commenters further argue that the 

active management provision should be 

interpreted as a ‘‘snapshot’’ of 

agricultural land existing and actively 

managed on December 19, 2007. Under 

this interpretation, the land that was 

cleared or cultivated prior to December 

19, 2007 and was actively managed on 

that date, would be eligible for 

renewable biomass production 

indefinitely. 

We agree that the goal of the EISA and 

RFS program, to increase the presence 

of renewable fuels in transportation 

fuel, will be better served by 

interpreting the ‘‘actively managed or 

fallow’’ requirement in the renewable 

biomass definition as applying to land 

actively managed or fallow on December 

19, 2007, rather than interpreting this 

requirement as applying beginning on 

December 19, 2007 and continuously 

thereafter. In addition, by simplifying 

the requirement in this fashion, there 

will be significantly less burden on 

regulated parties in ensuring that their 

feedstocks come from qualifying lands. 

For these reasons, we are modifying the 

definition of existing agricultural land 

so that the ‘‘active management’’ 

requirement is satisfied for those that 

were cleared or cultivated and actively 

managed or fallow, and non-forested on 

December 19, 2007. 

Further, we proposed and are 

finalizing that ‘‘actively managed’’ 

means 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. While 

we received comments indicating that 

including a definitive checklist of 

required evidential records would be 

helpful to have explicitly identified in 

the regulations, we are not doing so in 

order to maintain flexibility, as 

feedstock producers may vary in the 

types of evidence they can readily 

obtain to show that their agricultural 

land was actively managed. We are 

adding, however, a clarification that the 

records must be traceable to the land in 

question. For example, it will not be 

sufficient to have a receipt for seed 

purchase if there is not additional 

evidence indicating that the seed was 

applied to the land which is claimed as 

existing agricultural land. 

The term ‘‘fallow’’ is generally used to 

describe cultivated land taken out of 

production for a finite period of time. 

We proposed and sought comment on 

defining 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. We also proposed and 

sought comment on requiring 

documentation of such intent. We 

received many comments that 

supported our proposed definition of 

fallow. We also received comments 

indicating that EPA should set a time 

limit for land to qualify as fallow (as 

opposed to abandoned for agricultural 

purposes). We have decided not to 

include a time limit for land to qualify 

as ‘‘fallow’’ because we understand that 

agricultural land may be left fallow for 

many different purposes and for varying 

amounts of time. Any particular 

timeframe that EPA might choose for 

this purpose would be somewhat 

arbitrary. Further, EISA does not 

indicate a time limit on the period of 

time that qualifying land could be 

fallow, so EPA does not believe that it 

would be appropriate to do so in its 

regulations. Therefore, EPA is finalizing 

its proposed definition of ‘‘fallow.’’ 

Finally, in order to define the term 

‘‘nonforested’’ as used in the definition 

of ‘‘existing agricultural land,’’ we 

proposed first to define the term 

‘‘forestland’’ as generally undeveloped 

land covering a minimum area of one 

acre upon which the predominant 

vegetative cover is trees, including land 

that formerly had such tree cover and 

that will be regenerated. We also 

proposed that forestland would not 

include tree plantations. ‘‘Nonforested’’ 

land under our proposal would be land 

that is not forestland. 

We received many comments on our 

proposed definition of forestland. Some 

commenters urged EPA to broaden the 

definition of ‘‘forestland’’ to include tree 

plantations, arguing that plantations are 

well-accepted as a subset of forestland. 

Others advocated that EPA should make 

every effort to distinguish between tree 

plantations and forestland so as not to 

run the risk of allowing native forests to 

be converted into less diverse tree 

plantations from which trees could be 

harvested for renewable fuel 

production. For today’s final rule, EPA 

is including tree plantations as a subset 

of forestland since it is commonly 

understood as such throughout the 

forestry industry. Under EISA, 

renewable biomass may include ‘‘slash 

and pre-commercial thinnings’’ from 

non-federal forestlands, and ‘‘planted 

trees and tree residue’’ from actively 

managed tree plantations on non-federal 

land. One effect under EISA of the 

modification from the proposed rule to 

include tree plantations as a subset of 

forestland is to allow pre-commercial 

thinnings and slash, in addition to 

planted trees and tree residue, harvested 

from tree plantations to serve as 

qualifying feedstocks for renewable fuel 

production. EPA believes it is 

appropriate to include pre-commercial 

thinnings and slash from actively 

managed tree plantations as renewable 

biomass, consistent with the EISA 

provision allowing harvested trees and 

tree residue from tree plantations to 

qualify as renewable biomass. Another 

effect of including the tree plantations 

as a kind of forestland is that, since 

crops and crop residue must come from 

land that was ‘‘non-forested’’ as of the 

date of EISA enactment, a tract of land 

managed as a tree plantation on the date 

of EISA enactment could not be 

converted to cropland for the 

production of feedstock for RINgenerating renewable fuel. EPA believes 

that this result in keeping with 

Congressional desire to avoid the 

conversion of new lands to crop 

production for renewable fuel 

production. 

Additionally, EPA received comments 

indicating that, in order to be consistent 

with existing statutory and/or regulatory 

definitions of ‘‘forestland,’’ EPA should 

exclude tree covered areas in intensive 

agricultural crop production settings, 

such as fruit orchards, or tree-covered 

areas in urban settings such as city 

parks from the definition of forestland. 

EPA agrees that these types of land 

cannot be characterized as ‘‘forestland,’’ 

and is thus excluding them from the 

definition. EPA’s final definition of 

forestland is ‘‘generally undeveloped 

land covering a minimum of 1 acre 

upon which the primary vegetative 

species is trees, including land that 

formerly had such tree cover and that 

will be regenerated and tree plantations. 

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Tree covered areas in intensive 

agricultural crop production settings, 

such as fruit orchards, or tree-covered 

areas in urban settings such as city 

parks, are not considered forestland.’’ 

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 proposed 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. Some commenters disagreed 

with our inclusion of naturally seeded 

trees in our definition of ‘‘planted trees.’’ 

They argue that an area which is 

managed for natural regeneration of 

trees is more akin to a natural forest 

than a tree plantation, and that the 

difference between the two types of land 

should be clear in order to distinguish 

between the two and to avoid the 

effective conversion of natural forests to 

tree plantations under EISA. EPA agrees 

that the inclusion of natural reseeding 

in the definition of ‘‘planted trees’’ 

would make distinguishing between tree 

plantations and forests difficult or 

impossible, thus negating the separate 

restrictions that Congress placed on the 

two types of land. On the other hand, 

EPA believes that trees that are naturally 

seeded and grown together with handor machine-planted trees in a tree 

plantation should not categorically be 

excluded from qualifying as renewable 

biomass. Such natural reseeding may 

occur after planting the majority of trees 

in a tree plantation, and may be 

consistent with the management plan 

for a tree plantation. EPA has decided, 

therefore, to modify its proposed 

definition of ‘‘planted tree’’ to be trees 

harvested from a tree plantation. The 

term ‘‘tree plantation’’ is defined as a 

stand of no less than 1 acre composed 

primarily of trees established by handor machine-planting of a seed or 

sapling, or by coppice growth from the 

stump or root of a tree that was handor machine-planted.’’ The net effect is 

that as long as a tree plantation consists 

‘‘primarily’’ of trees that were hand- or 

machine planted (or derived therefrom, 

as described below), then all trees from 

the tree plantation, including those 

established from natural seeding by 

mature trees left undisturbed for such a 

purpose, will qualify as renewable 

biomass. 

We also received a number of 

comments suggesting that EPA broaden 

the definition of planted trees to include 

other methods of tree regeneration, such 

as coppice (the production of new stems 

from stumps or roots), that are 

frequently used in the forestry industry 

to regenerate tree plantations. EPA 

believes that ‘‘planted’’ implies direct 

human intervention, and that allowing 

stump-growth from the stump or roots 

of a tree that was hand- or machineplanted is consistent with this concept. 

Therefore, today’s final rule broadens 

the concept of ‘‘planted trees’’ from a 

tree plantation to include ‘‘a tree 

established by hand- or machineplanting of a seed or sapling, or by 

coppice growth from the stump or root 

of a tree that was hand- or machineplanted.’’ This new language will appear 

in the definition of ‘‘tree plantation.’’ 

In the NPRM, we proposed 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 one acre. 

We received numerous comments on 

our definition of tree plantation. Several 

commenters urged EPA to define tree 

plantation more broadly by using the 

definition from the Dictionary of 

Forestry—‘‘a stand composed primarily 

of trees established by planting or 

artificial seeding,’’ However, this 

definition does not provide sufficiently 

clear guidelines for determining 

whether a given parcel of land would be 

considered a tree plantation rather than 

a natural forest. Since trees are 

considered renewable biomass under 

RFS2 only if they are harvested from 

tree plantations, we believe that our 

proposed definition was clearer and 

more easily applied in the field. 

Accordingly, EPA has not adopted the 

definition of this term from the 

Dictionary of Forestry. Other 

commenters argued that there is no 

technical justification for limiting the 

number of species or number of trees in 

a plantation, and that many tree 

plantations include a variety of species. 

EPA believes that there is merit in these 

comments. Accordingly, EPA is 

finalizing a broadened definition of ‘‘tree 

plantation,’’ by removing the limitations 

on the number and species of trees. EPA 

is defining tree plantation as ‘‘a stand of 

no less than 1 acre composed primarily 

of trees established by hand- or 

machine-planting of a seed or sapling, 

or by coppice growth from the stump or 

root of a tree that was hand- or machineplanted.’’ 

We proposed to apply similar 

management restrictions to tree 

plantations as would apply to existing 

agricultural land and also to interpret 

the EISA language as requiring that to 

qualify as renewable biomass for 

renewable fuel 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. Consistent 

with our final position regarding 

actively managed existing agricultural 

land, we are defining the term ‘‘actively 

managed’’ in the context of tree 

plantations as managed for a 

predetermined outcome as evidenced by 

any of the following that must be 

traceable to the land in question: Sales 

records for planted trees or slash; 

purchasing records for seeds, seedlings, 

or other nursery stock together with 

other written documentation connecting 

the land in question to these purchases; 

a written management plan for 

silvicultural purposes; documentation 

of participation in a silvicultural 

program sponsored by a Federal, state or 

local government agency; 

documentation of land management in 

accordance with an agricultural or 

silvicultural product certification 

program; an agreement for land 

management consultation with a 

professional forester that identifies the 

land in question; or evidence of the 

existence and ongoing maintenance of a 

road system or other physical 

infrastructure designed and maintained 

for logging use, together with one of the 

above-mentioned documents. 

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. As with the definition 

of ‘‘actively managed’’ as it applies to 

crops from existing agricultural lands, 

we received extensive comments on this 

interpretation. As with our final 

position for crops from existing 

agricultural lands, we are interpreting 

the ‘‘active management’’ requirement 

for tree plantations to apply on the date 

of EISA’s enactment, December 19, 

2007. Those tree plantations that were 

cleared or cultivated and actively 

managed on December 19, 2007 are 

eligible for the production of planted 

trees, tree residue, slash and precommercial thinnings for renewable fuel 

production. 

In lieu of the term ‘‘tree residue,’’ we 

proposed to use the term ‘‘slash’’ in our 

regulations as a more descriptive, but 

otherwise synonymous, term. According 

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to the Dictionary of Forestry (1998, p. 

168), a source of commonly understood 

industry definitions, 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 also 

proposed to clarify that slash can 

include tree bark and can be the result 

of any natural disaster, including 

flooding. We received comments in 

support of this additional inclusion and 

are expanding the definition of ‘‘slash’’ 

to include tree bark and residue 

resulting from natural disaster, 

including flooding. We received general 

support for our proposal to substitute 

our definition of ‘‘slash’’ for ‘‘tree 

residue,’’ however, several commenters 

argued that our definition of slash is too 

narrow to be substituted for ‘‘tree 

residue,’’ which should include woody 

residues from saw mills and paper mills 

that process planted trees from tree 

plantations. EPA agrees that the term 

‘‘residue’’ should include this material. 

Therefore, EPA is expanding the 

definition of ‘‘tree residue’’ to include 

residues from processing planted trees 

at lumber and paper mills, but is 

limiting it to the biogenically derived 

portion of the residues that can be 

traced back to feedstocks meeting the 

definition of renewable biomass (i.e. 

planted trees and tree residue from 

actively managed tree plantations on 

non-federal land cleared at any time 

prior to December 19, 2007). RINs may 

only be generated for the fraction of fuel 

produced that represents the biogenic 

portion of the tree residue, using the 

procedures described in ASTM test 

method D–6866. Thus, if the tree 

residues are mixed with chemicals or 

other materials during processing at the 

lumber or paper mills, producers may 

only generate RINs for the portion of the 

mixture that is actually derived from 

planted trees. EPA’s final definition of 

‘‘tree residue’’ is ‘‘slash and any woody 

residue generated during the processing 

of planted trees from actively managed 

tree plantations for use in lumber, 

paper, furniture or other applications, 

providing that such woody residue is 

not mixed with similar residue from 

trees that do not originate in 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. However, EISA excludes 

slash and pre-commercial thinnings 

from forests or forestlands that are 

ecological communities with a global or 

State ranking of critically imperiled, 

imperiled, or rare pursuant to a State 

Natural Heritage Program, old growth 

forest, or late successional forest. 

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

preamble, our definition of ‘‘forestland’’ 

is generally undeveloped land covering 

a minimum of 1 acre upon which the 

primary vegetative species is trees, 

including land that formerly had such 

tree cover and that will be regenerated 

and tree plantations. Tree-covered areas 

in intensive agricultural crop 

production settings, such as fruit 

orchards or tree-covered areas in urban 

setting such as city parks, are not 

considered forestland. Also as noted in 

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

adopting the definition of slash listed in 

the Dictionary of Forestry, with the 

addition of tree bark and residue 

resulting from natural disaster, 

including flooding. 

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.’’ 

Because what may now be considered 

pre-commercial may eventually be 

saleable as renewable fuel feedstock, we 

proposed 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. Additionally, we 

proposed to include diseased trees in 

the definition of pre-commercial 

thinnings due to the fact that they can 

threaten the integrity of an otherwise 

healthy stand of trees, and their removal 

can be viewed as reducing stocking to 

promote the growth of more desirable 

trees. We sought comment on whether 

our definition of pre-commercial 

thinnings should include a maximum 

diameter and, if so, what the 

appropriate maximum diameter should 

be. We received comments on our 

proposed definition of pre-commercial 

thinnings that were generally supportive 

of our proposed definition. Many 

commenters argued that EPA should not 

use a maximum tree diameter as a basis 

for defining pre-commercial thinning as 

tree diameter varies greatly by forest 

type and location, making any diameter 

limitation EPA might set arbitrary. EPA 

agrees with this assessment. 

Commenters also argued that precommercial thinnings may include 

other non-tree vegetative material that is 

removed to promote and improve tree 

growth. EPA is attempting to utilize 

standard industry definitions to the 

extent practicable, and believes that the 

proposed definition of pre-commercial 

thinnings, based largely on the 

Dictionary of Forestry definition with 

the addition of other vegetative material 

removed to promote tree growth, is 

appropriate. Therefore, we are finalizing 

the proposed definition of ‘‘precommercial thinnings,’’ with the 

addition of the phrase ‘‘or other 

vegetative material that is removed to 

promote tree growth.’’ 

We proposed that the State Natural 

Heritage Programs referred to in EISA 

are those comprising a network 

associated with NatureServe, a nonprofit conservation and research 

organization. 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 proposed and sought comment on 

prohibiting slash and pre-commercial 

thinnings from all forest ecological 

communities with global or State 

rankings of critically imperiled, 

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

case of State rankings) from being used 

for renewable fuel for which RINs may 

be generated under RFS2. 

We proposed to use data compiled by 

NatureServe and published in special 

reports to identify ‘‘ecologically 

sensitive forestland.’’ The reports listed 

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 included descriptions of the key 

geographic and biologic attributes of the 

referenced ecological community. We 

proposed that the document be 

incorporated by reference into the 

definition of renewable biomass in the 

final RFS2 regulations (and updated as 

appropriate through notice and 

comment rulemaking). The document 

would 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. Draft versions of the 

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document containing the global and 

State rankings were placed in the docket 

for the proposed rule. 

EPA received several comments on 

our proposed interpretation of EISA’s 

State Natural Heritage Program 

requirement and the reports listing G1– 

G3 and S1–S3 ecological communities. 

Several commenters argued that while 

EISA authorizes EPA to exclude slash 

and pre-commercial thinnings from S1– 

3 and G1 and G2 communities, it does 

not authorize the exclusion of biomass 

from G3 communities, which are 

designated as ‘‘vulnerable,’’ not 

‘‘critically imperiled, imperiled or rare,’’ 

as EISA requires. The commenters 

further argue that there is little or no 

environmental benefit to adding G3 

communities to the list of lands 

unavailable for renewable fuel feedstock 

production, and that their inclusion 

limits the availability of forest-derived 

biomass. EPA agrees with these 

comments, and has drafted today’s final 

rule so as not to specifically exclude 

from the definition of renewable 

biomass slash and pre-commercial 

thinnings from G3-ranked ‘‘vulnerable’’ 

ecological communities to qualify as 

renewable biomass for purposes of 

RFS2. We are interpreting EISA’s 

language to exclude from the definition 

of renewable biomass any biomass taken 

from ecological communities in the U.S. 

with Natural Heritage Programs global 

ranking of G1 or G2, or with a State 

ranking of S1, S2, or S3. We are 

including in today’s rulemaking docket 

(EPA–HQ–OAR–2005–0161) the list of 

ecological communities fitting this 

description. 

To complete the definition of 

‘‘ecologically sensitive forestland,’’ we 

proposed to include old growth and late 

successional forestland which is 

characterized by trees at least 200 years 

old. We received comments on this 

proposed definition recommending that 

EPA not use a single tree age in the 

define old growth and late-successional 

forests, as this criterion does not apply 

to all types of forests. While EPA 

understands that there are a number of 

criteria for determining whether a forest 

is old growth and that the criteria differ 

depending on the type of forest, for 

purposes of the RFS2 rule, EPA seeks to 

use definitive criteria that can be 

applied by non-professionals. EPA is 

finalizing the definition of ‘‘old growth’’ 

as proposed. 

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 proposed 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. 

Furthermore, we proposed 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. We sought 

comment on two possible 

implementation alternatives for 

identifying areas at risk of wildfire. The 

first proposed alternative would 

incorporate into our definition of ‘‘areas 

at risk of wildfire’’ any communities 

identified as ‘‘communities at risk’’ and 

covered by a community wildfire 

protection plan (CWPP). Communities 

at risk are defined through a process 

within the document, ‘‘Field Guidance— 

Identifying and Prioritizing 

Communities at Risk’’ (National 

Association of State Foresters, June 

2003). CWPPs are 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 

sought comment on incorporating by 

reference into the final RFS2 regulations 

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

approved CWPP. We also sought 

comment on a second implementation 

approach, which 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. 

We noted that 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 the 2000 

Census and the U.S. Geological Survey 

National Land Cover Data (NLCD), and 

we sought comment on how best to use 

this map. 

We received comments on the 

proposal and on the two proposed 

alternative options for identifying areas 

at risk of wildfire. A number of 

commenters argued that EPA should 

define ‘‘areas at risk of wildfire’’ using an 

existing definition of WUI from the 

Healthy Forests Restoration Act (Pub. L. 

108–148). Many commenters 

recommended that EPA include both 

lands covered by a CWPP as well as 

lands meeting the Healthy Forests 

Restoration Act definition of WUI in 

order to maximize the amount of land 

available for biomass feedstock and to 

encourage the removal of hazardous fuel 

for wildfires. EPA understands that very 

few communities that might be eligible 

for a CWPP actually have one in place, 

due to the numerous administrative 

steps that must be taken in order to have 

a CWPP approved, so the option of 

defining areas at risk of wildfire 

exclusively by reference to a list of 

communities with an approved CWPP 

would be underinclusive of all lands 

that a professional forester would 

consider to be at risk of wildfire. 

Furthermore, EPA believes that the 

statutory definition of WUI from the 

Healthy Forests Restoration Act (Pub. L. 

108–148) is too vague using directly in 

implementing the RFS2 program. If EPA 

used this WUI definition, individual 

plots of land would have to be assessed 

by a professional forester on a case-bycase basis in order to determine if they 

meet the WUI definition, creating an 

expensive burden for landowners 

seeking to sell biomass from their lands 

as renewable fuel feedstocks. 

In light of the comments received and 

the need for a simple way for 

landowners and renewable fuel 

producers to track the status of 

particular plots of land, for the final rule 

we are identifying ‘‘areas at risk of 

wildfire’’ as those areas identified as 

wildland urban interface. Those areas 

are depicted and mapped at http:// 

silvis.forest.wisc.edu/Library/ 

WUILibrary.asp. The electronic WUI 

map is a readily accessible reference 

tool that was prepared by experts in the 

field of identifying areas at risk of 

wildfire, and is thus an ideal reference 

for purposes of implementing RFS2. 

EPA has included in the rulemaking 

docket instructions on using the WUI 

map to find the status of a plot of land. 

v. Algae 

EISA specifies that ‘‘algae’’ qualify as 

renewable biomass. EPA did not 

propose a definition for this term. A 

number of commenters have requested 

clarification, specifically asking whether 

cyanobacteria (also known as blue-green 

algae), diatoms, and angiosperms are 

within the definition. Technically, the 

term ‘‘algae’’ has recently been defined 

as ‘‘thallophytes (plants lacking roots, 

stems and leaves) that have chlorophyll 

a as their primary photosynthetic 

pigment and lack a sterile covering of 

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5Phycology, Robert Edward Lee, Cambridge 

University Press, 2008, page 3. 6See, generally, Introduction to the Algae. 

Structure and Reproduction, by Harold C. Bold and 

Michael J. Wynne, Prentice-Hall Inc. 1978, page 31. 7See id. 

cells around the reproductive cells.’’ 5

Algae are relatively simple organisms 

that are virtually ubiquitous, occurring 

in freshwater, brackish water, saltwater, 

and terrestrial habitats. When present in 

water, they may be suspended, or grow 

attached to various substrates. They 

range in size from unicellular to among 

the longest living organisms (e.g. sea 

kelp). There is some disagreement 

among scientists as to whether 

cyanobacteria should be considered 

bacteria or algae. Some consider them to 

be bacteria because of their cellular 

organization and biochemistry. 

However, others find it more significant 

that they contain chlorophyll a, which 

differs from the chlorophyll of bacteria 

which are photosynthetic, and also 

because free oxygen is liberated in bluegreen algal photosynthesis but not in 

that of the bacteria.6 EPA believes that 

it furthers the purposes of EISA to 

interpret the term ‘‘algae’’ in EISA 

broadly to include cyanobacteria, since 

doing so will make available another 

possible feedstock for renewable fuel 

production that will further the energy 

independence and greenhouse gas 

reduction objectives of the Act. Further, 

EPA expects that cyanobacteria used in 

biofuel production would be cultivated, 

as opposed to harvested, and therefore 

that there would be no significant 

impact from use of cyanobacteria for 

biofuel production on naturally 

occurring algal populations. Diatoms are 

generally considered by the scientific 

community to be algae,7 and, consistent 

with this general scientific consensus, 

EPA interprets the EISA definition of 

algae to include them. Microcrop 

angiosperms, however, do not meet the 

definition of algae, even if they live in 

an aquatic habitat, since they are 

relatively more complex organisms than 

the algae. A discussion of microcrop 

angiosperms is included above in the 

discussion of ‘‘planted crops and crop 

residue.’’ 

b. Implementation of Renewable 

Biomass Requirements 

Our proposed approach to the 

treatment of renewable biomass under 

RFS2 was 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. 

Our proposed and final approaches to 

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 eligible for the program if 

made from certain feedstocks, and if 

some of those feedstocks 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 meets EISA’s 

definitions of renewable biomass 

include land restrictions. Otherwise, no 

RINs could be generated to represent the 

renewable fuel produced or imported. 

The EISA language does not distinguish 

between domestic renewable fuel 

feedstocks and renewable fuel 

feedstocks that come from abroad, so 

our final rule requires similar feedstock 

affirmation and recordkeeping 

requirements for both RIN-generating 

domestic renewable fuel producers and 

RIN-generating foreign producers or 

importers. 

We acknowledge that incidental 

contaminants can be introduced into 

feedstocks during cultivation, transport 

or processing. It is not EPA’s intent that 

the presence of such contaminants 

should disqualify the feedstock as 

renewable biomass. The final 

regulations therefore stipulate that the 

term ‘‘renewable biomass’’ includes 

incidental contaminants related to 

customary feedstock production and 

transport that are present in feedstock 

that otherwise meets the definition if 

such incidental contaminants are 

impractical to remove and occur in de 

minimus levels. By ‘‘related to 

customary feedstock production and 

transport,’’ we refer to contaminants 

related to crop production, such as soil 

or residues related to fertilizer, pesticide 

and herbicide applications to crops, as 

well as contaminants related to 

feedstock transport, such as nylon rope 

used to bind feedstock materials. It 

would also include agricultural 

contaminants introduced to the 

feedstock during sorting or shipping, 

such as miscellaneous sorghum grains 

present in a load of corn kernels. 

However, contamination is not related 

to customary feedstock production and 

transport, so such feedstocks would not 

qualify, and in particular, any 

hazardous waste or toxic chemical 

contaminant in feedstock would 

disqualify the feedstock as renewable 

biomass. 

ii. Whether RINs Must Be 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. 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.’’ 

The inclusion of such 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 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 shortage of 

RINs in the market that could force 

obligated parties into non-compliance 

even though biofuels are being 

produced and used. 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. 

With these concerns in mind, EPA 

proposed to preserve in RFS2 the RFS1 

requirement that RINs be generated for 

all qualifying renewable fuel. We also 

proposed that renewable fuel producers 

maintain records showing that they 

utilized feedstocks made from 

renewable biomass if they are generating 

RINs, or, if they are not generating RINs, 

that they did not use feedstocks that 

qualify as renewable biomass. However, 

we considered this matter further, and 

we realize that the implication of these 

proposed requirements is that 

renewable fuel producers would be 

caught in the untenable position of 

being forced to participate in the RFS2 

program (register, keep records, etc.) 

even if they are unable to generate RINS 

because their feedstocks do not meet the 

definition of renewable biomass. We 

received many comments on the 

proposed requirement to generate RINs 

for all qualifying renewable fuel. Most 

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commenters argued that the requirement 

to keep records for non-qualifying 

renewable fuels was excessively 

onerous and served little purpose for the 

program. 

After considering the comments 

received, EPA has determined that this 

requirement would be overly 

burdensome and unreasonable for 

producers. The burden stems from the 

requirement that producers prove that 

their feedstocks do not qualify if they 

are not generating RINs. If the data did 

not exist or could not be obtained, 

producers could not produce the fuel, 

even if no RINs would be generated. 

Thus, for the final rule, EPA is requiring 

only that producers that do generate 

RINs have the requisite records (as 

discussed in section II.B.4.c.i. of this 

preamble) documenting that their fuel is 

produced from feedstocks meeting the 

definition of renewable biomass. NonRIN generating producers need not 

maintain any paperwork related to their 

feedstocks and their origins. 

Although EPA is not requiring that 

RINs be generated for all qualifying 

renewable fuel, EPA is seeking to avoid 

situations where biofuels are produced, 

but RINs are not made available to the 

market for compliance. EPA received 

comments requesting that we consider a 

provision in which any volume of 

renewable fuel for which RINs were not 

generated would be an obligated volume 

for that producer, to serve as a 

disincentive for those producers who 

might not generate RINs in order to 

avoid the RFS program requirements. 

While EPA is not finalizing this 

provision in today’s rule, we may 

consider a future rulemaking to 

promulgate a provision such as this if 

we find that EISA volumes are not being 

met due to producers declining to 

generate RINs for their qualifying 

renewable fuel. We also note that it is 

ultimately the availability of qualifying 

renewable fuel, as determined in part by 

the number of RINs in the marketplace, 

that will determine the extent to which 

EPA should issue a waiver of RFS 

requirements on the basis of inadequate 

domestic supply. It is in the interest of 

renewable fuel producers to avoid a 

situation where a waiver of the EISA 

volume requirements appears necessary. 

EPA encourages renewable fuel 

producers to generate RINs for all fuel 

that is made from feedstocks meeting 

the definition of renewable biomass and 

that meets the GHG emissions reduction 

thresholds set out in EISA. Please see 

section II.D.6 for additional discussion 

of this issue. 

c. Implementation Approaches for 

Domestic Renewable Fuel 

Consistent with RFS1, renewable fuel 

producers will be responsible for 

generating Renewable Identification 

Numbers (RINs) under RFS2. In order to 

determine whether or not their fuel is 

eligible for generating RINs, renewable 

fuel producers will generally need to 

have at least basic information about the 

origin of their feedstocks, to ensure they 

meet the definition of renewable 

biomass. In the proposal, EPA described 

and sought comment on several 

approaches for implementing the land 

restrictions on renewable biomass 

contained in EISA. 

The proposed approach for ensuring 

that producers generate RINs properly 

was that EPA would 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 

fall within the EISA definition of 

renewable biomass. EPA would require 

renewable fuel producers who generate 

RINs to affirm on their renewable fuel 

production reports that the feedstock 

used for each renewable fuel batch 

meets the definition of renewable 

biomass. EPA would also require 

renewable fuel producers to maintain 

sufficient records to support these 

claims. Specifically, we proposed that 

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 proposed to require 

renewable fuel producers to have, at a 

minimum, written records from their 

feedstock supplier that serve as 

evidence that the feedstock qualifies as 

renewable biomass. 

We sought comment on this approach 

generally as well as other methods of 

verifying renewable fuel producers’ 

claims that feedstocks qualify as 

renewable biomass. EPA received 

extensive comments on the proposed 

approach. Many affected parties argued 

that the proposed approach would pose 

an unnecessary recordkeeping burden 

on both feedstock and renewable fuel 

producers when, in practice, new lands 

will not be cleared, at least in the near 

future, for purposes of growing 

renewable fuel feedstocks. Commenters 

argued that individual recordkeeping 

was onerous, when compliance with the 

renewable biomass requirements could 

be determined through the use of 

existing data and third-party programs. 

Commenters contend that the 

recordkeeping and feedstock tracking 

requirements are particularly arduous 

for corn, soybeans and other agricultural 

crops that are used as renewable fuel 

feedstocks due to both the maturity and 

the highly fungible nature of those 

feedstock systems. In contrast, other 

commenters argued that recordkeeping 

and reporting requirements are 

necessary to ensure that feedstocks are 

properly verified as renewable biomass 

to prevent undesirable impacts on 

natural ecosystems and wildlife habitat 

globally. 

We also sought comment on the 

possible use under EISA of 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. We 

examined third-party organizations that 

certify specific types of biomass from 

croplands and organizations that certify 

forest lands, including the Roundtable 

on Sustainable Palm Oil, the Basel 

Criteria for Responsible Soy Production, 

the Roundtable on Sustainable Biofuels 

(RSB) and the Better Sugarcane 

Initiative (BSI). Additionally, we 

examined the work of the international 

Soy Working Group, the Brazilian 

Association of Vegetable Oil Industries 

(ABIOVE) and Brazil’s National 

Association of Grain Exporters (ANEC), 

Greenpeace, Verified Sustainable 

Ethanol initiative, the Sustainable 

Agriculture Network (SAN), the Forest 

Stewardship Council (FSC), American 

Tree Farm program and Sustainable 

Forestry Initiative (SFI). We proposed 

not to solely rely on any existing thirdparty verification program to implement 

the land restrictions on renewable 

biomass under RFS2 for several reasons. 

These programs are limited in the scope 

of products they certify, the acreage of 

land certified through third parties in 

the U.S. covers only a small portion of 

the total available land estimated to 

qualify for renewable biomass 

production under the EISA definition, 

and none of the existing third-party 

systems had definitions or criteria that 

perfectly match the land use definitions 

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and restrictions contained in the EISA 

definition of renewable biomass. 

We received several comments 

indicating that producers would like to 

use evidence of their participation in 

these types of programs to prove that 

their feedstocks meet the definition of 

renewable biomass. Others argued that 

while, at this time, the requirements of 

third-party programs may not 

encompass all of the restrictions and 

requirements of EISA’s renewable 

biomass definition, the programs may 

alter their criteria in the future to 

parallel EISA’s requirements. EPA 

agrees that this is a possibility and, in 

the future, will consider the use of these 

programs in order to simplify 

compliance with the renewable biomass 

requirements. We encourage fuel 

producers to work to identify changes to 

such programs that could allow them to 

be used as a viable compliance option. 

In the proposal, EPA also 

acknowledged that land restrictions 

contained within the definition of 

renewable biomass may not, in practice, 

result in a significant change in 

agricultural practices, since biomass 

from nonqualifying lands may still be 

used for non-fuel (e.g., food) purposes. 

Therefore, we sought 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. Additionally, 

EPA offered as an alternative the use of 

existing satellite and aerial imagery and 

mapping software and tools to 

implement the renewable biomass 

provisions of EISA. We received 

numerous comments in support of these 

options. Commenters argued that USDA 

collects and maintains ample data on 

land use that EPA could use to 

demonstrate that, due to increasing crop 

yields and other considerations, 

agricultural land acreage will not 

expand, at least in the near term, to 

accommodate the increased renewable 

fuel obligations of RFS2. 

EPA also sought comment on an 

additional alternative in which EPA 

would require renewable fuel producers 

to set up and administer a companywide quality assurance program that 

would create an additional level of rigor 

in the implementation scheme for the 

EISA land restrictions on renewable 

biomass. EPA is not finalizing this 

company-wide quality assurance 

program approach, but rather, is 

encouraging the option for an industrywide quality assurance program, as 

described in the following section, to be 

administered. 

i. Recordkeeping and Reporting for 

Feedstocks 

After considering the comments we 

received on the proposed approach, 

EPA is finalizing reporting and 

recordkeeping requirements comparable 

to those in the approach we discussed 

in the proposed rule for all categories of 

renewable biomass, with the exception 

of planted crops and crop residue from 

agricultural land in the United States, 

which will be covered by the aggregate 

compliance approach discussed below 

in Section II.B.4.c.iii. EPA believes that 

these requirements on the fuel producer 

utilizing feedstocks other than crops 

and crop residue are necessary to ensure 

that the definition of renewable biomass 

is being met, and to allow feedstocks to 

be traced from their original producer to 

the renewable fuel production facility. 

Furthermore, we believe that, in most 

cases, feedstock producers will already 

have or will be able to easily generate 

the specified documentation for 

renewable fuel producers necessary to 

provide them with adequate assurance 

that the feedstock in question meets the 

definition of renewable biomass. 

Under today’s rule, all renewable fuel 

producers must maintain written 

records from their feedstock suppliers 

for each feedstock purchase that identify 

the type and amount of feedstocks and 

where the feedstock was produced and 

that are sufficient to verify that the 

feedstock qualifies as renewable 

biomass. Specifically, renewable fuel 

producers must maintain maps and/or 

electronic data identifying the 

boundaries of the land where the 

feedstock was produced, product 

transfer documents (PTDs) or bills of 

lading tracing the feedstock from that 

land to the renewable fuel production 

facility, and other written records that 

serve as evidence that the feedstock 

qualifies as renewable biomass. We 

believe the maps or electronic data can 

be easily generated using existing Webbased information. 

Producers using planted trees and tree 

residue from tree plantations must 

maintain additional documentation that 

serves as evidence that the tree 

plantation was cleared prior to 

December 19, 2007, and actively 

managed as a tree plantation on 

December 19, 2007. This documentation 

must consist of the following types of 

records which must be traceable to the 

land in question: Sales records for 

planted trees or slash; purchasing 

records for fertilizer, weed control, or 

reseeding, including seeds, seedlings, or 

other nursery stock together with other 

written documentation connecting the 

land in question to these purchases; 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 a silvicultural product 

certification program; an agreement for 

land management consultation with a 

professional forester that identifies the 

land in question; or evidence of the 

existence and ongoing maintenance of a 

road system or other physical 

infrastructure designed and maintained 

for logging use. There are many existing 

programs, such as those administered by 

USDA and independent third-party 

certifiers, that could be used as 

documentation that verifies that 

feedstock from certain land qualifies as 

renewable biomass. For example, many 

tree plantation owners already 

participate in a third-party certification 

program such as FSC or SFI. Written 

proof of participation by a tract of land 

in a program of this type on December 

19, 2007 would be sufficient to show 

that a tree plantation was cleared prior 

to that date and that it was actively 

managed on that date. The tree 

plantation owner would need to send 

copies of this documentation to the 

renewable fuel producer when 

supplying them with biomass that will 

be used as a renewable fuel feedstock. 

We anticipate that the recordkeeping 

requirements will result in renewable 

fuel producers amending their contracts 

and modifying their supply chain 

interactions to satisfy the requirement 

that producers have documented 

assurance and proof about their 

feedstock’s origins. Enforcement will 

rely in part on EPA’s review of 

renewable fuel production reports and 

attest engagements of renewable fuel 

producers’ records. EPA will also 

consult other data sources, including 

any data made available by USDA, and 

may conduct site visits or inspections of 

feedstock producers’ and suppliers’ 

facilities. 

The reporting requirements for 

renewable biomass in today’s final rule 

include, as proposed, include an 

affirmation by the renewable fuel 

producer for each batch of renewable 

fuel for which they generate RINs that 

the feedstocks used to produce the batch 

meet the definition of renewable 

biomass. Additionally, the final 

reporting requirements include a 

quarterly report to be sent to EPA by 

each renewable fuel producer that 

includes a summary of the types and 

volumes of feedstocks used throughout 

the quarter, as well as electronic data or 

maps identifying the land from which 

those feedstocks were harvested. 

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Producers need not provide duplicate 

maps if purchasing feedstocks multiple 

times from one plot of land; producers 

may cross-reference the previously 

submitted map. Producers will also be 

required to keep records tracing the 

feedstocks from the land to the 

renewable fuel production facility, other 

written records from their feedstock 

suppliers that serve as evidence that the 

feedstock qualifies as renewable 

biomass, and for producers using 

planted trees or tree residue from tree 

plantations, written records that serve as 

evidence that the land from which the 

feedstocks were obtained was cleared 

prior to December 19, 2007 and actively 

managed on that date. These 

requirements will apply to renewable 

fuel producers using feedstocks from 

foreign sources (unless special 

approvals are granted in the future, as 

described below), or from domestic 

sources, except for planted crops or crop 

residue (discussed below). 

This approach will be integrated into 

the existing registration, recordkeeping, 

reporting, and attest engagement 

procedures for renewable fuel 

producers. It places the burden of 

implementation and enforcement on 

renewable fuel producers rather than 

bringing feedstock producers and 

suppliers directly under EPA regulation, 

minimizing the number of regulated 

parties under RFS2. 

EPA also sought comment on, and is 

finalizing as an option, an alternative 

approach in which EPA allows 

renewable fuel producers and renewable 

fuel feedstock producers and suppliers 

to develop a quality assurance program 

for the renewable fuel production 

supply chain, similar to the model of 

the successful Reformulated Gasoline 

Survey Association. While individual 

renewable fuel producers may still 

choose to comply with the individual 

renewable biomass recordkeeping and 

reporting requirements rather than 

participate in a quality assurance 

program, we believe that this preferred 

alternative could be less costly than an 

individual compliance demonstration, 

and it would add a quality assurance 

element to RFS2. Those participating 

renewable fuel producers would be 

presumed to be in compliance with the 

renewable biomass requirements unless 

and until the quality assurance program 

finds evidence to the contrary. Under 

today’s rule, renewable fuel producers 

must choose either to comply with the 

individual renewable biomass 

recordkeeping and reporting described 

above, or they must participate in the 

quality assurance program. 

The quality assurance program must 

be carried out by an independent 

auditor funded by renewable fuel 

producers and feedstock suppliers. The 

program must consist of a verification 

program for participating renewable fuel 

producers and renewable feedstock 

producers and handlers designed to 

provide independent oversight of the 

feedstock handling processes that are 

required to determine if a feedstock 

meets the definition of renewable 

biomass. Under this option, a 

participating 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 auditor 

conduct a program of compliance 

surveys. The compliance audit must be 

carried out by an independent auditor 

pursuant to a detailed survey plan 

submitted to EPA for approval by 

November 1 of the year preceding the 

year in which the alternative 

compliance program would be 

implemented. The compliance survey 

program plan must include a 

statistically supportable methodology 

for the survey, the locations of the 

surveys, the frequency of audits 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 individual 

recordkeeping and reporting 

requirements included in the RFS2 

regulations. 

Under this alternative compliance 

program, the independent auditor 

would be required to visit participating 

renewable feedstock producers and 

suppliers to determine if the biomass 

they supply to renewable fuel producers 

meets the definition of renewable 

biomass. This program would be 

designed to ensure representative 

coverage of participating renewable 

feedstock producers and suppliers. The 

auditor 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 renewable fuel producers 

would be responsible for identifying 

and addressing the root cause of the 

problem. The renewable fuel producers 

would have to take corrective action to 

retire the appropriate number of invalid 

RINs depending on the violation. EPA 

received comments from a number of 

parties who were supportive of this 

option as an alternative and lessburdensome way of ensuring that 

renewable fuel feedstocks meet the 

definition of renewable biomass. EPA 

believes this option to be an efficient 

and effective means of implementing 

and enforcing the renewable biomass 

requirements of EISA, and has therefore 

included it as a compliance option in 

today’s final rule. 

ii. Approaches for Foreign Producers of 

Renewable Fuel 

The EISA renewable biomass 

language does not distinguish between 

domestic renewable fuel and fuel 

feedstocks and renewable fuel and fuel 

and feedstocks that come from abroad. 

EPA proposed that foreign producers of 

renewable fuel that is exported to the 

U.S. be required to meet the same 

compliance obligations as domestic 

renewable fuel producers, as well as 

some additional measure, discussed in 

Section II.C., designed to facilitate EPA 

enforcement in other countries. These 

proposed obligations include facility 

registration and submittal of 

independent engineering reviews 

(described in Section II.C below), and 

reporting, recordkeeping, and attest 

engagement requirements. The proposal 

also would have included for foreign 

producers the same obligations that 

domestic producers have for verifying 

that their feedstock meets the definition 

of renewable biomass, 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 suppliers to ensure that 

they receive and maintain accurate and 

sufficient documentation in their 

records to support their claims. 

(1) RIN-Generating Importers 

EPA proposed to allow importers to 

generate RINs for renewable fuel they 

are importing into the U.S. only if the 

foreign producer of that renewable fuel 

had not already done so. Under the 

proposal, in order to generate RINs, 

importers would need to obtain 

information from the registered foreign 

producers concerning the point of origin 

of their fuel’s feedstock and whether it 

meets the definition of renewable 

biomass. Therefore, we proposed that in 

the event that a batch of foreignproduced renewable fuel does not have 

RINs accompanying it when it arrives at 

a U.S. port, an importer must obtain 

documentation that proves that the 

fuel’s feedstock meets the definition of 

renewable biomass (as described in 

Section II.B.4.a. of this preamble) from 

the fuel’s producer, who must have 

registered with the RFS program and 

conducted a third-party engineering 

review. With such documentation, the 

importer could generate RINs prior to 

introducing the fuel into commerce in 

the U.S. 

We sought comment on this proposed 

approach and whether and to what 

extent the approaches for ensuring 

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compliance with the EISA’s land 

restrictions by foreign renewable fuel 

producers should differ from the 

proposed approach for domestic 

renewable fuel producers. We received 

comments on the proposed 

implementation option for importers of 

foreign renewable fuel. Some argue that 

the proposed recordkeeping 

requirements for imported fuel were 

overly burdensome. On the other hand, 

others argued that importers, similarly 

to domestic producers, should be 

required to obtain information that can 

serve as evidence that the feedstocks 

meet the definition of renewable 

biomass, in order to avoid fraud. Some 

commenters also argued that importers 

should be able to generate RINs for fuel 

imported from foreign producers that 

are not registered with EPA under the 

RFS2 program. 

For the final rule, EPA is requiring 

that importers may only generate RINs 

for renewable fuel if the foreign 

producer has not already done so. The 

foreign producers must be registered 

with EPA under the RFS2 program, and 

must have conducted an independent 

engineering review. Furthermore, we are 

requiring that importers obtain from the 

foreign producer and maintain in their 

records written documentation that 

serves as evidence that the renewable 

fuel for which they are generating RINs 

was made from feedstocks meeting the 

definition of renewable biomass. The 

foreign producer that originally 

generated the fuel must ensure that 

these feedstock records are transferred 

with each batch of fuel and ultimately 

reach the RIN-generating importer. A 

requirement that importers maintain 

these renewable biomass records is 

consistent with the renewable biomass 

recordkeeping requirements imposed on 

domestic producers of renewable fuel. 

(2) RIN-Generating Foreign Producers 

Foreign producers that intend to 

generate RINs would be required to 

designate renewable fuel intended for 

export to the U.S. as such, 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, 

as discussed in Section II.D.2.b. 

Similarly to domestic producers of 

renewable fuel, foreign producers must 

obtain and maintain written 

documentation from their feedstock 

providers that can serve as evidence that 

their feedstocks meet the definition of 

renewable biomass. Foreign producers 

may also develop a quality assurance 

program for their renewable fuel 

production supply chain, as described 

above. However, while domestic 

renewable fuel producers using crops or 

crop residues may rely on the aggregate 

compliance approach described below 

to ensure that their feedstocks are 

renewable biomass, this approach is not 

available at this time to foreign 

renewable fuel producers, as described 

below. 

EPA believes that the renewable 

biomass recordkeeping provisions are 

necessary in order for EPA to ensure 

that RINs are being generated for fuel 

that meets EISA’s definition of 

renewable fuel. Just as for domestic 

producers, foreign producers must 

maintain evidence that the fuel meets 

the GHG reduction requirements and is 

made from renewable biomass. 

iii. Aggregate Compliance Approach for 

Planted Crops and Crop Residue From 

Agricultural Land 

In light of the comments received on 

the proposed renewable biomass 

recordkeeping requirements and 

implementation options, EPA sought 

assistance from USDA in determining 

whether existing data and data sources 

might suggest an alternative method for 

verifying compliance with renewable 

biomass requirements associated with 

the use of crops and crop residue for 

renewable fuel production. Taking into 

consideration publicly available data on 

agricultural land available from USDA 

and USGS as well as expected economic 

incentives for feedstock producers, EPA 

has determined that an aggregate 

compliance approach is appropriate for 

certain types of renewable biomass, 

namely planted crops and crop residue 

from the United States. 

Under the aggregate compliance 

approach, EPA is determining for this 

rule the total amount of ‘‘existing 

agricultural land’’ in the U.S. (as defined 

above in Section II.B.4.a.) at the 

enactment date of EISA, which is 402 

million acres. EPA will monitor total 

agricultural land annually to determine 

if national agricultural land acreage 

increases above this 2007 national 

aggregate baseline. Feedstocks derived 

from planted crops and crop residues 

will be considered to be consistent with 

the definition of renewable biomass and 

renewable fuel producers using these 

feedstocks will not be required to 

maintain specific renewable biomass 

records as described below unless and 

until EPA determines that the 2007 

national aggregate baseline is exceeded. 

If EPA finds that the national aggregate 

baseline is exceeded, individual 

recordkeeping and reporting 

requirements as described below will be 

triggered for renewable fuel producers 

using crops and crop residue. We 

believe that the aggregate approach will 

fully ensure that the EISA renewable 

biomass provisions related to crops and 

crop residue are satisfied, while also 

easing the burden for certain renewable 

fuel producers and their feedstock 

suppliers vis-a`-vis verification that their 

feedstock qualifies as renewable 

biomass. 

As discussed in more detail below, 

there are five main factors supporting 

the aggregate compliance approach we 

are taking for planted crops and crop 

residue. First, EPA is using data sets 

that allow us to obtain an appropriately 

representative estimate of the 

agricultural lands available under EISA 

for the production of crops and crop 

residue as feedstock for renewable fuel 

production. Second, USDA data 

indicate an overall trend of agricultural 

land contraction. These data, together 

with EPA economic modeling, suggest 

that 2007 aggregate baseline acreage 

should be sufficient to support EISA 

renewable fuel obligations and other 

foreseeable demands for crop products, 

at least in the near term, without 

clearing and cultivating additional land. 

Third, EPA believes that existing 

economic factors for feedstock 

producers favor more efficient 

utilization practices of existing 

agricultural land rather than converting 

non-agricultural lands to crop 

production. Fourth, if, at any point, EPA 

finds that the total amount of land in 

use for the production of crops 

including crops for grazing and forage is 

equal or greater than 397 million acres 

(i.e. within 5 million acres of EPA’s 

established 402 million acre baseline), 

EPA will conduct further investigations 

to evaluate whether the presumption 

built into the aggregate compliance 

approach remains valid. Lastly, EPA has 

set up a trigger mechanism that in the 

event there are more than the baseline 

amount of acres of cropland, 

pastureland and CRP land in 

production, renewable fuel producers 

will be required to meet the same 

individual or consortium-based 

recordkeeping and reporting 

requirements applicable to RINgenerating renewable fuel producers 

using other feedstocks. Taken together, 

these factors give EPA high confidence 

that the aggregate compliance approach 

for domestically grown crops and crop 

residues meets the statutory obligation 

to ensure feedstock volumes used to 

meet the renewable fuel requirements 

also comply with the definition of 

renewable biomass. 

(1) Analysis of Total Agricultural Land 

in 2007 

As described in Section II.B.4.a. 

above, EPA is defining ‘‘existing 

agricultural land’’ for purposes of the 

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8 ‘‘Producer Accuracy’’ indicates the probability 

that a groundtruth pixel will be correctly mapped 

and measures errors of omission; ‘‘User Accuracy’’ 

indicates the probability that a pixel from the 

classification actually matches the groundtruth data 

and measures errors of omission. 

EISA land use restrictions on crops and 

crop residue to include cropland, 

pastureland and CRP land that was 

cleared and actively managed or fallow 

and nonforested on the date of EISA 

enactment. To determine the aggregate 

total acreage of existing agricultural 

land for the aggregate compliance 

approach on the date of EISA 

enactment, EPA obtained from USDA 

data representing total cropland 

(including fallow cropland), 

pastureland, and CRP land in 2007 from 

three independently gathered national 

land use data sources (discussed in 

further detail below): The Farm Service 

Agency (FSA) Crop History Data, the 

USDA Census of Agriculture (2007), and 

the satellite-based USDA Crop Data 

Layer (CDL). In addition, CRP acreage is 

provided by FSA’s annually published 

‘‘Conservation Reserve Program: 

Summary and Enrollment Statistics.’’ By 

definition, the cropland, pastureland, 

and CRP land included in these data 

sources for 2007 were cleared or 

cultivated on the date of EISA 

enactment (December 19, 2007) and, 

consistent with the principles set forth 

in Section II.4.a.i, would be considered 

‘‘actively managed’’ or fallow and 

nonforested on that date. These 

categories of lands include those from 

which traditional crops, such as corn, 

soy, wheat and sorghum, would likely 

be grown. Therefore quantification of 

cropland, pastureland, and CRP land 

from these data sources represents a 

reasonable assessment of the acreage in 

the United States that is available under 

the Act for the production of crops and 

crop residues that could satisfy the 

definition of renewable biomass in 

EISA. 

Conservation Reserve Program Data. 

FSA reports CRP enrollment acreage 

each year in the publication 

‘‘Conservation Reserve Program: 

Summary and Enrollment Statistics.’’ 

The CRP program includes the general 

CRP, the Conservation Reserve 

Enhancement Program (CREP), and the 

Farmable Wetlands Program (FWP). The 

Wetlands Reserve Program (WRP) and 

Grasslands Reserve Program (GRP) are 

not under CRP and are not included in 

the total agricultural land figure in this 

rulemaking. The 2007 CRP acreage was 

36.7 million acres. This is an exact 

count of acreage within the CRP 

program in 2007. 

Farm Service Agency Crop History 

Data. The FSA maintains annual 

records of field-level land use data for 

all farms enrolled in FSA programs. 

Almost all national cropland and 

pastureland is reported through FSA 

and recorded in this data set. We used 

the ‘‘Cropland’’ category to determine 

total agricultural land. Pastureland is 

reported by farms under the category 

‘‘Cropland’’ as cropland used for grazing 

and forage under the crop type ‘‘mixed 

forage.’’ Timber land and any grazed 

native grass was removed from the 

‘‘Cropland’’ category, because these land 

types represent either forestland or 

rangeland, which are not within the 

definition of existing agricultural land. 

CRP lands and other conservation 

program lands are also reported as 

cropland. Because GRP and WRP lands 

are not within the definition of ‘‘existing 

agricultural land’’ as defined in today’s 

regulations, they were also subtracted 

from the ‘‘Cropland’’ category total. FSA 

Crop History Data show that there was 

402 million acres of agricultural land, as 

defined here, in the U.S. in 2007 (See 

Table II.B.4–1). 

TABLE II.B.4–1—TOTAL U.S. AGRICULTURAL LAND IN 2007 FROM USDA DATA SOURCES

Land category FSA crop 

history data 

Agricultural 

census data 

Cropland and Pastureland ....................................................................................................................................... 365 367 

CRP Land ................................................................................................................................................................ 37 37 

Total Land ......................................................................................................................................................... 402 404 

USDA Census of Agriculture. USDA 

conducts a full census of the U.S. 

agricultural sector once every five years. 

The data are available for the U.S., each 

of the 50 States, and for each county. 

The most recent census available is the 

2007 Census of Agriculture. For the 

purpose of this rulemaking, USDA 

provided EPA total acreage and 95% 

confidence intervals for the Census 

category ‘‘Total Cropland,’’ which 

includes the sub-categories ‘‘Harvested 

cropland,’’ ‘‘Cropland used only for 

pasture and grazing,’’ and ‘‘Other 

cropland.’’ WRP and GRP acreage are 

included in ‘‘Other cropland,’’ so, for 

purposes of this rulemaking, they were 

subtracted from the sub-category 

number (see above). The analysis 

excluded the ‘‘Permanent rangeland and 

pasture’’ category, as the pasture data 

cannot be separated from rangeland in 

this category. Total CRP acreage in 2007 

was added to ‘‘Total cropland.’’ With 

these adjustments, the Census of 

Agriculture showed 404 million acres 

(95% confidence range 401–406 million 

acres) of existing agricultural land as 

defined in today’s rule, in the U.S. in 

2007 (See Table II.B.4–1). 

Crop Data Layer. The USDA National 

Agricultural Statistics Service (NASS) 

Crop Data Layer (CDL) is a raster, georeferenced, crop-specific land cover data 

layer suitable for use in geographic 

information systems (GIS) analysis. 

Based on satellite data, the CDL has a 

ground resolution of 56 meters and was 

verified using FSA surveys. The CDL 

covers 21 major agricultural states for 

2007 and therefore cannot be used to 

determine a 2007 national aggregate 

agricultural land baseline. There will be 

full coverage of the 48 contiguous states 

for 2009, and the CDL can be used for 

analysis validation purposes during 

monitoring. From 2010 onward, it 

coverage of the 48 contiguous states will 

be dependent on available funding. GIS 

analyses of the CDL will include all 

cropland and pastureland data for each 

state. To ensure that non-pasture 

grasslands are not included in the final 

sum, all areas of the ‘‘Grassland 

herbaceous’’ category from the U.S. 

Geological National Land Cover Data 

layer (NLCD) that overlap the CDL 

layers are removed from the total 

agricultural land number. Producer and 

user accuracies 8 are available for the 

CDL crop categories. 

Primary Data Source Selection for 

Aggregate Compliance Approach. EPA 

has determined that the FSA Crop 

History Data will be used as the data set 

on which the total existing agricultural 

land baseline will be based for the 

aggregate compliance approach. The 

FSA Crop History Data is the only 

complete data set for 2007 that is 

collected annually, enabling EPA to 

monitor agricultural land expansion or 

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contraction from year to year using a 

consistent data set. The total existing 

agricultural land value derived from 

FSA Crop History Data rests within the 

95% confidence interval of the 2007 

Census of Agriculture and is only 2 

million acres less than the Census of 

Agriculture point estimate. The Census 

of Agriculture provides slightly fuller 

coverage than the FSA Crop History 

Data due to the nature of the data 

collection; however, given that both 

data collection systems have consistent 

and long-standing methodologies, the 

disparity between the two should 

remain approximately constant. 

Therefore, the FSA Crop History Data 

will provide a consistent data set for 

analyzing any expansion or contraction 

of total national agricultural land in the 

U.S. 

During its annual monitoring, EPA 

will use the FSA Crop History Data and 

the CDL analyses as a secondary source 

to validate our annual assessment. In 

years when the Census of Agriculture is 

updated, this data will also be used to 

validate our annual assessment. Other 

data sources, such as the annual NASS 

Farms, Land in Farms and Livestock 

Operations may also be useful as 

secondary data checks. Lastly, EPA 

intends to consider, as appropriate, 

other data sources for the annual 

monitoring analysis of total agricultural 

land as new technologies and data 

sources come online that would 

improve the accuracy and robustness of 

annual monitoring. 

(2) Aggregate Agricultural Land Trends 

Over Time 

The Census of Agriculture (conducted 

every five years) shows that U.S. 

agricultural land has decreased by 44 

million acres from 1997 to 2007, 

indicating an overall decade trend of 

contraction of agricultural land 

utilization despite some year-to-year 

variations that can be seen by reference 

to the annual FSA Crop History records 

(See Table II.B.4–2 and Table II.B.4–3). 

EPA’s FASOM modeling results, which 

model full EISA volumes in 2022, 

support this contraction trend, 

indicating that total cropland, 

pastureland, and CRP land in the U.S. 

in 2022, under a scenario of full 

renewable fuel volume as required by 

EISA, would be less than the 2007 

national acreage reported in the FSA 

Crop History Data (See preamble 

Section VII and RIA Chapter 5). 

TABLE II.B.4–2—TOTAL AGRICULTURAL

LAND (AS DEFINED IN SECTION

II.B.4.a) COUNTED IN THE CENSUS

OF AGRICULTURE FROM 1997–2007 

Census year Total agricultural land 

(millions of acres) 

2007 ...................... 404 

2002 * .................... 431 

1997 * .................... 445 

* 2002 data do not include farms with land in 

FWP or CREP. 

TABLE II.B.4–3—TOTAL AGRICULTURAL

LAND (AS DEFINED IN SECTION

II.B.4.a) RECORDED IN FSA CROP

HISTORY DATA FROM 2005–2007 

Year Total agricultural land 

(millions of acres) 

2007 ...................... 402 

2006 ...................... 393 

2005 ...................... 392 

(3) Aggregate Compliance Determination 

The foundation of the aggregate 

compliance approach is establishment 

of a baseline amount of eligible 

agricultural land that was cleared or 

cultivated and actively managed or 

fallow and non-forested on December 

19, 2007. Based on USDA–FSA Crop 

History Data, EPA is establishing a 

baseline of 402 million acres of U.S. 

agricultural land, as defined in Section 

II.B.4.a and based upon the methods 

described in Section II.B.4.c.iii.(1), that 

is eligible for production of planted 

crops and crop residue meeting the 

EISA definition of renewable biomass. 

EPA will monitor total U.S. agricultural 

land annually, using FSA Crop History 

Data as a primary determinant, but 

using other data sources for support 

(See Section II.4.c.iii.(1)). If, at any 

point, EPA finds that the total land in 

use for the production of crops, 

including crops for grazing and forage, 

is greater than 397 million acres (i.e. 

within 5 million acres of EPA’s 

established 402 million acre baseline), 

EPA will conduct further investigations 

to evaluate whether the presumption 

built into the aggregate compliance 

approach remains valid. Additionally, if 

EPA determines that the data indicates 

that this 2007 baseline level of eligible 

agricultural land has been exceeded, 

EPA will publish in the Federal 

Register a finding to that effect, and 

additional requirements will be 

triggered for renewable fuel producers 

to verify that they are using planted 

crops and crop residue from ‘‘existing 

agricultural land’’ as defined in today’s 

rule as their renewable fuel feedstock. 

EPA’s findings will be published by 

November 30, at the latest. If in 

November the 402 million acres 

baseline is found to be exceeded, then 

on July 1 of the following year, 

renewable fuel producers using 

feedstocks qualifying for this aggregate 

compliance approach, namely planted 

crops and crop residue from the United 

States, will be required to comply with 

the recordkeeping and reporting 

requirements applicable to producers 

using other types of renewable biomass, 

as described in the previous sections. 

This includes the option that fuel 

producers could utilize a third-party 

consortium to demonstrate compliance. 

EPA acknowledges that it is possible 

that under this approach some of the 

land available under EISA for crop 

production on the date of EISA 

enactment could be retired and other 

land brought into production, without 

altering the assessment of the aggregate 

amount of cropland, pastureland and 

CRP land. Under EISA, crops or crop 

residues from the new lands would not 

qualify as renewable biomass. However, 

EPA expects such shifts in acreage to be 

de minimus, as long as the total 

aggregate amount of agricultural land 

does not exceed the 2007 national 

aggregate baseline. EPA expects that 

new lands are unlikely to be cleared for 

agricultural purposes for two reasons. 

First, it can be assumed that most 

undeveloped land that was not used as 

agricultural land in 2007 is generally 

not suitable for agricultural purposes 

and would serve only marginally well 

for production of renewable fuel 

feedstocks. Due to the high costs and 

significant inputs that would be 

required to make the non-agricultural 

land suitable for agricultural purposes, 

it is highly unlikely that farmers will 

undertake the effort to ‘‘shift’’ land that 

is currently non-agricultural into 

agricultural use. Second, crop yields are 

projected to increase, reducing the need 

for farmers to clear new land for 

agricultural purposes. We believe that 

this effect is reflected in the overall 

trend, discussed earlier, of an overall 

contraction in agricultural land acreage 

over time. 

If EPA determines that the baseline is 

exceeded, and that individual 

compliance with the renewable biomass 

reporting and recordkeeping 

requirements is triggered, renewable 

fuel producers using crops and crop 

residue as a feedstock for renewable fuel 

would become responsible, beginning 

July 1 of the following year, for meeting 

individual recordkeeping and reporting 

requirements related to renewable 

biomass verification. These 

requirements are identical to those that 

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14704 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

apply to producers using other types of 

renewable biomass feedstocks, such as 

planted trees from tree plantations, as 

described in the previous sections. 

Renewable fuel producers generating 

RINs under the RFS2 program would 

continue to be required to affirm 

(through EMTS—EPA Moderated 

Transaction System) for each batch of 

renewable fuel that their feedstocks 

meet the definition of renewable 

biomass. Additionally, producers would 

send a quarterly report to EPA that 

includes a summary of the types and 

volumes of feedstocks used throughout 

the quarter, as well as electronic data or 

maps identifying the land from which 

those feedstocks were harvested. 

Furthermore, those RIN-generating 

renewable fuel producers will be 

required to obtain and maintain in their 

files written records from their 

feedstock suppliers for each feedstock 

purchase that identify where the 

feedstocks were produced and that are 

sufficient to verify that the feedstocks 

qualify as renewable biomass. This 

includes maps and/or electronic data 

identifying the boundaries of the land 

where the feedstock was produced, 

PTDs or bills of lading tracing the 

feedstock from that land to the 

renewable fuel production facility, and 

other written records that serve as 

evidence that the feedstock qualifies as 

renewable biomass. Finally, producers 

using planted crops and crop residue 

must maintain additional 

documentation that serves as evidence 

that the agricultural land used to 

produce the crop or crop residue was 

cleared or cultivated and actively 

managed or fallow, and nonforested on 

December 19, 2007. This documentation 

must consist of the following types of 

records which must be traced to the 

land in question: sales records for 

planted crops, crop residue, or 

livestock, purchasing records for land 

treatments such as fertilizer, weed 

control, or reseeding or a written 

agricultural management plan or 

documentation of participation in an 

agricultural program sponsored by a 

Federal, State or local government 

agency. 

Alternatively, if the baseline is 

exceeded and the requirements are 

triggered for individual producer 

verification that their feedstocks are 

renewable biomass renewable fuel 

producers may choose to work with 

other renewable fuel producers as well 

as feedstock producers and suppliers to 

develop a quality assurance program for 

the renewable fuel production supply 

chain. This quality assurance program 

would take the place of individual 

accounting and would consist of an 

independent third party qualityassurance survey of all participating 

renewable fuel producers and their 

feedstock suppliers, completed in 

accordance with an industry-developed, 

EPA-approved plan, to ensure that they 

are utilizing feedstocks that meet the 

definition of renewable biomass. An indepth discussion of this industry survey 

option is included in the previous 

section. 

While the aggregate compliance 

approach is appropriate for planted 

crops and crop residues from 

agricultural land in the United States, 

due in part to certain additional or 

different constraints imposed by EISA, 

the aggregate approach cannot be 

applied, at this time, to the other types 

of renewable biomass. Renewable fuel 

producers utilizing these types of 

renewable biomass, including planted 

trees and tree residues from tree 

plantations, slash and pre-commercial 

thinnings from non-federal forestland, 

animal waste, separated yard and food 

waste, etc., will be subject to the 

individual reporting and recordkeeping 

requirements discussed in the previous 

section. 

Additionally, EPA is not finalizing the 

aggregate compliance approach for 

foreign producers of renewable fuel. 

EPA does not, at this time, have 

sufficient data to make a finding that 

non-domestically grown crops and crop 

residues used in renewable fuel 

production satisfy the definition of 

renewable biomass. Nevertheless, if, in 

the future, adequate land use data 

becomes available to make a finding 

that, in the aggregate, crops and crop 

residues used in renewable fuel 

production in a particular country 

satisfy the definition of renewable 

biomass, EPA is willing to consider an 

aggregate compliance approach for 

renewable biomass on a country by 

country basis, in lieu of the individual 

recordkeeping and reporting 

requirements. 

d. Treatment of Municipal Solid Waste 

(MSW) 

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.’’ 

We solicited 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. On the other hand, we noted 

that EISA does not define the term 

‘‘separated,’’ and so does not specify the 

degree of separation required. We also 

noted that there was some evidence in 

the Act that Congress did not intend to 

exclude MSW entirely from the 

definition of renewable biomass. The 

definition of ‘‘advanced biofuel’’ 

includes a list of fuels that are ‘‘eligible 

for consideration’’ as advanced biofuel, 

including ‘‘ethanol derived from waste 

material’’ and biogas ‘‘including landfill 

gas.’’ 

As an initial matter, we note that 

some materials clearly fall within the 

definition of ‘‘separated yard or food 

waste.’’ The statute itself identifies 

‘‘recycled cooking and trap grease’’ as 

one example of separated food waste. 

An example of separated yard waste is 

the leaf waste that many municipalities 

pick up at curbside and keep separate 

from other components of MSW for 

mulching or other uses. However, a 

large quantity of food and yard waste is 

disposed of together with other 

household waste as part of MSW. EPA 

estimates that about 120 million tons of 

MSW are disposed of annually much of 

it inextricably mixed with yard and 

especially food waste. This material 

offers a potentially reliable, abundant 

and inexpensive source of feedstock for 

renewable fuel production which, if 

used, could reduce the volume of 

discarded materials sent to landfills and 

could help achieve both the GHG 

emissions reductions and energy 

independence goals of EISA. Thus, EPA 

believes we should consider under what 

conditions yard and food waste that is 

present in MSW can be deemed 

sufficiently separated from other 

materials to qualify as renewable 

biomass. 

One commenter stated that it is clear 

that MSW does not qualify as renewable 

biomass under EISA, since the 2005 

Energy Policy Act explicitly allowed for 

qualifying renewable fuel to be made 

from MSW, and EISA has no mention of 

it. Commenters from the renewable fuel 

industry generally favored maximum 

flexibility for the use of MSW in 

producing qualifying fuels under EISA, 

offering a variety of arguments based on 

the statutory text and reasons why it 

would benefit the environment and the 

nation’s energy policy to do so. They 

favored either (1) a determination that 

unsorted MSW can be used as a 

feedstock for advanced biofuel even if it 

does not meet the definition of 

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renewable biomass, (2) that the Act be 

interpreted to include MSW as 

renewable biomass, or (3) that MSW 

from which varying amounts of 

recyclable materials have been removed 

could qualify as renewable biomass. A 

consortium of ten environmental groups 

said that for EISA volume mandates to 

be met, it is important to take advantage 

of biomass resources from urban wastes 

that would otherwise be landfilled. 

They urged that post-recycling residues 

(i.e., those wastes that are left over at 

material recovery facilities after 

separation and recycling) would fit 

within the letter and spirit of the 

definition of renewable biomass. 

EPA does not believe that the statute 

can be reasonably interpreted to allow 

advanced biofuel to be made from 

material that does not meet the 

definition of renewable biomass as 

suggested in the first approach. The 

definition of advanced biofuel specifies 

that it is a form of ‘‘renewable fuel,’’ and 

renewable fuel is defined in the statute 

as fuel that is made from renewable 

biomass. While the definition of 

advanced biofuel includes a list of 

materials that ‘‘may’’ be ‘‘eligible for 

consideration’’ as advanced biofuel, and 

that list includes ‘‘ethanol derived from 

waste materials’’ and biogas ‘‘including 

landfill gas,’’ the fact that the specified 

items are ‘‘eligible for consideration’’ 

indicates that they do not necessarily 

qualify but must meet the definitional 

requirements—being ‘‘renewable fuel’’ 

made from renewable biomass and 

having life cycle greenhouse gas 

emissions that are at least 50% less than 

baseline fuel. There is nothing in the 

statute to suggest that Congress used the 

term ‘‘renewable fuel’’ in the definition 

of ‘‘advanced biofuel’’ to have a different 

meaning than the definition provided in 

the statute. The result of the 

commenter’s first approach would be 

that general renewable fuel and 

cellulosic biofuel would be required to 

be made from renewable biomass 

because the definitions of those terms 

specifically refer to renewable biomass, 

whereas advanced biofuel and biomassbased diesel would not, because their 

definitions refer to ‘‘renewable fuel’’ 

rather than ‘‘renewable biomass.’’ EPA 

can discern no basis for such a 

distinction. EPA believes that the Act as 

a whole is best interpreted as requiring 

all types of qualifying renewable fuels 

under EISA to be made from renewable 

biomass. In this manner the land and 

feedstock restrictions that Congress 

deemed important in the context of 

biofuel production apply to all types of 

renewable fuels. 

EPA also does not agree with the 

commenter who suggested that the 

listing in the definition of renewable 

biomass of ‘‘biomass obtained from the 

immediate vicinity of buildings and 

other areas regularly occupied by 

people, or of public infrastructure, at 

risk from wildfire’’ should be interpreted 

to include MSW. It is clear that the term 

‘‘at risk of wildfire’’ modifies the entire 

sentence, and the purpose of the listing 

is to make the biomass that is removed 

in wildfire minimization efforts, such as 

brush and dead woody material, 

available for renewable fuel production. 

Such material does not typically include 

MSW. Had Congress intended to 

include MSW in the definition of 

renewable biomass, EPA believes it 

would have clearly done so, in a manner 

similar to the approach taken in EPAct. 

EPA also does not believe that it 

would be reasonable to interpret the 

reference to ‘‘separated yard or food 

waste’’ to include unsorted MSW. 

Although MSW contains yard and food 

waste, such an approach would not give 

meaning to the word ‘‘separated.’’ 

We do believe, however, that yard and 

food wastes that are part of MSW, and 

are separated from it, should qualify as 

renewable biomass. MSW is the logical 

source from which yard waste and food 

waste can be separated. As to the degree 

of separation required, some 

commenters suggested a simple ‘‘post 

recycling’’ test be appropriate. They 

would leave to municipalities and waste 

handlers a determination of how much 

waste should be recycled before the 

residue was used as a feedstock for 

renewable fuel production. EPA 

believes that such an approach would 

not guarantee sufficient ‘‘separation’’ 

from MSW of materials that are not yard 

waste or food waste to give meaning to 

the statutory text. Instead, EPA believes 

it would be reasonable in the MSW 

context to interpret the word 

‘‘separated’’ in the term ‘‘separated yard 

or food waste’’ to refer to the degree of 

separation to the extent that is 

reasonably practicable. A large amount 

of material can be, and is, removed from 

MSW and sold to companies that will 

recycle the material. EPA believes that 

the residues remaining after reasonably 

practicable efforts to remove recyclable 

materials other than food and yard 

waste (including paper, cardboard, 

plastic, textiles, metal and glass) from 

MSW should qualify as separated yard 

and food waste. This MSW-derived 

residue would likely include some 

amount of residual non-recyclable 

plastic and rubber of fossil fuel origin, 

much of it being wrapping and 

packaging material for food. Since this 

material cannot be practicably separated 

from the remaining food and yard waste, 

EPA believes it is incidental material 

that is impractical to remove and 

therefore appropriate to include in the 

category of separated food and yard 

waste. In sum, EPA believes that the 

biogenic portion of the residue 

remaining after paper, cardboard, 

plastic, textiles metal and glass have 

been removed for recycling should 

qualify as renewable biomass. This 

interpretation is consistent with the text 

of the statute, and will promote the 

productive use of materials that would 

otherwise be landfilled. It will also 

further the goals of EISA in promoting 

energy independence and the reduction 

of GHG emissions from transportation 

fuels. 

EPA notes there are a variety of 

recycling methods that can be used, 

including curbside recycling programs, 

as well as separation and sorting at a 

material recovery facility (MRF). For the 

latter, the sorting could be done by hand 

or by automated equipment, or by a 

combination of the two. Sorting by hand 

is very labor intensive and much 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. 

Separation via MRFs is generally very 

efficient and can provide comparable if 

not better removal of recyclables to that 

achieved by curbside recycling. 

Based on this analysis, today’s rule 

provides that those MSW-derived 

residues that remain after reasonably 

practicable separation of recyclable 

materials other than food and yard 

waste is renewable biomass. What 

remains to be addressed is what 

regulatory mechanisms should be used 

to ensure the appropriate generation of 

RINs when separated yard and food 

waste is used as a feedstock. We are 

finalizing two methods. 

The first method would apply 

primarily to a small subset of producers 

who are able to obtain yard and/or food 

wastes that have been kept separate 

since waste generation from the MSW 

waste stream. Examples of such wastes 

are lawn and leaf waste that have never 

entered the general MSW waste stream. 

Typically, such wastes contain 

incidental amounts of materials such as 

the plastic twine used to bind twigs 

together, food wrappers, and other 

extraneous materials. As with our 

general approach to the presence of 

incidental, de minimus contaminants in 

feedstocks that are unintentionally 

present and impractical to remove, the 

presence of such material in separated 

yard or food waste will not disqualify 

such wastes as renewable biomass, and 

the contaminants may be disregarded by 

producers and importers generating 

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RINs. (See definition of renewable 

biomass and 80.1426(f)(1).) Waste 

streams kept separate since generation 

from MSW that consist of yard waste are 

expected to be composed almost 

entirely of woody material or leaves, 

and therefore will be deemed to be 

composed of cellulosic materials. Waste 

streams consisting of food wastes, 

however, may contain both cellulosic 

and non-cellulosic materials. For 

example, a food processing plant may 

generate both wastes that are primarily 

starches and sugars (such as carrot and 

potato peelings, as well as fruits and 

vegetables that are discarded) as well as 

corn cobs and other materials that are 

cellulosic. We will deem waste streams 

consisting of food waste to be composed 

entirely of non-cellulosic materials, and 

qualifying as advanced biofuels, unless 

the producer demonstrates that some 

portion of the food waste is cellulosic. 

The cellulosic portion would then 

qualify as cellulosic biofuel. The 

method for quantifying the cellulosic 

and non-cellulosic portions of the food 

waste stream is to be described in a 

written plan which must be submitted 

to EPA under the registration 

procedures in 80.1450(b)(vii) for 

approval and which indicates the 

location of the facility from which 

wastes are obtained, how identification 

and quantification of waste material is 

to be accomplished, and evidence that 

the wastes qualify as fully separated 

yard or food wastes. The producer must 

also maintain records regarding the 

source of the feedstock and the amounts 

obtained. 

The second method would involve 

use as feedstock by a renewable fuel 

producer of the portion of MSW 

remaining after reasonably practical 

separation activities to remove 

recyclable materials, resulting in a 

separated MSW-derived residue that 

qualifies as separated yard and food 

waste. Today’s rule requires that parties 

that intend to use MSW-derived residue 

as a feedstock for RIN-generating 

renewable fuel production ensure that 

reasonably practical efforts are made to 

separate recyclable paper, cardboard, 

textiles, plastics, metal and glass from 

the MSW, according to a plan that is 

submitted by the renewable fuel 

producer and approved by EPA under 

the registration procedures in 

80.1450(b)(viii). In determining whether 

the plan submittals provide for 

reasonably practicable separation of 

recyclables EPA will consider: (1) The 

extent and nature of recycling that may 

have occurred prior to receipt of the 

MSW material by the renewable fuel 

producer, (2) available recycling 

technology and practices, and (3) the 

technology or practices selected by the 

fuel producer, including an explanation 

for such selection and reasons why 

other technologies or practices were not 

selected. EPA asks that any CBI 

accompanying a plan or a party’s 

justification for a plan be segregated 

from the non-CBI portions of the 

submissions, so as to facilitate 

disclosure of the non-CBI portion of 

plan submittals, and approved plans, to 

interested members of the public. 

Producers using this second option, 

will need to determine what RINs to 

assign to a fuel that is derived from a 

variety of materials, including yard 

waste (largely cellulosic) and food waste 

(largely starches and sugar), as well as 

incidental materials remaining after 

reasonably practical separation efforts 

such as plastic and rubber of fossil 

origin. EPA has not yet evaluated the 

lifecycle greenhouse gas performance of 

fuel made from such mixed sources of 

waste, so is unable at this time to assign 

a D code for such fuel. However, if a 

producer uses ASTM test method 

D–6866 on the fuel made from MSWderived feedstock, it can determine 

what portion of the rule is of fossil and 

non-fossil origin. The non-fossil portion 

of the fuel will likely be largely derived 

from cellulosic materials (yard waste, 

textiles, paper, and construction 

materials), and to a much smaller extent 

starch-based materials (food wastes). 

Unfortunately, EPA is not aware of a test 

method that is able to distinguish 

between cellulosic- and starch-derived 

renewable fuel. Under these 

circumstances, EPA believes that it is 

appropriate for producers to base RIN 

assignment on the predominant 

component and, therefore, to assume 

that the biogenic portion of their fuel is 

entirely of cellulosic origin. The nonbiogenic portion of the fuel, however, 

would not qualify for RINs at this time. 

Thus, in sum, we are providing via the 

ASTM testing method an opportunity 

for producers using an MSW-derived 

feedstock to generate RINs only for the 

biogenic portion of their renewable fuel. 

There is no D code for the remaining 

fossil-derived fraction of the fuel in 

today’s rule nor for the entire volume of 

renewable fuel produced when using 

MSW-derived residue as a feedstock. 

The petition process for assigning such 

codes in today’s rule can be used for 

such purpose. 

Procedures for the use of ASTM 

Method D–6866 are detailed in 40 CFR 

80.1426(f)(9) of today’s rule. We 

solicited comment on this method, and 

while the context of the discussion of 

method D–6866 was with respect to 

using it for gasoline (see 74 FR 24951), 

the comments we received provided us 

information on the method itself. Also, 

commenters were supportive of its use. 

Fuel producers must either run the 

ASTM D–6866 method for each batch of 

fuel produced, or run it on composite 

samples of the food and yard wastederived fuel derived from post-recycling 

MSW residues. Producers will be 

required at a minimum to take samples 

of every batch of fuel produced over the 

course of one month and combine them 

into a single composite sample. The 

D–6866 test would then be applied to 

the composite sample, and the resulting 

non-fossil derived fraction will be 

deemed cellulosic biofuel, and applied 

to all batches of fuel produced in the 

next month to determine the 

appropriate number of RINs that must 

be generated. The producer would be 

required to recalculate this fraction at 

least monthly. For the first month, the 

producer can estimate the non-fossil 

fraction, and then make a correction as 

needed in the second month. (The 

procedure using the ASTM D–6866 

method applies not only to the wastederived fuel discussed here but also to 

all partially renewable transportation 

fuels, and is discussed in further detail 

in Section II.D.4. See also the 

regulations at § 80.1426(f)(4)). 

The procedures for assigning D codes 

to the fuel produced from such wastes 

are discussed in further detail in Section 

II.D.5. 

One commenter suggested that biogas 

from landfills should be treated in the 

same manner as renewable fuel 

produced from MSW. EPA agrees with 

the commenter to a certain extent. The 

definition of ‘‘advanced biofuels’’ in 

EISA identifies ‘‘Biogas (including 

landfill gas and sewage waste treatment 

gas) produced through the conversion of 

organic matter from renewable biomass’’ 

as ‘‘eligible for consideration’’ as an 

advanced biofuel. However, as with 

MSW, the statute requires that advanced 

biofuel be a ‘‘renewable fuel’’ and that 

such fuel be made from ‘‘renewable 

biomass.’’ The closest reference within 

the definition of renewable biomass to 

landfill material is ‘‘separated yard or 

food waste.’’ However, in applying the 

interpretation of ‘‘separated’’ yard and 

food waste described above for MSW to 

landfill material, we come to a different 

result. Landfill material has by design 

been put out of practical human reach. 

It has been disposed of in locations, and 

in a manner, that is designed to be 

permanent. For example, modern 

landfills are placed over impermeable 

liners and sealed with a permanent cap. 

In addition, the food and yard waste 

present in a landfill has over time 

become intermingled with other 

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9 Kaplan, et al. (2009). ‘‘Is it Better to Burn or Bury 

Waste for Clean Electricity Generation?’’ 

Environmental Science & Technology 2009 43(6), 

1711–1717 (Found in Table S1 of supplemental 

material to the article, at http://pubs.acs.org/doi/ 

suppl/10.1021/es802395e/suppl_file/ 

es802395e_si_001.pdf). 

materials to an extraordinary extent. 

This occurs in the process of waste 

collection, shipment, and disposal, and 

subsequently through waste decay, 

leaching and movement within the 

landfill. Additionally, we note that the 

process of biogas formation in a landfill 

provides some element of separation, in 

that it is formed only from the biogenic 

components of landfill material, 

including but not strictly limited to food 

and yard waste. Thus, plastics, metal 

and glass are effectively ‘‘separated’’ out 

through the process of biogas formation. 

As a result of the intermixing of wastes, 

the fact that biogas is formed only from 

the biogenic portion of landfill material, 

and the fact that landfill material is as 

a practical matter inaccessible for 

further separation, EPA believes that no 

further practical separation is possible 

for landfill material and biogas should 

be considered as produced from 

separated yard and food waste for 

purposes of EISA. Therefore, all biogas 

from landfills is eligible for RIN 

generation. 

We have considered whether to 

require biogas producers to use ASTM 

Method D–6866 to identify the biogenic 

versus non-biogenic fractions of the 

fuel. However, as noted above, biogas is 

not formed from non-biogenic 

compounds in landfills. (Kaplan, et al., 

2009) 9 Thus, no purpose would be 

solved in using the ASTM method in 

the biogas context. 

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 

revising the registration process for 

renewable fuel producers and importers. 

Under the 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 RFS1 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 and 3520– 

20B (Gasoline Programs Facility 

Registration) or 3520–20B1 (Diesel 

Programs Facility Registration), which 

require 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 was 

not required for most producers or 

importers to generate RINs under RFS1 

(producers of cellulosic biomass ethanol 

and waste-derived ethanol are the 

exception to this). 

Additionally, EPA recommends 

companies register their renewable fuels 

or fuel additives under title 40 CFR part 

79 as a motor vehicle fuel. In fact, 

renewable fuels intended for use in 

motor vehicles will be required to be 

registered under title 40 CFR part 79 

prior to any introduction into 

commerce. Manufacturers and 

subsequent parties of fuels and fuel 

additives not registered under part 79 

will be liable for separate penalties 

under 40 CFR parts 79 and 80 in the 

event their unregistered product is 

introduced into commerce for use in a 

motor vehicle. Further if a registered 

fuel or fuel additive is used in manner 

that is not consistent with their 

product’s registration under part 79 the 

manufacturer and subsequent parties 

will be liable for penalties under parts 

79 and 80. 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 and the RINs generated for fuel 

produced from nonrenewable sources 

will be invalidated. 

Due to the revised definitions of 

renewable fuel under EISA, we 

proposed to expand the registration 

process for renewable fuel producers 

and importers in order to implement the 

new program effectively. We received a 

number of comments that opposed the 

expanded registration as commenters 

deemed it overly burdensome, costly 

and unnecessary. However, EPA is 

finalizing the proposed expanded 

registration requirements for the 

following reasons. The information to be 

collected through the expanded 

registration process is essential to 

generating and assigning a certain 

category of RIN to a volume of fuel. 

Additionally, the information collected 

is essential to determining 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. Therefore, we are requiring 

producers, including foreign producers, 

and importers that generate RINs to 

provide us with information on their 

feedstocks, facilities, and products, in 

order to implement and enforce the 

program and have confidence that 

producers and importers are properly 

categorizing their fuel and generating 

RINs. The registration procedures will 

be integrated with the new EPA 

Moderated Transaction System, 

discussed in detail in Section III.A of 

this preamble. 

1. Domestic Renewable Fuel Producers 

Information on products, feedstocks, 

and facilities contained in a producer’s 

registration will 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. In 

addition, producers of renewable fuel 

from facilities that qualify for the 

exemption from the 20% GHG reduction 

threshold (as discussed in Section 

II.B.3) must provide information that 

demonstrates when the facility 

commenced construction, and that 

establishes the baseline volume of the 

fuel. For those facilities that would 

qualify as grandfathered but are not in 

operation we are allowing until May 1, 

2013 to submit and receive approval for 

a complete facility registration. This 

provision does not require actual fuel 

production, but simply the filing of 

registration materials that assert a claim 

for exempt status. It will benefit both 

fuel producers, who will likely be able 

to more readily collect the required 

information if it is done promptly, and 

EPA enforcement personnel seeking to 

verify the information. However, given 

the potentially significant implications 

of this requirement for facilities that 

may qualify for the exemption but miss 

the registration deadline, the rule also 

provides that EPA may waive the 

requirement if it determines that the 

submission is verifiable to the same 

extent as a timely-submitted 

registration. 

With respect to products, we are 

requiring that producers provide 

information on the types of renewable 

fuel and co-products that a facility is 

capable of producing. With respect to 

feedstocks, we are requiring producers 

to provide to EPA a list of all the 

different feedstocks that a renewable 

fuel producer’s facility is likely to use 

to convert into renewable fuel. With 

respect to the producer’s facilities, two 

types of information must be reported to 

the Agency. First, producers must 

describe 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 

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thus deemed to be in compliance with 

the 20% GHG threshold, we are 

requiring evidence and certification of 

the facility’s qualification under the 

definition of ‘‘commence construction’’ 

as well as information necessary to 

establish its renewable fuel baseline 

volume per the requirement outlined in 

Section II.B.3 of this preamble. 

EPA proposed to require that 

renewable fuel producers have a thirdparty engineering review of their 

facilities prior to generating RINs under 

RFS2, and every 3 years thereafter. EPA 

received comments that the on-site 

engineering review was overly 

burdensome, unnecessary and costly. A 

number of commenters noted that the 

time allotted for conducting the reviews, 

between the rule’s publication and prior 

to RIN generation, is not adequate for 

producers to hire an engineer and 

conduct the review for all of their 

facilities. Several commenters requested 

that on-site licensed engineers be 

allowed to conduct any necessary 

facility reviews. 

EPA is finalizing the proposed 

requirement for an on-site engineering 

review of facilities producing renewable 

fuel due to the variability of production 

facilities, the increase in the number of 

categories of renewable fuels, and the 

importance of ensuring that RINs are 

generated in the correct category. 

Without these engineering reviews, we 

do not believe it would be possible to 

implement the RFS2 program in a 

manner that ensured the requirements 

of EISA were being fulfilled. 

Additionally, the engineering review 

provides a check against fraudulent RIN 

generation. In order to establish the 

proper basis for RIN generation, we are 

requiring that every renewable fuel 

producer have the on-site engineering 

review of their facility performed in 

conjunction with his or her initial 

registration for the new RFS program. 

The engineering reviews must be 

conducted by independent third parties 

who can maintain impartiality and 

objectivity in evaluating the facilities 

and their processes. Additionally, the 

on-site engineering review must be 

conducted every three years thereafter 

to verify that the fuel pathways 

established in the initial registration are 

still applicable. These requirements 

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 needs to be performed within 60 

days of the registration update. Finally, 

producers are required to submit a copy 

of their independent engineering review 

to EPA, for verification and enforcement 

purposes. 

2. Foreign Renewable Fuel Producers 

Under RFS1, foreign renewable fuel 

producers of cellulosic biomass ethanol 

and waste-derived ethanol may apply to 

EPA to generate RINs for their own fuel. 

For RFS2, we proposed that foreign 

producers of renewable fuel 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 apply to all foreign 

renewable fuel producers who plan to 

export their products to the U.S. as part 

of the RFS2 program, whether the 

foreign producer generates RINs for 

their fuel or an importer does. 

Foreign producers, like domestic 

producers, must also undergo an 

independent engineering review of their 

facilities, conducted by an independent 

third party who is a licensed 

professional engineer (P.E.), or foreign 

equivalent who works in the chemical 

engineering field. The independent 

third party must provide to EPA 

documentation of his or her 

qualifications as part of the engineering 

review, including proof of appropriate 

P.E. license or foreign equivalent. The 

third-party engineering review must be 

conducted by both foreign producers 

who plan to generate RINs and those 

that don’t generate RINs but anticipate 

their fuel will be exported to the United 

States by an importer who will generate 

the RINs. 

3. Renewable Fuel Importers 

We are requiring importers who 

generate RINs for imported fuel that 

they receive without RINs may only do 

so under certain circumstances. If an 

importer receives fuel without RINs, the 

importer may only generate RINs for 

that fuel if they can verify the fuel 

pathway and that feedstocks use meet 

the definition of renewable biomass. An 

importer must rely on his supplier, a 

foreign renewable fuel producer, to 

provide documentation to support any 

claims for their decision 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 and must have had 

a third-party engineering review 

conducted, as noted above, in order for 

EPA to be able to verify that the 

renewable biomass and GHG reduction 

requirements of EISA are being fulfilled. 

Section II.D.2.b describes the RIN 

generating restrictions and requirements 

for importers under RFS2. 

4. Process and Timing 

We are making forms for expanded 

registration for renewable fuel 

producers and importers, as well as 

forms for registration of other regulated 

parties, available electronically with the 

publication of this final rule. Paper 

registration forms will only be accepted 

in exceptional cases. Registration forms 

must be submitted and accepted by the 

EPA by July 1, 2010, or 60 days prior to 

a producer producing or importer 

importing any renewable fuel, 

whichever dates come later. If a 

producer changes its fuel pathway 

(feedstock, production process, or fuel 

type) to not listed in his registration 

information on file with EPA but the 

change will not incur a change of RIN 

category for the fuel (i.e., a change in the 

appropriate D code), the producer must 

update his registration information 

within seven (7) days of the change. 

However, if the fuel producer changes 

its fuel pathway in a manner that would 

result in a change in its RIN category 

(and thus a new D code), 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. If EPA finds that these 

deadlines and requirements have not 

been met, or that a facility’s registered 

profile, dictated by the various 

parameters for product, process and 

feedstock, does not reflect actual 

products produced, processes 

employed, or feedstocks used, then EPA 

reserves the right to void, ab initio, any 

affected RINs generated and may impose 

significant penalties. For example a 

newly registered (i.e. not grandfathered) 

ethanol production facility claims in 

their registration that they qualify to 

generate RINs based upon the use of two 

advanced engineering practices (1) corn 

oil fractionation and (2) production of 

wet DGS co-product that is, at a 

minimum, 35% of its total DGS 

produced annually. However, during an 

audit of the producer’s records, it is 

found that of all their DGS produced, 

less than 15% was wet. In this example, 

the producer has committed a violation 

that results in the disqualification of 

their eligibility to generate RINs; that is, 

they no longer have an eligible pathway 

that demonstrates qualification with the 

20% GHG threshold requirement for 

corn ethanol producers. As such any 

and all RINs produced may be deemed 

invalid and the producer may be subject 

to Clean Air Act penalties. 

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The required independent 

engineering review as discussed above 

for domestic and foreign renewable fuel 

producers is an integral part of the 

registration process. The agency 

recognizes, through comments received, 

that there are significant concerns 

involving timing necessary and ability 

to produce a completed engineering 

review to satisfy registration 

requirements. Since the publication of 

the RFS2 NPRM, we have delivered 

consistently a message stating that 

advanced planning and preparation was 

necessary from all parties, EPA and the 

regulated community inclusive, for 

successful implementation of this 

program. In an effort to reduce demand 

on engineering resources, we are 

allowing grandfathered facilities an 

additional six months to submit their 

engineering review. This will direct the 

focus of engineering review resources 

on producers of advanced, cellulosic 

and biomass based diesel. EPA fully 

expects these producers of advanced 

renewable fuels to meet the engineering 

review requirement; however, if they are 

having difficulties producing engineer’s 

reports prior to April 1, we ask that they 

contact us. 

D. Generation of RINs 

Under RFS2, each RIN will 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. 

Other aspects of the generation of RINs, 

such as the definition of a batch, as well 

as the assignment of RINs to batches, 

will remain unchanged from the RFS1 

requirements. We received several 

comments regarding the method for 

calculating temperature standardization 

of biodiesel and address this issue in 

Section III.G. 

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 the sections 

of EPAct that provided extra credit for 

cellulosic and waste-derived renewable 

fuels, and the direction that EPA 

establish ‘‘appropriate’’ credit for 

biodiesel and renewable fuel volumes in 

excess of the mandated volumes. 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. EPA stated that these 

provisions indicated that Congress did 

not intend to restrict EPA discretion in 

implementing the program to utilizing a 

straight volume measurement of gallons. 

See 72 FR 23918–23920, and 71 FR 

55570–55571. The result was an 

Equivalence Value for ethanol of 1.0, for 

butanol of 1.3, for biodiesel (mono alkyl 

ester) of 1.5, and for non-ester 

renewable diesel of 1.7. 

In the NPRM we noted that EISA 

made a number of changes to CAA 

section 211(o) that impacted our 

consideration of Equivalence Values in 

the context of the RFS2 program. For 

instance, EISA eliminated the 2.5-to-1 

credit for cellulosic biomass ethanol and 

waste-derived ethanol and replaced this 

provision with large mandated volumes 

of cellulosic biofuel and advanced 

biofuels. 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 of these new 

requirements, we indicated that there 

may no longer be a need for additional 

incentives for certain fuels in the form 

of Equivalence Values greater than 1.0. 

In the NPRM we co-proposed and 

took 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, with the addition that biomassbased diesel standard would be based 

on energy content in comparison to 

biodiesel. 

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). 

In response to the NPRM, some 

stakeholders pointed to the 

aforementioned changes brought about 

by EISA as support for a straight volume 

approach to Equivalence Values, and 

argued that it had always been the 

intent of Congress that the statutory 

volume mandates be treated as straight 

volumes. Stakeholders taking this 

position were generally producers of 

corn ethanol. However, a broad group of 

other stakeholders including refiners, 

biodiesel producers, a broad group of 

advanced biofuel producers, fuel 

distributor and States indicated that the 

first option for an energy-based 

approach to Equivalence Values was 

both supported by the statute and 

necessary to provide for equitable 

treatment of advanced biofuels. They 

noted that EISA did not change certain 

of the statutory provisions EPA 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 direct EPA 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. Had Congress 

intended to change these provisions 

they could have easily done so. 

Moreover, some stakeholders 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 does not obviate 

the value of standardizing for energy 

content, which provides a level playing 

field under RFS1 for various types of 

renewable fuels based on energy 

content. 

Some stakeholders who supported an 

energy-based approach to Equivalence 

Values also argued 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. 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 80 gallons of ethanol (and 

another 14 gal of other alcohols) or 50 

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10Another 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. 

11 Value is lower than 98% because it is based on 

energy content of denaturant versus ethanol, not 

relative volume. 

gallons of diesel fuel (and naphtha).10 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 their 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. Since the 

technologies for producing more energydense fuels such as cellulosic diesel are 

still in the early stages of development, 

they may benefit from not having to 

overcome the disincentive in the form of 

the same Equivalence Value based on 

straight volume. 

Based on our interpretation of EISA as 

allowing the use of energy-based 

Equivalence Values, and because we 

believe it provides a level playing field 

for the development of different fuels 

that can displace the use of fossil fuels, 

and that this approach therefore furthers 

the energy independence goals of EISA, 

we are finalizing the energy-based 

approach to Equivalence Values in 

today’s action. We also note that a large 

number of companies have already 

made investments based on the 

decisions made for RFS1, and using 

energy-based Equivalence Values will 

maintain consistency with RFS1 and 

ease the transition into RFS2. Insofar as 

renewable fuels with volumetric energy 

contents higher than ethanol are used, 

the actual volumes of renewable fuel 

that are necessary to meet the EISA 

volume mandates will be smaller than 

those shown in Table I.A.1–1. The 

impact on the physical volume will 

depend on actual volumes of various 

advanced biofuels produced in the 

future. The main scenario modeled for 

this final rule includes a forecast for 

considerable volumes of relatively high 

energy diesel fuel made from renewable 

biomass, and still results in a physical 

volume mandate of 30.5 billion gallons. 

The energy-based approach results in 

the advanced biofuel standard being 

automatically met during the first few 

years of the program. For instance, the 

biomass-based diesel mandated volume 

for 2010 is 0.65 billion gallons, which 

will be treated as 0.975 billion gallons 

(1.5 × 0.65) in the context of meeting the 

advanced biofuel standard. Since the 

mandated volume for advanced biofuel 

in 2010 is 0.95 billion gallons, this 

requirement is automatically met by 

compliance with the biomass-based 

diesel standard. 

Although we are finalizing an energybased approach to Equivalence Values, 

we believe that Congress intended the 

biomass-based diesel volume mandate 

to be treated as diesel volumes rather 

than as ethanol-equivalent volumes. 

Since all RINs are generated based on 

energy equivalency to ethanol, to 

accomplish this, we have modified the 

formula for calculating the standard for 

biomass-based diesel to compensate 

such that one physical gallon of 

biomass-based diesel will count as one 

gallon for purposes of meeting the 

biomass-based diesel standard, but will 

be counted based on their Equivalence 

Value for purposes of meeting the 

advanced biofuel and total renewable 

fuel standards. Since it is likely that the 

statutory volume mandates were based 

on projections for biodiesel, we have 

chosen to use the Equivalence Value for 

biodiesel, 1.5, in this calculation. See 

Section II.E.1.a for further discussion. 

Other diesel fuel made from renewable 

biomass can also qualify as biomassbased diesel (e.g., renewable diesel, 

cellulosic diesel). But since the 

variation in energy content between 

them is relatively small, variation in the 

total physical volume of biomass-based 

diesel will likewise be small. 

In the NPRM we also proposed that 

the energy content of denatured ethanol 

be changed from the 77,550 Btu/gal 

value used in the RFS1 program to 

77,930 Btu/gal (lower heating value). 

The revised value was intended to 

provide a more accurate estimate of the 

energy content of pure ethanol, 76,400 

Btu/gal, rather than the rounded value 

of 76,000 Btu/gal that was used under 

RFS1. Except for the Renewable Fuels 

Association who supported this change, 

most stakeholders did not comment on 

this proposal. However, based on new 

provisions in the Food, Conservation, 

and Energy Act of 2008, we have since 

determined that the denaturant content 

of ethanol should be assumed to be 2% 

rather than the 5% used in the RFS1 

program. This additional change results 

in a denatured ethanol energy content of 

77,000 Btu/gal and a renewable content 

of denatured ethanol of 97.2%.11 The 

value of 77,000 Btu/gal will be used to 

convert biogas and renewable electricity 

into volumes of renewable fuel under 

RFS2. This change also affects the 

formula for calculating Equivalence 

Values assigned to renewable fuels. The 

new formula is shown below: 

EV = (R/0.972) * (EC/77,000) 

Where: 

EV = Equivalence Value for the renewable 

fuel, rounded to the nearest tenth. 

R = Renewable content of the renewable fuel. 

This is a measure of the portion of a 

renewable fuel that came from a 

renewable source, expressed as a 

percent, on an energy basis. 

EC = Energy content of the renewable fuel, 

in Btu per gallon (lower heating value). 

Under this new formula, Equivalence 

Values assigned to specific types of 

renewable fuel under RFS1 will 

continue unchanged under RFS2. 

However, non-ester renewable diesel 

will be required to have a lower energy 

content of at least 123,500 Btu/gal in 

order to qualify for an Equivalence 

Value of 1.7. A non-ester renewable 

diesel with a lower energy content 

would be required to apply for a 

different Equivalent Value according to 

the provisions in § 80.1415. 

2. Fuel Pathways and Assignment of D 

Codes 

As described in Section II.A, RINs 

under RFS2 would in general continue 

to have the same number of digits and 

code definitions as under RFS1. The one 

change will be that, while the D code 

will continue to identify the standard to 

which the RIN can be applied, it will 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 II.A–1. 

In order to generate RINs for 

renewable fuel that meets the various 

eligibility requirements (see Section 

II.B), a producer or importer must know 

which D code to assign to those RINs. 

Following the approach we described in 

the NPRM, a producer or importer will 

determine the appropriate D code using 

a lookup table in the regulations. The 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14711 

12However, a biomass-based diesel RIN can be 

used to satisfy Renewable Volume Obligations 

(RVO) for biomass-based diesel, advanced biofuel, 

and total renewable fuel. See Section II.G.3 for 

further discussion of the use of RINs for compliance 

purposes. 

13This suggestion was also made by several 

companies with respect to the RFS1 definition of 

cellulosic biomass ethanol, which allowed cornbased ethanol to be deemed cellulosic if 90% of the 

fossil fuel used at the ethanol facility to make 

ethanol was displaced by fuel derived from animal 

or other waste materials, including landfill gas. 

lookup table lists various combinations 

of fuel type, production process, and 

feedstock, and the producer or importer 

chooses the appropriate combination 

representing the fuel he is producing 

and for which he is generating RINs. 

Parties generating RINs are required to 

use the D code specified in the lookup 

table and are not 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 for purposes of RIN 

generation.12

This section describes our 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 

facilities for which the lookup table 

does not provide an applicable D code. 

a. Producers 

For both domestic and foreign 

producers of renewable fuel, the lookup 

table identifies 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 is assigned to one of the 

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 V. 

Note that the generation of RINs also 

requires as a prerequisite that the 

feedstocks used to make the renewable 

fuel meet the definition of ‘‘renewable 

biomass’’ as described in Section II.B.4, 

including applicable land use 

restrictions. If a producer is not able to 

demonstrate that his feedstocks meet the 

definition of renewable biomass, RINs 

cannot be generated. However, as noted 

in Section II.B.4.b.1, feedstocks 

typically include incidental 

contaminants. These contaminants may 

have been intentionally added to 

promote cultivation (e.g., pesticides, 

herbicides, fertilizer) or transport (e.g., 

nylon baling rope). In addition, there 

may be some incidental contamination 

of a particular load of feedstocks with 

co-product during feedstock production, 

or with other agricultural materials 

during shipping. For example, there 

may be incidental corn kernels 

remaining on some corn cobs used to 

produce cellulosic biofuel, or some 

sorghum kernels left in a shipping 

container that are introduced into a load 

of corn kernels being shipped to a 

biofuel production facility. The final 

regulations clarify that in assigning D 

codes for renewable fuel, producers and 

importers should disregard the presence 

of incidental contaminants in their 

feedstocks if the incidental 

contaminants are related to customary 

feedstock production and transport, and 

are impractical to remove and occur in 

de minimus levels. 

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 will 

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 will count as 

cellulosic biofuel. Biodiesel made from 

waste grease or soybean oil can count as 

biomass-based diesel. Ethanol made 

from sugarcane sugar will count as 

advanced biofuel. Finally, a variety of 

pathways will count as renewable fuel 

under the RFS2 program. The complete 

list of pathways that are valid under our 

final RFS2 program is discussed in 

Section V.C and are provided in the 

regulations at § 80.1426(f). 

Producers must 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 II.C. If there are 

changes to a 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 is 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 II.D.3 below. 

For producers for whom none of the 

defined fuel pathways in the lookup 

table apply, a producer can still generate 

RINs if he meets the criteria for 

grandfathered or deemed compliant 

status as described in Section II.B.3 and 

his fuel meets the definition of 

renewable fuel as described in Section 

II.B.1. In this case he would use a D 

code of 6 for those RINs generated under 

the grandfathering or deemed compliant 

provisions. 

A diesel fuel product produced from 

cellulosic feedstocks that meets the 60% 

GHG threshold can qualify as either 

cellulosic biofuel or biomass-based 

diesel. In the NPRM, we proposed that 

the producer of such ‘‘cellulosic diesel’’ 

be required to choose whether to 

categorize his product as either 

cellulosic biofuel or biomass-based 

diesel. However, we requested comment 

on an alternative approach in which an 

additional D code would be defined to 

represent cellulosic diesel allowing the 

cellulosic diesel RIN to be sold into 

either market. As described more fully 

in Section II.A above, we are finalizing 

this alternative approach in today’s final 

rule. Producers or importers of a fuel 

that qualifies as both biomass-based 

diesel and cellulosic biofuel must use a 

D code of 7 in the RINs they generate, 

and will thus have the flexibility of 

marketing such RINs to parties seeking 

either cellulosic biofuel or biomassbased diesel RINs, depending on market 

demand. Obligated parties can apply 

RINs with a D code of 7 to either their 

cellulosic biofuel or biomass-based 

diesel RVOs, but not both. 

In addition to the above comments, 

we received comments requesting that 

the use of biogas as process heat in the 

production of ethanol, should not be 

limited to use at the site of renewable 

fuel production. Specifically, 

commenters point out that the 

introduction of gas produced from 

landfills or animal wastes to fungible 

pipelines is the only practical manner 

for most renewable fuel facilities to 

acquire and use landfill gas, since very 

few are located adjacent to landfills, or 

have dedicated pipelines from landfill 

gas operations to their facilities.13 The 

commenters suggested that ethanol 

plants causing landfill gas to be 

introduced into a fungible gas pipeline 

be allowed to claim those volumes. The 

alternative would be to allow landfill 

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14712 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

14Note that biogas used for transportation fuel 

includes propane made from renewable biomass. 

gas that is only used onsite to be 

counted in establishing the pathway. 

We believe that the suggested 

approach has merit. We agree that it 

does not make any difference in terms 

of the beneficial environmental 

attributes associated with the use of 

landfill gas whether the displacement of 

fossil fuel occurs in a fungible natural 

gas pipeline, or in a specific facility that 

draws gas volume from that pipeline. In 

fact, a similar approach is widely used 

with respect to electricity generated by 

renewable biomass that is placed into a 

commercial electricity grid. A party 

buying the renewable power is credited 

with doing so in state renewable 

portfolio programs even though the 

power from these sources is placed in 

the fungible grid and the electrons 

produced by a renewable source may 

never actually be used by the party 

purchasing it. In essence these programs 

assume that the renewable power 

purchased and introduced into the grid 

is in fact used by the purchaser, even 

though all parties acknowledge that use 

of the actual renewable-derived 

electrons can never be verified once 

placed in the fungible grid. We believe 

that this approach will ultimately 

further the GHG reduction and energy 

security goals of RFS2. 

Producers may therefore take into 

account such displacement provided 

that they demonstrate that a verifiable 

contractual pathway exists and that 

such pathway ensures that (1) a specific 

volume of landfill gas was placed into 

a commercial pipeline that ultimately 

serves the transportation fueling facility 

and (2) that the drawn into this facility 

from that pipeline matches the volume 

of landfill gas placed into the pipeline 

system. Thus facilities using such a fuel 

pathway may then use an appropriate D 

code for generation of RINs. 

This approach also applies to biogas 

and electricity made from renewable 

fuels and which are used for 

transportation. Producers of such fuel 

will be able to generate RINs, provided 

that a contractual pathway exists that 

provides evidence that specific 

quantities of the renewable fuel (either 

biogas or electricity) was purchased and 

contracted to be delivered to a specific 

transportation fueling facility.14 We 

specify that the pipeline (or 

transmission line) system must 

ultimately serve the subject facility. For 

electricity that is produced by the cofiring of fossil fuels with renewable 

biomass derived fuels, we are requiring 

that the resulting electricity is pro-rated 

to represent only that amount of 

electricity generated by the qualifying 

biogas, for the purpose of computing 

RINs. 

We are also providing for those 

situations in which biogas or renewable 

electricity is provided directly to the 

transportation facility, rather than using 

a commercial distribution system such 

as pipelines or transmission lines. For 

both cases—dedicated use and 

commercial distribution—producers 

must provide contractual evidence of 

the production and sale of such fuel, 

and there are also reporting and 

recordkeeping requirements to be 

followed as well. 

Presently, there is no D code for 

electricity that is produced from 

renewable biomass. The petition process 

for assigning such codes in today’s rule 

can be used for such purpose. 

b. Importers 

For imported renewable fuel under 

RFS2, we are anticipating the importer 

to be the primary party responsible for 

generating RINs. However, the foreign 

producer of renewable fuel can instead 

elect to generate RINs themselves under 

certain conditions as described more 

fully in Section II.D.2.c below. This 

approach is consistent with the 

approach under RFS1. 

Under RFS1, importers who import 

more than 10,000 gallons in a calendar 

year were required to 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 wastederived ethanol. Due to the new 

definitions of renewable fuel and 

renewable biomass in EISA, importers 

can no longer generate RINs under RFS2 

on the basis of fuel type alone. Instead, 

they must be able to demonstrate that 

the renewable biomass definition has 

been met for the renewable fuel they 

intend to import and for which they will 

generate RINs. 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 the RINs they generate. 

Therefore, in order to generate RINs, the 

importer will be required to obtain this 

information from a foreign producer. 

RINs can only be generated if a 

demonstration is made that the 

feedstocks used to produce the 

renewable fuel meet the definition of 

renewable biomass. 

In summary, under today’s final rule, 

importers can import any renewable 

fuel, but can only generate RINs to 

represent the imported renewable fuel 

under the two conditions described 

below. If these conditions do not apply, 

the importer can import biofuel but 

cannot generate RINs to represent that 

biofuel. 

1. The imported renewable fuel is not 

accompanied by RINs generated by the 

registered foreign producer 

2. The importer obtains from the 

foreign producer: 

—Documentation demonstrating that 

the renewable biomass definition has 

been met for the volume of renewable 

fuel being imported. 

—Documentation about the feedstock 

and production process used to 

produce the renewable fuel to allow 

the importer to determine the 

appropriate D-code designation in the 

RINs generated. 

We are also finalizing additional 

requirements for foreign producers who 

either generate RINs or provide 

documentation to an importer sufficient 

to allow the importer to generate RINs. 

As described more fully in the next 

section, these additional requirements 

include restrictions on mixing of 

biofuels in the distribution system as it 

travels from the foreign producer to the 

importer. 

Finally, EPA is assessing whether 

additional requirements on foreigngenerated fuel may be necessary for 

situations in which importers are 

generating RINs for the fuel. Additional 

requirements may be necessary to 

ensure that the importers have sufficient 

information to properly generate the 

RINs and that EPA has sufficient 

information to determine whether those 

RINs have been legitimately generated. 

EPA will pursue an amendment to the 

final RFS2 regulations if we find that 

additional requirements are appropriate 

and necessary. 

c. Additional Provisions for Foreign 

Producers 

In general, we are requiring foreign 

producers of renewable fuel to meet the 

same requirements as domestic 

producers with respect to registration, 

recordkeeping and reporting, attest 

engagements, and the transfer of RINs 

they generate with the batches of 

renewable fuel that those RINs 

represent. However, we are also placing 

additional requirements on foreign 

producers to ensure that RINs entering 

the U.S. are valid and that the 

regulations can be enforced at foreign 

facilities. These additional requirements 

are designed to accommodate the more 

limited access that EPA enforcement 

personnel have to foreign entities that 

are regulated parties under RFS2, and 

also the fact that foreign-produced 

biofuel intended for export to the U.S. 

is often mixed with biofuel that will not 

be exported to the U.S. 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14713 

Under RFS1, foreign producers had 

the option of generating RINs for the 

renewable fuel that they export to the 

U.S. if they wanted to designate their 

fuel as cellulosic biomass ethanol or 

waste-derived ethanol, and thereby take 

advantage of the additional 1.5 credit 

value afforded by the 2.5 Equivalence 

Value for such products. In order to 

ensure that EPA had the ability to 

enforce the regulations relating to the 

generation of RINs from such foreign 

ethanol producers, the RFS1 regulations 

specified additional requirements for 

them, including posting a bond, 

admitting EPA enforcement personnel, 

and submitting to third-party 

engineering reviews of their production 

process. For RFS2, we are maintaining 

these additional requirements for 

foreign producers because EPA 

enforcement personnel have the same 

limitations under RFS2 with regard to 

access to foreign entities that are 

regulated parties as they did under 

RFS1. 

EISA also creates other unique 

challenges in the implementation and 

enforcement of the renewable fuel 

standards for foreign-produced 

renewable fuel imported into the U.S. 

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 under the RFS2 

program. Thus, whether foreign 

producers or importers generate RINs, 

this information must be collected and 

maintained by the RIN generator. 

If a foreign producer generates RINs 

for renewable fuel that it produces and 

exports to the U.S., we are requiring that 

ethanol must be dewatered and 

denatured by the foreign producer prior 

to leaving the production facility and 

prior to the generation of RINs. This is 

consistent with our definition of 

renewable fuel in which ethanol that is 

valid under RFS2 must be denatured. 

Moreover, the foreign producer is 

required to strictly segregate a batch of 

renewable fuel and its associated RINs 

from all other volumes of renewable fuel 

as it travels from the foreign producer to 

the importer. The strict segregation 

ensures that RINs entering the U.S. 

appropriately represent the renewable 

fuel imported into the U.S. both in 

terms of renewable fuel type and 

volume. 

Several commenters requested that in 

general the importer be the RIN 

generator for imported renewable fuel. 

Since most imported ethanol is 

currently made in Brazil and is not 

denatured by the foreign producer, any 

RINs generated must be generated by the 

importer. However, to accomplish this, 

the importer must obtain the 

appropriate information from a foreign 

producer regarding compliance with the 

renewable biomass definition and a 

description of the associated pathway 

for the renewable fuel. Under these 

circumstances, the foreign producer 

must ensure that the information is 

transferred along with the renewable 

fuel through the distribution system 

until it reaches the importer. The 

foreign producer’s volume of renewable 

fuel need not be strictly segregated from 

other volumes in this case, so long as a 

volume of chemically indistinguishable 

renewable fuel is tracked through the 

distribution system from the foreign 

producer to the importer, and the 

information needed by the importer to 

generate RINs follows this same path 

through the distribution system. Strict 

segregation of the volume is not 

necessary in this case, and the importer 

will determine appropriate number of 

RINs for the specific volume and type of 

renewable fuel that he imports. 

Finally, if a foreign producer chooses 

not to participate in the RFS2 program 

and thus neither generates RINs nor 

provides information to the importer so 

that the importer can generate RINs, the 

foreign producer can still export biofuel 

to the U.S. However, under these 

circumstances the biofuel would not be 

renewable fuel under RFS2, no RINs 

could be generated by any party, and 

thus the foreign producer would not be 

subject to any of the registration, 

recordkeeping, reporting, or attest 

engagement requirements. 

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 for fuel produced at 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 

applicable D code for various RINs 

generated at the facility. 

If more than one pathway applies to 

a facility within a compliance period, 

no special steps will need to be taken 

if the D code is the same for all the 

applicable pathways. In this case, all 

RINs generated at the facility will have 

the same D code regardless. Such a 

producer with multiple applicable 

pathways must still describe its 

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

production process(es) in its initial 

registration and annual report to the 

Agency so that we can 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. For instance, a 

producer could change feedstocks, 

production processes, or the type of fuel 

he produces in the middle of a 

compliance period. Or, he could use 

more than one feedstock or produce 

more than one fuel type simultaneously. 

The approach we are finalizing for 

designating D codes for RINs in these 

cases follows the approach described in 

the NPRM and is summarized in Table 

II.D.3–1. 

TABLE II.D.3–1—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. 

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14714 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

15Batch-RINs and gallon-RINs are defined in the 

regulations at 40 CFR 80.1401. 

TABLE II.D.3–1—APPROACH TO ASSIGNING MULTIPLE D CODES FOR MULTIPLE APPLICABLE PATHWAYS—Continued 

Case/Description Proposed approach 

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. 

Commenters were generally 

supportive of this approach to multiple 

applicable pathways, and as a result we 

are finalizing it with few modifications 

from the proposal. Further discussion of 

the comments we received can be found 

in Section 3.5.4 of the S&A document. 

Following our proposal, cases listed 

in Table II.D.3–1 will 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. This approach 

covers all likely cases in which multiple 

applicable pathways may apply to a 

renewable fuel producer. Some 

examples of how Case 2 or 3 would 

apply are provided in the NPRM. 

A facility where two or more different 

types of feedstock are used to produce 

a single fuel (such as Case 3 in Table 

II.D.3–1) will be required to generate 

two or more separate batch-RINs 15 for a 

single volume of renewable fuel, and 

these separate batch-RINs will have 

different D codes. The D codes will be 

chosen on the basis of the different 

pathways as defined in the lookup table 

in § 80.1426(f). The number of gallonRINs that will be included in each of the 

batch-RINs will depend on the relative 

amount of the different types of 

feedstocks used by the facility. In the 

NPRM, we proposed to use the relative 

energy content of the feedstocks to 

determine how many gallon-RINs 

should be assigned to each D code. 

Commenters generally did not address 

this aspect of our proposal, and we are 

finalizing it in today’s action. Thus, the 

useable energy content of each feedstock 

must be used to divide the total number 

of gallon-RINs generated for a batch of 

renewable fuel into two or more groups, 

each corresponding to a different D 

code. Several separate batch-RINs can 

then be generated and assigned to the 

single volume of renewable fuel. The 

applicable calculations are given in the 

regulations at § 80.1426(f)(3). 

We proposed several elements of the 

calculation of the useable energy 

content of the feedstocks, including the 

following: 

1. Only that fraction of a feedstock 

which is expected to be converted into 

renewable fuel by the facility can be 

counted in the calculation, taking into 

account facility conversion efficiency. 

2. The producer of the renewable fuel 

is required to designate this fraction 

once each year for the feedstocks 

processed by his facility during that 

year, and to include this information as 

part of his reporting requirements. 

3. Each producer is required to 

designate the energy content (in Btu/lb) 

once each year of the portion of each of 

his feedstocks which is converted into 

fuel. The producer may determine these 

values for his own feedstocks, or may 

use default values provided in the 

regulations at § 80.1426(f)(7). 

4. Each producer is required to 

determine the total mass of each type of 

feedstock used by the facility on at least 

a daily basis. 

Based on the paucity of comments we 

received on this issue, we are finalizing 

the provisions regarding the calculation 

of useable energy content of the 

feedstocks as it was proposed in the 

NPRM. As described in Section II.J, 

producers of renewable fuel will be 

required to submit information in their 

reports on the feedstocks they used, 

their production processes, and the type 

of fuel(s) they produced during the 

compliance period. This will apply to 

both domestic producers and foreign 

producers who export any renewable 

fuel to the U.S. We will 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 co-fired 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 will be only 

partially renewable. RINs can be 

generated in such cases, but must be 

done 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 are eliminating the RFS1 

provision applicable only to liquid 

feedstocks and replacing it with a more 

comprehensive approach that will apply 

to liquid, solid, or gaseous feedstocks 

and any type of conversion process. In 

this final approach, producers are 

required to use the relative energy 

content of their renewable and nonrenewable feedstocks to determine the 

renewable fraction of the fuel that they 

produce. This fraction in turn is used to 

determine the number of gallon-RINs 

that should be generated for each batch. 

Commenters said little about our 

proposed methodology to use the 

relative energy content of the 

feedstocks, and we are therefore 

finalizing it largely as proposed. 

We also requested comment on 

allowing renewable fuel producers to 

use an accepted test method to directly 

measure the fraction of the fuel that is 

derived from biomass rather than a 

fossil fuel feedstock. For instance, 

ASTM D–6866 is a radiocarbon dating 

test method that can be used to 

determine the renewable content of 

transportation fuel. The use of such a 

test method can be used in lieu of the 

calculation of the renewable portion of 

the fuel based on the relative energy 

content of the renewable biomass and 

fossil feedstocks. Commenters generally 

supported the option of using a 

radiocarbon dating approach. As a 

result, we believe it would be 

appropriate and are finalizing a 

provision to allow parties that coprocess renewable biomass and fossil 

fuels to choose between using the 

relative energy in the feedstocks or 

ASTM D–6866 to determine the number 

of gallon-RINs that should be generated. 

Regardless of the approach chosen, the 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14715 

producer will still need to separately 

verify that the renewable feedstocks 

meet the definition of renewable 

biomass. 

If a producer chose to use the energy 

content of the feedstocks, the 

calculation would be similar to the 

treatment of renewable fuels with 

multiple D codes as described in 

Section II.D.3 above. As shown in the 

regulations at § 80.1426(f)(3), 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. Only one batch-RIN 

would be generated for a single volume 

of fuel produced from both a renewable 

feedstock and a fossil feedstock, and 

this one batch-RIN must be based on the 

contribution that the renewable 

feedstock makes to the total volume of 

fuel. The calculation of the relative 

energy contents includes 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 will be accounted for. The 

relative energy content of the feedstocks 

is used to adjust the basic calculation of 

the number of gallon-RINs downward 

from that calculated on the basis of 

batch fuel volume and the applicable 

Equivalence Value. The D code that 

must be assigned to the RINs is 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 

produces only cellulosic diesel for 

purposes of identifying the appropriate 

D code for the fraction of biofuel that 

qualifies as renewable fuel under EISA. 

If a producer chose to use D–6866, he 

would be required to either apply this 

test to every batch, or alternatively to 

take samples of every batch of fuel he 

produced over the course of one month 

and combine them into a single 

composite sample. The D–6866 test 

would then be applied to the composite 

sample, and the resulting renewable 

fraction would be applied to all batches 

of fuel produced in the next month to 

determine the appropriate number of 

RINs that must be generated. For the 

first month, the producer can estimate 

the non-fossil fraction, and then make a 

correction as needed in the second 

month. The producer would be required 

to recalculate the renewable fraction 

every subsequent month. See the 

regulations at § 80.1426(f)(9). 

5. Facilities That Process Municipal 

Solid Waste 

As described in Section II.B.4.d, only 

the separated yard and food waste of 

municipal solid waste (MSW) are 

considered to be renewable biomass and 

may be used to produce renewable fuels 

under the RFS2 program. While 

renewable fuel producers may produce 

fuel from all organic components of 

MSW, they may generate RINs for only 

that portion of MSW that qualifies as 

renewable biomass. We are providing 

two methods for determining the 

appropriate number of RINs to generate 

for each batch of fuel, depending on 

whether the feedstock is pure food and 

yard waste, or separated municipal solid 

waste, as described in Section II.B.4.d. 

While not all biogenic material in the 

separated MSW is cellulosic, the vast 

majority of it is likely to be in most 

situations. Specifically, separated 

municipal solid waste may contain 

some non-biogenic materials such as 

plastics that were unable to be recycled 

due to market conditions. We are 

requiring producers of renewable fuel 

made from separated municipal solid 

waste to use the radiocarbon dating 

method D–6866 to calculate the 

biogenic fraction, presumed to be 

composed of cellulosic materials. 

Therefore, unless a renewable fuel 

producer is using MSW streams that are 

clearly not cellulosic, we anticipate that 

a D code of either 3 or 7 will be 

appropriate for such RINs. See the 

regulations at § 80.1426(f). 

6. RINless Biofuel 

Under the RFS1 program, all 

renewable fuel made from renewable 

feedstocks and used as motor vehicle 

fuel in the U.S. was assigned RINs. 

Therefore, aside from the very small 

amounts of biofuel used in nonroad 

applications or as heating oil, all 

renewable fuel produced or imported 

counted towards the mandated volume 

goals of the RFS program. Although 

conventional diesel fuel was not subject 

to the standards under RFS1, all other 

motor vehicle fuel fell into two groups: 

fuel subject to the standards, and fuel 

for which RINs were generated and was 

used to meet those standards. 

Under RFS2, our approach to 

compliance with the renewable biomass 

provision will allow the possibility for 

some biofuel to be produced without 

RINs. As described in Section II.B.4 

above, we are modifying our approach 

to compliance with the renewable 

biomass provision so that renewable 

fuel producers using feedstocks from 

domestic planted crops and crop 

residue will be presumed to meet the 

renewable biomass provision. Under 

this ‘‘aggregate compliance’’ approach, 

these producers will be generating RINs 

for all their renewable fuel. However, 

producers who use foreign-grown crops 

or crop residue or other feedstocks such 

as planted trees or forestry residues will 

not be able to take advantage of this 

aggregate compliance approach. Instead, 

they will be required to demonstrate 

that their feedstocks meet the renewable 

biomass definition, including the 

associated land use restrictions, before 

they will be permitted to generate RINs. 

Absent such a demonstration, these 

producers can still produce biofuel but 

will not generate RINs. In addition, fuel 

producers whose fuel does not qualify 

as renewable fuel under this program 

because it does not meet the 20% GHG 

threshold (and is not grandfathered) can 

still produce biofuel but will not be 

allowed to generate RINs. 

Transportation fuel consumed in the 

U.S. will therefore be comprised of three 

groups: fuel subject to the standards 

(gasoline and diesel), fuel for which 

RINs are generated and will be used to 

meet those standards, and RINless 

biofuel. RINless biofuel will not be 

covered under any aspect of the RFS2 

program, despite the fact that in many 

cases it will meet the EISA definition of 

transportation fuel upon blending with 

gasoline or diesel. 

In their comments in response to the 

NPRM, several refiners suggested that 

RINless biofuel should be treated as an 

obligated volume similar to gasoline and 

diesel, and thus be subject to the 

standards. Doing so would ensure that 

all transportation fuels are covered 

under the RFS2 program, consistent 

with RFS1. Such an approach would 

also provide renewable fuel producers 

with an incentive to demonstrate that 

their feedstocks meet the renewable 

biomass definition and thus generate 

RINs for all the biofuel that they 

produce. There could be less potential 

for market manipulation on the part of 

biofuel producers who might be 

considering producing RINless biofuel 

as a means for increasing demand for 

renewable fuel and RINs. 

Nevertheless, we do not believe that 

it would be appropriate at this time to 

finalize a requirement that RINless 

biofuel be considered an obligated fuel 

subject to the standards. We did not 

propose such an approach in the NPRM, 

and as a result many renewable fuel 

producers who could be affected did not 

have an opportunity to consider and 

comment on it. Moreover, the volume of 

RINless biofuel is likely to be small 

compared to the volume of renewable 

fuel with RINs since RINs have value 

and producers currently have an 

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14716 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

16Actual 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. 

17Hawaii opted-in to the original RFS program; 

that opt-in is carried forward to this program. 

18Under 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. 

19See Section III.E. 

incentive to generate them. However, if 

in the future RIN values should fall—for 

instance, if crude oil prices rise high 

enough and the market drives up 

demand for biofuels—the incentive to 

demonstrate compliance with the 

renewable biomass definition may 

decrease and there may be an increase 

in the volume of RINless biofuel. Under 

such circumstances it may be 

appropriate to reconsider whether 

RINless biofuel should be designated as 

an obligated volume subject to the 

standards. 

E. Applicable Standards 

The renewable fuel standards are 

expressed as a volume percentage, and 

are used by each refiner, blender or 

importer to determine their renewable 

fuel 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 I.A.1–1.16

The formulas finalized today for use 

in deriving annual renewable fuel 

standards are based in part on an 

estimate of combined gasoline and 

diesel volumes, for both highway and 

nonroad uses, for the year in which the 

standards will apply. The standards will 

apply to refiners, blenders, and 

importers of these fuels. As described 

more fully in Section II.F.3, other 

producers of transportation fuel, such as 

producers of natural gas, propane, and 

electricity from fossil fuels, are not 

subject to the standards. Since the 

standards apply to refiners, blenders 

and importers of gasoline and diesel, 

these are also the transportation fuels 

that are used to determine the annual 

volume obligations of an individual 

refiner, blender, or importer. 

The projected volumes of gasoline 

and diesel used to calculate the 

standards will continue to be provided 

by EIA’s Short-Term Energy Outlook 

(STEO). The standards applicable to a 

given calendar year will be published by 

November 30 of the previous year. 

Gasoline and diesel volumes will 

continue to be adjusted to account for 

the required renewable fuel volumes. In 

addition, gasoline and diesel volumes 

produced by small refineries and small 

refiners will be exempt through 2010, 

and that year’s standard is adjusted 

accordingly, as discussed below. 

As discussed in the proposal, four 

separate standards are required under 

the RFS2 program, corresponding to the 

four separate volume requirements 

shown in Table I.A.1–1. The specific 

formulas we use to calculate the 

renewable fuel standards are described 

below in Section II.E.1. 

In order for an obligated party to 

demonstrate compliance, the percentage 

standards are 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 continues to be 

referred to as its Renewable Volume 

Obligation (RVO). Since there are four 

separate standards under the RFS2 

program, there are likewise four 

separate RVOs applicable to each 

obligated party. Each standard applies 

to the sum of all gasoline and diesel 

produced or imported. Determination of 

RVOs is discussed in Section II.G.2. 

1. Calculation of Standards 

a. How Are the Standards Calculated? 

The four separate renewable fuel 

standards are based primarily on (1) the 

49-state 17 gasoline and diesel 

consumption volumes projected by EIA, 

and (2) the total volume of renewable 

fuels required by EISA for the coming 

year. Table I.A.2–1 shows the required 

overall volumes of four types of 

renewable fuel specified in EISA. Each 

renewable fuel standard is expressed as 

a volume percentage of combined 

gasoline and diesel sold or introduced 

into commerce in the U.S., and is used 

by each obligated party to determine its 

renewable volume obligation. 

Today we are finalizing an approach 

to setting standards that is based in part 

on the sum of all gasoline and diesel 

produced or imported in the 48 

contiguous states and Hawaii. An 

approach we are not adopting but which 

we discussed in the proposal would 

have split the standards between those 

that would be specific to gasoline and 

those that would be specific to diesel. 

Though 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, we are not adopting this approach 

because it relies on projections of the 

relative amounts of gasoline-displacing 

and diesel-displacing renewable fuels. 

These projections would need to be 

updated every year, and as stated in the 

proposal, we believe that such an 

approach would unnecessarily 

complicate the program. 

While the required amount of total 

renewable fuel for a given year is 

provided by EISA, the Act requires EPA 

to base the standards on an EIA estimate 

of the amount of gasoline and diesel that 

will be sold or introduced into 

commerce for that year. As discussed in 

the proposal, EIA’s STEO will continue 

to be the source for projected gasoline, 

and now diesel, consumption estimates. 

In order to achieve the volumes of 

renewable fuels specified in EISA, the 

gasoline and diesel volumes used to 

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

diesel pools. Because the STEO volumes 

include renewable fuel use, we must 

subtract the total renewable fuel volume 

from the total gasoline and diesel 

volume to get total non-renewable 

gasoline and diesel volumes. The Act 

also requires EPA to use EIA estimates 

of renewable fuel volumes; the best 

estimation of the coming year’s 

renewable fuel consumption is found in 

Table 8 (U.S. Renewable Energy Supply 

and Consumption) of the STEO. 

Additional information on projected 

renewable fuel use will be included as 

it becomes available. 

As discussed in Section II.D.1, we are 

finalizing the energy content approach 

to Equivalence Values for the cellulosic 

biofuel, advanced biofuel, and total 

renewable fuel standards. However, the 

biomass-based diesel standard is based 

on the volume of biodiesel. In order to 

align both of these approaches 

simultaneously, biodiesel will continue 

to generate 1.5 RINs per gallon as in 

RFS1, and the biomass-based diesel 

volume mandate from EISA is then 

adjusted upward by the same 1.5 factor. 

The net result is a biomass-based diesel 

gallon being worth 1.0 gallons toward 

the biomass-based diesel standard, but 

1.5 gallons toward the other standards. 

CAA section 211(o) exempts small 

refineries 18 from the RFS requirements 

until the 2011 compliance period. In 

RFS1, we extended this exemption to 

the few remaining small refiners not 

already exempted.19 Small refineries 

and small refiners will continue to be 

exempt from the program until 2011 

under the new RFS2 regulations. Thus 

we have excluded their gasoline and 

diesel volumes from the overall nonrenewable gasoline and diesel volumes 

used to determine the applicable 

percentages until 2011. As discussed in 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14717 

the proposal, total small refinery and 

small refiner gasoline production 

volume is expected to be fairly constant 

compared to total U.S. transportation 

fuel production. Thus we estimated 

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 standards. 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 proposed 

and are finalizing this value as zero. 

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. 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. Therefore, 

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. 

In summary, the total projected nonrenewable gasoline and diesel volumes 

from which the annual standards are 

calculated are 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. 

The following formulas are used to 

calculate the percentage standards: 

Std

RFV

CB i

CB i

,

, = × % ( ) − + − ( ) − +− ( ) + −

100

G RG GS RGS GE D RD DS R i i i i ii i i ( ) DS DE i i −

Std

RFV

BBD i

BBD i

,

, % . = ×

×

( ) − + − ( ) − +− ( ) 100

1 5

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

Std

RFV

AB i

AB i

,

, = × % ( ) − + − ( ) − +− ( ) + −

100

G RG GS RGS GE D RD DS R i i i i ii i i ( ) DS DE i i −

Std

RFV

RF i

RF i

,

, = × % ( ) − + − ( ) − +− ( ) + −

100

G RG GS RGS GE D RD DS R i i i i ii i i ( ) DS DE i i −

Where 

StdCB,i = The cellulosic biofuel standard for 

year i, in percent 

StdBBD,i = The biomass-based diesel standard 

(ethanol-equivalent basis) 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 


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14718 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

20See 73 FR 70643 (November 21, 2008). 

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. Standards for 2010 

We are finalizing the standards for 

2010 in today’s action. As explained in 

Section I.A.2, while the rulemaking is 

not effective until July 1, 2010, the 2010 

standards we are setting are annual 

standards with compliance 

demonstrations are due by February 28, 

2011. 

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. 

As discussed in Section IV.B., we are 

utilizing the EIA projection of 5.04 

million gallons (6.5 million ethanol 

equivalent gallons) of cellulosic biofuel 

as the basis for setting the percentage 

standard for cellulosic biofuel for 2010. 

This is lower than the 100 million 

gallon standard set by EISA that we 

proposed upholding, but reflects the 

current state of the industry, as 

discussed in section V.B. We expect 

continued growth in the industry in 

2011 and beyond. Since the advanced 

biofuel standard is met by just the 

biomass-based diesel volume required 

in 2010, and additional volumes of 

other advanced biofuels (e.g., sugarcane 

ethanol) are available as well, no change 

to the advanced biofuel standard is 

necessary for 2010. Moreover, given the 

nested nature of the volume mandates, 

since no change in the advanced biofuel 

standard is necessary, the total 

renewable fuel standard need not be 

changed either. 

TABLE II.E.1.b–1—STANDARDS FOR

2010 

Percent 

Cellulosic biofuel ..................... 0 .004 

Biomass-based diesel ............ 1 .10 

Advanced biofuel .................... 0 .61 

Renewable fuel ....................... 8 .25 

2. Treatment of Biomass-Based Diesel in 

2009 and 2010 

As described in Section I.A.2, the four 

separate 2010 standards issued in 

today’s rule will apply to all gasoline 

and diesel produced in 2010. However, 

EISA included volume mandates for 

biomass-based diesel, advanced biofuel, 

and total renewable fuel that applied in 

2009. Since the RFS2 program was not 

effective in 2009 and thus the volume 

mandates for biomass-based diesel and 

advanced biofuel were not implemented 

in 2009, our NPRM proposed a 

mechanism to ensure that the 2009 

biomass-based diesel volume mandate 

would eventually be met. In today’s 

final rule we are finalizing the proposed 

approach. 

a. Shift in 2009 Biomass-Based Diesel 

Compliance Demonstration to 2010 

Under the RFS1 regulations that 

applied in 2009, we set the applicable 

standard for total renewable fuel in 

November 2008 20 using the required 

volume of 11.1 billion gallons specified 

in the Clean Air Act (as amended by 

EISA), gasoline volume projections from 

EIA, and the formula provided in the 

regulations at § 80.1105(d). The existing 

RFS1 regulations did not provide a 

mechanism for requiring the use of 0.5 

billion gallons of biomass-based diesel 

or the 0.6 billion gallons of advanced 

biofuel mandated by EISA for 2009. 

In the NPRM we proposed that the 

compliance demonstration for the 2009 

biomass-based diesel requirement of 0.5 

bill gal be extended to 2010. This 

approach would combine the 0.5 bill gal 

requirement for 2009 and the 0.65 bill 

gal requirement for 2010 into a single 

requirement of 1.15 bill gal for which 

compliance demonstrations would be 

made by February 28, 2011. As 

described in the NPRM, we believe that 

the deficit carryover provision provides 

a conceptual mechanism for this 

approach, since it would have allowed 

obligated parties to defer compliance 

with any or all of the 2009 standards 

until 2010. We are finalizing this 

approach in today’s action. We believe 

it will ensure that these two year’s 

worth of biomass-based diesel will be 

used, while providing reasonable lead 

time for obligated parties. It avoids a 

transition that fails to have any 

requirements related to the 2009 

biomass-based diesel volume, and 

instead requires the use of the 2009 

volume but achieves 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 were unable to issue 

final regulations prior to the 2009 

compliance year. We announced our 

intentions to implement the 2009 and 

2010 biomass-based diesel requirements 

in this manner in the November 2008 

Federal Register notice cited 

previously. We reiterated these 

intentions in our NPRM. Thus, obligated 

parties will have had sufficient lead 

time to acquire a sufficient number of 

biomass-based diesel RINs by the end of 

2010 to comply with the standard based 

on 1.15 bill gal. 

Data available at the time of this 

writing suggests that approximately 450 

million gallons of biodiesel was 

produced in 2009, thus requiring 700 

million gallons to be produced in 2010 

to satisfy the combined 2009 and 2010 

volume mandates. Information from 

commenters and other contacts in the 

biodiesel industry indicate that 

feedstocks and production facilities will 

be available in 2010 to produce this 

volume. 

Refiners generally commented that 

the proposed approach to 2009 and 

2010 biomass-based diesel volumes was 

not appropriate and should not be 

implemented. They also recommended 

that the RFS2 program should be made 

effective on January 1, 2011 with no 

carryover of any previous-year 

obligations for biomass-based diesel or 

any other volume mandate. In contrast, 

the National Biodiesel Board and 

several individual biodiesel producers 

supported the proposed approach, but 

believed it was insufficient to compel 

obligated parties to purchase biodiesel 

in 2009, something they considered 

critical to the survival of the biodiesel 

industry. Many of these commenters 

requested that we conduct an interim 

rulemaking that would apply to 2009 to 

implement the EISA mandated volume 

of 0.5 billion gallons of biomass-based 

diesel. If the RFS2 program could not be 

implemented until 2011, they likewise 

requested that interim measures be 

taken for 2010 to ensure that the full 

1.15 bill gal requirement would be 

implemented. However, putting in place 

this new volume requirement without 

also putting in place EISA’s new 

definition for biomass-based diesel, 

renewable fuel, and renewable biomass 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14719 

would have raised significant legal and 

policy issues that would necessarily 

have required a new proposal with its 

own public notice and comment 

process. Because of the significant time 

required for notice and comment 

rulemaking, the need to provide 

industry with adequate lead time for 

new requirements, and the fact that we 

were already well into calendar year 

2009 at the time the request for an 

interim rule was received, it was 

unlikely that any interim rule could 

have impacted biodiesel demand in 

2009. Moreover, Agency resources 

applied to the interim rulemaking 

would have been unavailable for 

development of the final RFS2 

rulemaking. Developing an interim rule 

could have undermined EPA’s ability to 

complete the full RFS2 program 

regulations in time for 2010 

implementation. As a result, we did not 

pursue an interim rulemaking. 

With regard to advanced biofuel, it is 

not necessary to implement a separate 

requirement for the 0.6 billion gallon 

mandate for 2009. Due to the nested 

nature of the volume requirements and 

the fact that Equivalence Values will be 

based on the energy content relative to 

ethanol, the 0.5 billion gallon 

requirement for biomass-based diesel 

will count as 0.75 billion gallons of 

advanced biofuel, exceeding the 

requirement of 0.6 billion gallons. Thus 

compliance with the biomass-based 

diesel requirement in 2009 

automatically results in compliance 

with the advanced biofuel standard. 

All 2009 biodiesel and renewable 

diesel RINs, identifiable through an RR 

code of 15 or 17 respectively under the 

RFS1 regulations, will 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 is consistent with our 

approach to any other standard for any 

other year and consistent with the 

flexibility available to any obligated 

party that carries 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. 

We did not reduce the 2009 volume 

requirement for total renewable fuel by 

0.5 billion gallons to account for the fact 

that we intended to move the 

compliance demonstration for this 

volume has been moved to the 2010 

compliance period. Instead, we are 

allowing 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). To accomplish this, we 

proposed in the NPRM that an obligated 

party would add up the 2009 biodiesel 

and renewable diesel RINs that he used 

for 2009 compliance with the RFS1 

standard for total renewable fuel, and 

reduce his 2010 biomass-based diesel 

obligation by this amount. Thus, 2009 

biodiesel and renewable diesel RINs are 

essentially used twice. Any remaining 

2010 biomass-based diesel obligation 

would need to be covered either with 

2009 biodiesel and renewable diesel 

RINs that were not used for compliance 

in 2009 or with 2010 biomass-based 

diesel RINs. We are finalizing this 

approach in today’s notice. 

b. Treatment of Deficit Carryovers, RIN 

Rollover, and RIN Valid Life for 

Adjusted 2010 Biomass-Based Diesel 

Requirement 

Our transition approach for biomassbased diesel is conceptually similar, but 

not identical, to the statutory deficit 

carryover provision. In a typical deficit 

carryover situation, an obligated party 

can carry forward any amount of a 

current-year deficit to the following 

year. In the absence of any 

modifications to the deficit carryover 

provisions for our biomass-based diesel 

transition 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. As 

described in the NPRM, we believe that 

the deficit carryover provisions should 

be modified in the context of the 

transition biomass-based diesel 

approach to more closely represent what 

would have occurred if we had been 

able to implement the 0.5 bill gal 

requirement in 2009. Specifically, we 

are prohibiting obligated parties from 

carrying over a biomass-based diesel 

deficit into 2011 larger than that based 

on the 0.65 bill gal volume requirement 

for 2010. This is the amount that would 

have been permitted had we been able 

to implement the biomass-based diesel 

requirements in 2009. In practice, this 

means that deficit carryovers from 2010 

into 2011 for biomass-based diesel 

cannot not exceed 57% (0.65/1.15) of an 

obligated party’s 2010 RVO. This 

approach also helps to ensure a 

minimum volume mandate for 

companies producing biomass-based 

diesel each year. 

Similarly, in the absence of any 

modifications to the provisions 

regarding valid life of RINs, 2008 

biodiesel and renewable diesel RINs 

could not be used for compliance in 

2010 with the adjusted biomass-based 

diesel standard, despite the fact that the 

2010 standard includes the 2009 

requirement for which 2008 RINs 

should be valid. The National Biodiesel 

Board opposed this approach on the 

basis that the use of 2008 RINs for 2010 

compliance demonstrations violated the 

2-year valid life limit for RINs. 

However, since the 2010 compliance 

demonstration will include the 

obligation that would have applied in 

2009, and 2008 RINs would be valid for 

2009 compliance, we are allowing 

excess 2008 biodiesel and renewable 

diesel RINs that were not used for 

compliance purposes in 2008 to be used 

for compliance purposes in 2009 or 

2010. 

As described in Section III.D, we are 

requiring the 20% RIN rollover cap to 

apply in all years, and separately for all 

four standards. However, consistent 

with our approach to deficit carryovers, 

we believe that an additional constraint 

is warranted in the application of the 

rollover cap to the biomass-based diesel 

obligation in the 2010 compliance year 

to more closely represent what would 

have occurred if we had been able to 

implement the 0.5 bill gal requirement 

in 2009. Specifically, we are limiting the 

use of excess 2008 RINs to 20% of the 

statutory 2009 requirement of 0.5 bill 

gal. This is equivalent to 0.1 bill gal 

(20% of 0.5 bill gal), or 8.7% of the 

combined 2009/2010 obligation of 1.15 

bill gal (0.1/1.15). Thus, obligated 

parties will be allowed to use excess 

2008 and 2009 biodiesel and renewable 

diesel RINs for compliance with the 

2010 combined standard of 1.15 bill gal, 

so long as the sum of all previous-year 

RINs (2008 plus 2009 RINs) does not 

exceed 20% of their 2010 obligation, 

and the 2008 RINs do not exceed 8.7% 

of their 2010 obligation. 

Under RFS1, RINs are generated when 

renewable fuel is produced, but if the 

fuel is ultimately used for purposes 

other than as motor vehicle fuel the 

RINs must generally be retired. Under 

EISA, however, RINs generated for 

renewable fuel that is ultimately used 

for nonroad purposes, heating oil, or jet 

fuel are valid for compliance purposes. 

To more closely align our transition 

approach for biomass-based diesel to 

what could have occurred if we had 

issued the RFS2 standards prior to 2009, 

we are allowing 2009 RINs that are 

retired because they are ultimately used 

for nonroad, heating oil or jet fuel 

purposes to be valid for compliance 

with the 2010 standards. Such RINs can 

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14720 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

21EPA’s diesel fuel regulations use the term 

‘‘nonroad’’ to designate one large category of land 

based off-highway engines and vehicles, 

recognizing that locomotive and marine engines 

and vessels are also nonroad engines and vehicles 

under EPAct’s definition of nonroad. Except where 

be reinstated by the retiring party in 

2010. 

3. Future Standards 

The statutorily-prescribed phase-in 

period ends in 2012 for biomass-based 

diesel and in 2022 for cellulosic biofuel, 

advanced biofuel, and total renewable 

fuel. Beyond these years, EISA requires 

EPA to determine the applicable 

volumes based on a review of the 

implementation of the program up to 

that time, and an analysis of a wide 

variety of factors such as the impact of 

the production of renewable fuels on the 

environment, energy security, 

infrastructure, costs, and other factors. 

For these future standards, EPA must 

promulgate rules establishing the 

applicable volumes no later than 14 

months before the first year for which 

such applicable volumes would apply. 

For biomass-based diesel, this would 

mean that final rules would need to be 

issued by October 31, 2011 for 

application starting on January 1, 2013. 

In today’s 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. These provisions will be 

implemented as part of an annual 

standard-setting process. 

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 all 

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 II.G below, 

under this rule, the sum of all highway 

and nonroad gasoline and diesel fuel 

produced or imported within a calendar 

year will be the basis on which the 

RVOs are calculated. This section 

provides our final definition of gasoline 

and diesel for the purposes of the RFS2 

program. 

1. Gasoline 

As with the RFS1 rule, the volume of 

gasoline used in calculating the RVO 

under RFS2 will 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 includes 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) or exported 

gasoline, will 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 will 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 will 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 including in 

a party’s obligated volume are 

collectively called ‘‘gasoline.’’ 

Also consistent with the RFS1 

program, we are continuing the 

exclusion of any volume of renewable 

fuel contained in gasoline from the 

volume of gasoline used to determine 

the renewable fuels obligations. This 

exclusion applies 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 will 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 the statute, and EPA excludes ethanol 

and other renewable fuels that are 

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 rule, Gasoline 

Treated as Blendstock (GTAB) will 

continue to be treated as a blendstock 

under the RFS2 program, and thus will 

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, 

will 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 will 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 will be included 

in the volume of gasoline used to 

determine the renewable fuel obligation. 

2. Diesel 

EISA expanded the RFS program to 

include transportation fuels other than 

gasoline, thus both highway and 

nonroad diesel must be used in 

calculating a party’s RVO. Any party 

that produces or imports petroleumbased diesel fuel that is designated as 

motor vehicle, nonroad, locomotive, and 

marine diesel fuel (MVNRLM) (or any 

subcategory of MVNRLM) will be 

required to include the volume of that 

diesel fuel in the determination of its 

RVO under the RFS2 rule. Diesel fuel 

includes 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 fuel produced for use in 

highway diesel engines and vehicles), 

NRLM (diesel fuel produced for use in 

nonroad, locomotive, and marine diesel 

engines and equipment/vessels), NR 

(diesel fuel produced for use in nonroad 

engines and equipment), and LM (diesel 

fuel produced for use in locomotives 

and marine diesel engines and 

vessels).21 Transportation fuels meeting 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14721 

noted, the discussion of nonroad in reference to 

transportation fuel includes the entire category 

covered by EPAct’s definition of nonroad. 

22See 40 CFR 80.598(a) for the kinds of fuel types 

used by refiners or importers in designating their 

diesel fuel. 

the definition of MVNRLM will be used 

to calculate the RVOs, and refiners, 

blenders, or importers of MVNRLM will 

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, will not be subject to the 

applicable percentage standard and will 

not be used to calculate the RVOs.22 We 

requested 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. 

One commenter expressed support for 

including heating oil and jet fuel into 

the RIN program, but not to subject 

these fuels to the RVO mandate. The 

commenter stated that fluctuating 

weather conditions make it hard to 

predict with any reliability the volumes 

of heating oil that will be used in a 

given year. Another commenter stated 

that it supports the extension of the RFS 

program to transportation fuels, 

including diesel and nonroad fuels. 

With respect to fuels for use in oceangoing vessels, EISA specifies that 

‘‘transportation fuels’’ do not include 

such fuels. We are interpreting that 

‘‘fuels for use in ocean-going vessels’’ 

means residual or distillate fuels other 

than MVNRLM intended to be used to 

power large ocean-going vessels (e.g., 

those vessels that are powered by 

Category 3 (C3), and some Category 2 

(C2), marine engines and that operate 

internationally). Thus, fuel for use in 

ocean-going vessels, or that an obligated 

party can verify as having been used in 

an ocean-going vessel, will be excluded 

from the renewable fuel standards. Also, 

in the context of the recently finalized 

fuel standards for C3 marine vessels, 

this would mean that fuel meeting the 

1,000 ppm fuel sulfur standard would 

not be considered obligated volume, 

while all MVNRLM diesel fuel would. 

3. Other Transportation Fuels 

Transportation fuels other than 

gasoline or MVNRLM diesel fuel 

(natural gas, propane, and electricity) 

will 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 

portion used in the transportation sector 

from the large portion used in other 

sectors (in fact, the producer may have 

no knowledge of its ultimate use). We 

will reconsider this approach if and 

when these volumes grow. At the same 

time, it is clear that these fuels can be 

used as transportation fuel, and under 

certain circumstances, producers of 

such ‘‘other transportation fuels’’ may 

generate RINs as a producer or importer 

of a renewable fuel. See Section II.D.2.a 

for further discussion of other RINgenerating fuels. 

G. Renewable Volume Obligations 

(RVOs) 

Under RFS1, each obligated party was 

required to determine its RVO based on 

the applicable percentage standard and 

its annual gasoline volume. The RVO 

represented the volume of renewable 

fuel that the obligated party was 

required to ensure was used in the U.S. 

in a given calendar year. Obligated 

parties were required to meet their RVO 

through the accumulation of RINs 

which represent the amount of 

renewable fuel used as motor vehicle 

fuel that was sold or introduced into 

commerce within the U.S. Each gallonRIN counted as one gallon of renewable 

fuel for compliance purposes. 

We are maintaining this approach to 

compliance under the RFS2 program. 

However, one primary difference 

between RFS1 and the new RFS2 

program in terms of demonstrating 

compliance is that each obligated party 

now has four RVOs instead of one 

(through 2012) or two (starting in 2013) 

under the RFS1 program. Also, as 

discussed above, RVOs are now 

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 

deemed to have satisfied their obligation 

to cause the renewable fuel represented 

by the RINs to be consumed as 

transportation fuel in highway or 

nonroad vehicles or engines. Obligated 

parties are not required to physically 

blend the renewable fuel into gasoline 

or diesel fuel themselves. The 

accumulation of RINs will 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 can retain the excess 

RINs for use in complying with its RVOs 

in the following year (subject to the 20% 

rollover cap discussed in Section III.D) 

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 can carry a deficit into the 

next year. 

This section describes our approach 

to the calculation of RVOs under RFS2 

and the RINs that are valid for 

demonstrating compliance with those 

RVOs. This includes a description of the 

special treatment that must be applied 

to RFS1 RINs used for compliance 

purposes under RFS2, since RINs 

generated under RFS1 regulations are 

not exactly the same as those generated 

in under RFS2. 

1. Designation of Obligated Parties 

In the NPRM, we proposed to 

continue to designate obligated parties 

under the RFS2 program as they were 

designated under RFS1, with the 

addition of diesel fuel producers and 

importers. Regarding gasoline producers 

and importers, we proposed that 

obligated parties who are subject to the 

standard would be 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 would 

include 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, would not be included in the 

volume used to determine the RVO, 

except where the blendstock was 

combined with other blendstock or 

finished gasoline to produce finished 

gasoline, RBOB, or CBOB. Thus, parties 

downstream of a refinery or importer 

would only be obligated parties to the 

degree that they use non-renewable 

blendstocks to make finished gasoline, 

RBOB, CBOB, or diesel fuel. 

We also took comment on two 

alternative approaches to the 

designation of obligated parties: 

—Elimination of 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 nonrenewable volume of finished 

gasoline or diesel that he produces or 

imports, thereby moving a portion of 

the obligation to downstream blenders 

of renewable fuels into RBOB and 

CBOB. 

—Moving the obligations for all gasoline 

and diesel downstream of refineries 

and importers to parties who supply 

finished transportation fuels to retail 

outlets or to wholesale purchaserconsumer facilities. 

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14722 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

23As discussed above, the diesel fuel that is used 

to calculate the RVO is any diesel designated as 

MVNRLM or a subcategory of MVNRLM. 

These alternative approaches have the 

potential to more evenly align a party’s 

access to RINs with that party’s 

obligations under the RFS2 program. As 

described more fully in the NPRM, we 

considered these alternatives because of 

market conditions that had changed 

since the RFS1 program began. For 

instance, obligated parties who have 

excess RINs have been observed to 

retain rather than sell them to ensure 

they have a sufficient number for the 

next year’s compliance. This was most 

likely to occur with major integrated 

refiners who operate gasoline marketing 

operations and thus have direct access 

to RINs for ethanol blended into their 

gasoline. Refiners whose operations are 

focused primarily on producing refined 

products with less marketing do not 

have such direct access to RINs and 

could potentially find it difficult to 

acquire a sufficient number for 

compliance despite the fact that the 

total nationwide volume of renewable 

fuel meets or exceeds the standard. The 

result might be a higher price for RINs 

(and fuel) in the marketplace than 

would be expected under a more liquid 

RIN market. For similar reasons, we also 

took comment on possible changes to 

the requirement that RINs be transferred 

with volume through the distribution 

system as discussed more fully in 

Section II.H.4. 

In response to the NPRM, 

stakeholders differed significantly on 

whether EPA should implement one of 

these alternative approaches. For 

instance, while some refiners expressed 

support for moving the obligations to 

downstream parties such as blenders, 

terminals, and/or wholesale purchaserconsumers, other refiners preferred to 

maintain the current approach. Blenders 

and other downstream parties generally 

expressed opposition to a change in the 

designation of obligated parties, citing 

the additional burden of demonstrating 

compliance with the standard especially 

for small businesses. They also pointed 

to the need to implement new systems 

for determining and reporting 

compliance, the short leadtime for doing 

so, and the fewer resources that smaller 

downstream companies have to manage 

such work in comparison to the much 

larger refiners. Finally, they pointed to 

the additional complexity that would be 

added to the RFS program beyond that 

which is necessary to carry out the 

renewable fuels mandate under CAA 

section 211(o). 

When the RFS1 regulations were 

drafted, the obligations were placed on 

the relatively small number of refiners 

and importers rather than on the 

relatively large number of downstream 

blenders and terminals in order to 

minimize the number of regulated 

parties and keep the program simple. 

However, with the expanded RFS2 

mandates, essentially all downstream 

blenders and terminals are now 

regulated parties under RFS2 since 

essentially all gasoline will be blended 

with ethanol. Thus the rationale in 

RFS1 for placing the obligation on just 

the upstream refiners and importers is 

no longer valid. Nevertheless, based on 

the comments we received, we do not 

believe that the concerns expressed 

warrant a change in the designation of 

obligated parties for the RFS2 program 

at this time. We continue to believe that 

the market will provide opportunities 

for parties who are in need of RINs to 

acquire them from parties who have 

excess. Refiners who market 

considerably less gasoline or diesel than 

they produce can establish contracts 

with splash blenders to purchase RINs. 

Such refiners can also purchase ethanol 

from producers directly, separate the 

RINs, and then sell the ethanol without 

RINs to blenders. Since the RFS 

program is based upon ownership of 

RINs rather than custody of volume, 

refiners need never take custody of the 

ethanol in order to separate RINs from 

volumes that they own. Moreover, a 

change in the designation of obligated 

parties would result in a significant 

change in the number of obligated 

parties and the movement of RINs, 

changes that could disrupt the operation 

of the RFS program during the transition 

from RFS1 to RFS2. 

We will continue to evaluate the 

functionality of the RIN market. Should 

we determine that the RIN market is not 

operating as intended, driving up prices 

for obligated parties and fuel prices for 

consumers, we will consider revisiting 

this provision in future regulatory 

efforts. 

In the NPRM we also took comment 

on several other possible ways to help 

ensure that obligated parties can 

demonstrate compliance. For instance, 

one alternative approach would have 

left our proposed definitions for 

obligated parties in place, but would 

have added 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. 

Stakeholders generally opposed this 

change, agreeing with our assessment 

that it would be extremely difficult to 

implement given that RBOB and CBOB 

are often transferred between multiple 

parties prior to ethanol blending. As a 

result, a regulatory requirement for RIN 

transfers back to the original producer 

would have necessitated 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 have not 

finalized this alternative approach. 

Another alternative approach on 

which we took comment would have 

allowed use of RINs that expire without 

being used for compliance by an 

obligated party to be used to reduce the 

nationwide volume of renewable fuel 

required in the following year. This 

alternative approach could have helped 

to prevent the hoarding of RINs from 

driving up demand for renewable fuel. 

However, it would also effectively alter 

the valid life limit for RINs. Comments 

from stakeholders did not change our 

position that such an approach is not 

warranted at this time, and thus we 

have not finalized it. 

2. Determination of RVOs 

Corresponding to the Four Standards 

In order for an obligated party to 

demonstrate compliance, the percentage 

standards described in Section II.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 will 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 follows the same format as the 

formulas in the RFS1 regulations at 

§ 80.1107(a), with one modification. The 

standards for a particular compliance 

year must 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 RFS1 

program.23 To the degree that an 

obligated party did not demonstrate full 

compliance with its RVOs for the 

previous year, the shortfall will 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 each of 

its RVOs including the deficit carryover 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14723 

24Note that we are finalizing an exception to this 

general prohibition for the specific and limited case 

of 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 II.E.2.a. 

in the second year. Thus deficit 

carryovers cannot occur two years in 

succession for any of the four individual 

standards. They can, however, occur as 

frequently as every other year for a 

given obligated party for each standard. 

Note that a party that produces only 

diesel fuel will have an obligation for all 

four standards even though he will 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 will not have an opportunity 

to blend biomass-based diesel into his 

own diesel fuel. 

3. 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 can be used to meet 

each of the four standards. 

As described in Section I.A.1, the 

volume requirements in EISA are 

generally nested within one another, so 

that any fuel that satisfies the advanced 

biofuel requirement also satisfies the 

total renewable fuel requirement, and 

fuel that meets either the cellulosic 

biofuel or the biomass-based diesel 

requirements also satisfies the advanced 

biofuel requirement. As a result, the 

RINs that can be used to meet the four 

standards are likewise nested. Using the 

D codes defined in Table II.A–1, the 

RFS2 RINs that can be used to meet 

each of the four standards are shown in 

Table II.G.3–1. RFS1 RINs generated in 

2010 and identified by a D code of 1 or 

2 can also be applied to these standards 

using the protocol described in Section 

II.G.4 below. 

TABLE II.G.3–1—RINS THAT CAN BE USED TO MEET EACH STANDARD

Standard Obligation Allowable D 

codes 

Cellulosic biofuel ....................................................................... RVOCB ...................................................................................... 3 and 7. 

Biomass-based diesel ............................................................... RVOBBD .................................................................................... 4 and 7. 

Advanced biofuel ....................................................................... RVOAB ...................................................................................... 3, 4, 5, and 7. 

Renewable fuel .......................................................................... RVORF ....................................................................................... 3, 4, 5, 6, and 7. 

The nested nature of the four 

standards also means that in some cases 

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 3 can be used to meet 

three of the four standards, while a RIN 

with a D code of 5 can be used to meet 

both the advanced biofuel and total 

renewable fuel standards. However, a D 

code of 6 can only be used to meet the 

renewable fuel standard. Consistent 

with our proposal, we are continuing to 

prohibit the use of a single RIN for 

compliance purposes in more than one 

year or by more than one party.24

4. Treatment of RFS1 RINs Under RFS2 

As described in the introduction to 

this section, we are implementing a 

number of changes to the RFS program 

as a result of the requirements in EISA. 

These changes will go into effect on July 

1, 2010 and, among other things, will 

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 these 

RFS2 regulations will not be exactly the 

same as RINs generated under RFS1 

regulations. 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. Also, since RINs 

generated in January through June of 

2010 will be generated under RFS1 

regulations, we must provide a means 

for them to be used to meet the annual 

2010 RFS2 standards. Finally, we must 

address deficit carryovers from 2009 to 

2010, since the total renewable fuel 

standards in these two years will be 

defined differently. 

a. Use of RFS1 RINs To Meet Standards 

Under RFS2 

In 2009 and the first three months of 

2010, 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 under 

RFS1 regulations meet any of these 

criteria. However, we believe that the 

vast majority of RFS1 RINs generated in 

2009 and the first two months of 2010 

will 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 

and the first three months of 2010 will 

meet the prerequisites for this 

exemption. Second, it is unlikely that 

renewable fuels produced in 2009 or the 

first three months of 2010 will have 

been made from feedstocks that do not 

meet the new renewable biomass 

definition. It is very unlikely that new 

land would have been cleared or 

cultivated since December 19, 2007 for 

use in growing crops for renewable fuel 

production, and thus the land use 

restrictions associated with the 

renewable biomass definition will very 

likely be met. 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 RFS1 RINs generated in 2009 and 

early 2010 to be valid to show 

compliance for the annual 2010 

obligations. 

The separate definitions for cellulosic 

biofuel and biomass-based diesel 

require GHG thresholds of 60% and 

50%, respectively. While we do not 

have a mechanism in place to determine 

if these thresholds have been met for 

RFS1 RINs generated in 2009 or early 

2010, any shortfall in GHG performance 

for this one transition period is unlikely 

to have a significant impact on longterm GHG benefits of the program. Few 

stakeholders commented on our 

proposed treatment of RFS1 RINs under 

RFS2. Of those that did, most supported 

our proposed approach to the use of 

RFS1 RINs to meet RFS2 obligations. 

Based on our belief that it is critical to 

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14724 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

25There is no cellulosic biofuel standard for 2010. 

26EISA, Title II, Subtitle A—Renewable Fuel 

Standard, Section 201. 

the smooth operation of the program 

that excess 2009 RINs be allowed to be 

used for compliance purposes in 2010, 

we are allowing RFS1 RINs that were 

generated in 2009 or 2010 representing 

cellulosic biomass ethanol to be valid 

for use in satisfying the 2010 cellulosic 

biofuel standard. Likewise, we are 

allowing RFS1 RINs that were generated 

in 2009 or 2010 representing biodiesel 

and renewable diesel to be valid for use 

in satisfying the 2010 biomass-based 

diesel standard. 

Consistent with our proposal, we have 

used 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 under RFS1 

regulations must be identified with a D 

code of 1, and these fuels will be valid 

for meeting the cellulosic biofuel 

standard under RFS2. Our final 

treatment of RFS1 RINs for compliance 

under RFS2 is shown in Table II.G.4.a– 

1. 

TABLE II.G.4.a–1—TREATMENT OF RFS1 RINS FOR RFS2 COMPLIANCE PURPOSES

RINs generated under RFS1 a Treatment under RFS2 b

Any RIN with D code of 2 and RR code of 15 or 17 ...................................................................... Equivalent to RFS2 RINs with D code of 4. 

All other RINs with D code of 2 ...................................................................................................... Equivalent to RFS2 RINs with D code of 6. 

Any RIN with D code of 1 ............................................................................................................... Equivalent to RFS2 RINs with D code of 3. 

a See RFS1 RIN code definitions at § 80.1125. b See RFS2 RIN code definitions at § 80.1425. 

b. Deficit Carryovers From the RFS1 

Program to RFS2 

The calculation of RVOs in 2010 

under the RFS2 regulations will be 

somewhat different than the calculation 

of RVOs in 2009 under RFS1. In 

particular, 2009 RVOs were based on 

gasoline production only, while 2010 

RVOs will 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 will undermine 

the goals of the program in requiring 

specific volumes of renewable fuel to be 

used each year. Although RVOs in 2009 

and 2010 will 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 implementing any special 

treatment for deficits carried over from 

2009 to 2010. 

A deficit carried over from 2009 to 

2010 will only affect a party’s total 

renewable fuel obligation in 2010, as the 

2009 obligation is for total renewable 

fuel use, not a subcategory. The RVOs 

for biomass-based diesel or advanced 

biofuel will not be affected, as they do 

not have parallel obligations in 2009 

under RFS1.25

H. Separation of RINs 

As we proposed in the NPRM, we are 

requiring the RFS1 provisions regarding 

the separation of RINs from volumes of 

renewable fuel to be retained for RFS2. 

However, the modifications in EISA 

required changes 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 were required 

to be retired by the party who owned 

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. However, EISA 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 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. 

Since RINs have a valid life of two 

years, the NPRM proposed that a 2009 

RFS1 RIN that is retired because the 

renewable fuel associated with it was 

used in nonroad vehicles or engines 

could be reinstated in 2010 for use in 

compliance with the 2010 standards. 

Stakeholders supported this approach, 

and we are finalizing it in today’s 

action. 

2. Heating Oil and Jet Fuel 

EISA defines ‘‘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.’’ 26 While we are not requiring 

fossil-based heating oil and jet fuel to be 

included in the fuel used by a refiner or 

importer to calculate their RVOs, we are 

allowing renewable fuels used as or in 

heating oil and jet fuel to generate RINs. 

Similarly, RINs associated with a 

renewable fuel, such as biodiesel, that is 

blended into heating oil will continue to 

be valid for compliance purposes. See 

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

3. Exporters 

Under RFS1, exporters were assigned 

an RVO representing the volume of 

renewable fuel that was exported, and 

they were required to separate all RINs 

that were assigned to fuel that was 

exported. Since there was only one 

standard, there was 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, and total renewable fuel). 

However, given the fungible nature of 

the RIN system and the fact that an 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14725 

assigned RIN transferred with a volume 

of renewable fuel may not be the same 

RIN that was originally generated to 

represent that volume, RINs from 

different fuel types can accompany 

volumes. Thus, there may be no way for 

an exporter to determine from an 

assigned RIN which of the four 

categories applies to an exported 

volume. In order to determine its RVOs, 

the only information available to the 

exporter may be the type of renewable 

fuel that he is exporting. 

However, if an exporter knows, or has 

reason to know, that the renewable fuel 

that it is exporting is either cellulosic 

biofuel or advanced biofuel, we are 

requiring the exporter to determine an 

RVO for the exported fuel based upon 

these fuel types. For instance, if an 

exporter purchases cellulosic biofuel or 

advanced biofuel directly from a 

producer or if the fuel has been 

segregated from other fuels, we would 

expect the exporter to know or have 

reason to know the type of fuel that it 

is exporting. Another example of when 

we would expect an exporter to know or 

have reason to know that the fuel that 

it is exporting is cellulosic or advanced 

biofuel would be if the commercial 

documents that accompany the 

purchase or sale of the renewable fuel 

identify the product as cellulosic or 

advanced biofuel. 

EPA recognizes that in many 

situations, exporters will not know or 

have reason to know which of the four 

categories of renewable fuel apply to the 

exported fuel. If this is the case, we are 

requiring exporters to follow the 

approach proposed in the NPRM. 

Exported volumes of biodiesel (mono 

alkyl esters) and renewable diesel must 

be used to determine the exporter’s RVO 

for biomass-based diesel. For all other 

types of renewable fuel, the most likely 

category is general renewable fuel. 

Thus, we are requiring that all 

renewable fuels be used to determine 

the exporter’s RVO for total renewable 

fuel. Our final approach is provided at 

§ 80.1430. 

In the NPRM we took comment on an 

alternative approach in which the total 

nationwide volumes required in each 

year (see Table I.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, as 

described in the NPRM, we believe that 

this alternative approach would have 

added considerable complexity to the 

compliance determinations for exporters 

without necessarily adding more 

precision. Given the expected small 

volumes of exported renewable fuel, we 

continue to believe that this added 

complexity is not warranted at this time. 

As described above, exporters must 

separate any RINs assigned to renewable 

fuel that they export. However, since 

RINs are fungible and the owner of a 

batch of renewable fuel has the 

flexibility to assign between zero and 

2.5 gallon-RINs to each gallon, we have 

made this flexibility explicit for 

exporters. Thus, an exporter can 

separate up to 2.5 gallon-RINs for each 

gallon of renewable fuel that he exports. 

While the exporter is not required to 

retain these separated RINs for use in 

complying with his RVOs calculated on 

the basis of the exported volumes, this 

would be the most straightforward 

approach and would ensure that the 

exporter has sufficient RINs to comply. 

However, we are aware of some 

exporters who sell RINs that they 

separate as a source of revenue, with the 

intention to purchase replacement RINs 

on the open RIN market later in the year 

to comply with their RVOs. At this time 

we are not aware of such activities 

resulting in noncompliance, and thus 

the RFS2 regulations promulgated today 

will continue to allow this. However, 

we may revisit this issue in the future 

if there is evidence that exporters are 

failing to comply because they are 

selling RINs that they separate from 

exported volumes. 

4. Requirement To Transfer RINs With 

Volume 

In the NPRM, we proposed that the 

approach to RIN transfers established 

under RFS1—that RINs generated by 

renewable fuel producers and importers 

must be assigned to batches of 

renewable fuel and transferred along 

with those batches—be continued under 

RFS2. However, given the higher 

volumes required under RFS2 and the 

resulting expansion in the number of 

regulated parties, we also took comment 

on two alternative approaches to RIN 

transfers. Along with the alternative 

approaches for designation of obligated 

parties as described in Section II.G.1 

above, a change to the requirement to 

transfer RINs with batches had the 

potential to more evenly align a party’s 

access to RINs with that party’s 

obligations under the RFS2 program. 

Nevertheless, for the reasons described 

below, we have determined that it 

would not be appropriate to implement 

these alternative approaches at this 

time. 

In the first alternative approach, we 

would have removed 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 have 

sold RINs (with a K code of 2 rather 

than 1) separately from volumes of 

renewable fuel to any party. 

In the second alternative approach, 

producers and importers of renewable 

fuels would be required to separate and 

transfer the RIN, but only to an 

obligated party. 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. Any RINs not sold in 

this way would be required to be offered 

for sale to any obligated party through 

a public auction. Only renewable fuel 

producers, importers, and obligated 

parties would be allowed to own RINs. 

Many renewable fuel producers 

supported the concept of allowing them 

to separate the RINs from renewable fuel 

that they produce. They generally 

argued in favor of a free market 

approach to RINs in which there would 

be no restrictions on whom they could 

sell RINs to, or in what timeframe. The 

direct transfer approach was 

unnecessary, they argued, since the 

market would compel them to sell all 

RINs they generated, and all RINs would 

eventually end up in the hands of the 

obligated parties that need them. 

However, other renewable fuel 

producers opposed any change to the 

requirement that RINs be assigned to 

volumes of renewable and transferred 

with those volumes through the 

distribution system. They argued that 

the system established under RFS1 has 

proven to work and it would create an 

unwarranted burden to require 

producers to modify their IT systems for 

RFS2. 

Marketers and distributors were 

generally opposed to our proposed 

alternative approaches to RIN transfers. 

Moreover, SIGMA and NACS, as in the 

RFS1 rulemaking process, 

recommended that RINs not be 

generated by producers at all, but rather 

by the party that blends renewable fuel 

into gasoline or diesel, or uses 

renewable fuel in its neat form as a 

transportation fuel. 

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14726 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

Obligated parties generally opposed 

any change to the RFS1 requirement 

that RINs be assigned to volumes of 

renewable fuel by the producer or 

importer, and transferred with volumes 

through the distribution system. They 

reiterated their concern, first raised in 

the RFS1 rulemaking, that a free market 

approach would place them at greater 

risk of market manipulation by 

renewable fuel producers. Moreover, 

while generally expressing support for 

the concept of a direct transfer 

approach, they also expressed doubt 

that the auctions could be regulated in 

such a way as 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. These concerns 

were exacerbated by the nested 

standards required by EISA, under 

which many obligated parties have 

expressed concern about being able to 

acquire sufficient RINs for compliance. 

Given the significant challenges 

associated with a change to the 

requirement that RINs be transferred 

with volume and the opposing views 

among stakeholders, we are not making 

any change in today’s final rule. 

5. Neat Renewable Fuel and Renewable 

Fuel Blends Designated as 

Transportation Fuel, 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. 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. While EPA 

understands that in the vast majority of 

cases, biodiesel is blended with diesel 

in concentrations of 80 volume percent 

or less, there may be instances in which 

biodiesel is blended with diesel in 

concentrations of more than 80 percent 

biodiesel, but the blender is prohibited 

from separating RINs under the RFS1 

regulations. 

Thus, in order to account for 

situations in which biodiesel blends of 

81 percent or greater may be used as 

transportation fuel, heating oil, or jet 

fuel without ever having been owned by 

an obligated party, EPA proposed, and 

is finalizing a change to the 

applicability of the RIN separation 

provisions for RFS2. Section 

80.1429(b)(4) will allow for separation 

of RINs for neat renewable fuel or 

blends of renewable fuel and diesel fuel 

that the party designates as 

transportation fuel, heating oil, or jet 

fuel, provided the neat renewable fuel 

or blend is used in the designated form, 

without further blending, as 

transportation fuel, heating oil, or jet 

fuel. Those parties that blend renewable 

fuel with gasoline or diesel fuel (in a 

blend containing 80 percent or less 

biodiesel) must separate RINs pursuant 

to § 80.1429(b)(2). 

Thus, for example, if a party intends 

to separate RINs from a volume of B85, 

the party must designate the blend for 

use as transportation fuel, heating oil, or 

jet fuel and the blend must be used in 

its designated form without further 

blending. The party is also required to 

maintain records of this designation 

pursuant to § 80.1454(b)(5). Finally, the 

party is required to comply with the 

proposed PTD requirements in 

§ 80.1453(a)(11)(iv), which serve to 

notify downstream parties that the 

volume of fuel has been designated for 

use as transportation fuel, heating oil, or 

jet fuel, and must be used in that 

designated form without further 

blending. Parties may separate RINs at 

the time they comply with the 

designation and PTD requirements, and 

do not need to physically track ultimate 

fuel use. 

I. Treatment of Cellulosic Biofuel 

1. Cellulosic Biofuel Standard 

EISA requires 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 based on EIA 

estimates 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 

total renewable fuel and advanced 

biofuels requirement by the same or a 

lesser volume. We will examine EIA’s 

projected volumes and other available 

data including the required production 

outlook reports discussed in Section II.K 

to decide the appropriate standard for 

the following year. The outlook reports 

from all renewable fuel producers will 

assist EPA in determining what the 

cellulosic biofuel standard should be 

and if the total renewable fuel and/or 

advanced biofuel standards 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. 

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 may 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. 

Thus, the Act requires EPA to examine 

the total and advanced renewable fuel 

standards and volumes in the event of 

a cellulosic volume waiver. EPA will 

look at projections for each year on an 

individual yearly basis to determine if 

the standards should be adjusted. EPA 

believes that since the standards are 

nested and the total and advanced 

renewable fuel volume mandates are 

met in part by the cellulosic volume 

mandate, Congress gave EPA the 

flexibility to lower the required total 

and advanced volumes, but Congress 

also wanted to encourage the 

development of advanced renewable 

fuels as well and allow in appropriate 

circumstances for the use of those fuels 

in the event they can meet that year’s 

required volumes that would have been 

met by the cellulosic mandate. 

2. EPA Cellulosic Biofuel Waiver 

Credits for Cellulosic Biofuel 

Whenever EPA sets the cellulosic 

biofuel standard at a level lower than 

that required in EISA, but greater than 

zero, 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. The inflation 

adjustment will be based on the 

standard US inflation measure 

Consumer Price Index for All Urban 

Consumers (CPI–U) for All Items 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14727 

27See U.S. Department of Labor, Bureau of Labor 

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

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

28More 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/hist/ 

LeafHandler.ashx?n=PET&s=A103B00002&f=M. 

expenditure category as provided by the 

Bureau of Labor Statistics.27

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.’’ 

We have fashioned a number of 

limitations on the use of cellulosic that 

reflect these considerations. 

Specifically, the credits will be called 

‘‘Cellulosic Biofuel Waiver Credits’’ (or 

‘‘waiver credits’’) so that there is no 

confusion with RINs or allowances used 

in the acid rain program. Such waiver 

credits will only be available for the 

current compliance year for which we 

have waived some portion of the 

cellulosic biofuel standard, they will 

only be available to obligated parties, 

and they will be nontransferable and 

nonrefundable. Further, obligated 

parties may only purchase waiver 

credits up to the level of their cellulosic 

biofuel RVO less the number of 

cellulosic biofuel RINs that they own. A 

company owning cellulosic biofuel RINs 

and cellulosic waiver credits may use 

both types of credits if desired to meet 

their RVOs, but unlike RINs obligated 

parties will not be able to carry waiver 

credits over to the next calendar year. 

Obligated parties may not use waiver 

credits to meet a prior year deficit 

obligation. These restrictions help 

ensure that waiver credits are not 

overutilized at the expense of actual 

renewable volume. 

In the NPRM, EPA proposed that the 

credits could be usable for the advanced 

and total renewable standards similarly 

to cellulosic biofuel RINs. Several 

commenters stated this provision could 

displace advanced and total renewable 

fuel that was actually produced which 

would be against the intent of the Act, 

and that unlike RINs a company should 

only be permitted to use waiver credits 

to meet its cellulosic biofuel obligation. 

We agree, and are limiting the use of 

waiver credits for compliance with only 

a company’s cellulosic biofuel RVO. 

In the event the total volume of 

conventional gasoline and diesel fuel 

produced or imported in the country 

exceeds the projections used to set the 

standard, companies will still be able to 

purchase waiver credits up to their 

cellulosic volume obligation. When 

setting a reduced cellulosic biofuel 

standard EPA makes a determination 

that the cellulosic volume specified in 

EISA will not be met and that 

determination is not based on how 

much nonrenewable motor fuel will be 

produced. EPA sets the standard based 

on the volumes in the Act and a 

projection of gasoline production to 

ensure the obligation is broken up most 

equitably. EPA believes that Congress 

wanted all obligated parties to have 

equal access to the waiver credits in the 

event of the waiver and did not want 

obligated parties to incur a deficit due 

to the timing of when they purchased 

waiver credits. 

Cellulosic Biofuel Waiver Credits, in 

the event of a waiver, will be offered in 

a generic format rather than a serialized 

format, like RINs. Waiver credits can be 

purchased using procedures defined by 

the EPA, and 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. EPA will define 

these procedures with the U.S. Treasury 

before the end of the first annual 

compliance period. EPA will publish 

these procedures with the obligated 

party annual compliance report 

template. EPA will provide the forms 

necessary to purchase the credits. EPA 

intends to provide options for obligated 

parties to use Pay.Gov or if desired to 

mail payment to the U.S. Treasury. 

The wholesale price of gasoline used 

by EPA in setting the price of the waiver 

credits 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 

available to EPA at the time it develops 

the cellulosic biofuel standard.28 EPA 

will use refinery gate price, U.S. Total 

Gasoline Bulk Sales (Price) by Refiners 

from EIA in calculating the average, 

since it is the price most reflective of 

what most obligated parties are selling 

their fuel. EPA will use the most recent 

twelve months of data provided by EIA 

to develop an average price on actual 

volumes produced in the year prior to 

the compliance year. In order to provide 

regulatory certainty, we will set the 

waiver credits price for the following 

year each November when and if we set 

a cellulosic biofuel standard for the 

following year that is based on 

achieving a lower volume of cellulosic 

biofuel use than is specified in EISA. 

For the 2010 compliance period, since 

the cellulosic standard is lower than the 

level otherwise required by EISA, we 

are also making cellulosic waiver credits 

available to obligated parties for end-ofyear compliance should they need them 

at a price of $1.56 per gallon-RIN.’’ The 

price for the 2011 compliance period, if 

necessary will be set when we announce 

the 2011 cellulosic biofuel standard. 

3. Application of Cellulosic Biofuel 

Waiver Credits 

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 consequences. 

This could occur in situations where the 

cost of total renewable fuel RINs 

exceeds the cost of the cellulosic waiver 

credits. To prevent this, we sought 

comment on and are finalizing an 

additional restriction: An obligated 

party may only purchase waiver credits 

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 applying 

any waiver credits to their cellulosic 

biofuel RVO. 

Even with this restriction the 

approach in the NPRM might not have 

operated as intended. For instance, if 

the combination of cellulosic biofuel 

volume price and RIN price were to 

become low compared to that for 

general renewable fuel, a small number 

of obligated parties could have 

purchased more cellulosic biofuel than 

they need to meet their cellulosic 

biofuel RVOs and could have used the 

additional cellulosic biofuel RINs to 

meet their advanced biofuel and total 

renewable fuel RVOs. Other obligated 

parties would then have had no access 

to cellulosic biofuel volume nor 

cellulosic biofuel RINs, and would have 

been forced to purchase waiver credits 

from the EPA. This situation would 

have had the net effect of waiver credits 

replacing advanced biofuels and/or 

general renewable fuel rather than 

cellulosic biofuel. Based on comments 

received on the NPRM, EPA is placing 

the additional restriction of only 

allowing the waiver credits to count 

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14728 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

29The cellulosic biofuel RIN would be a 

separated RIN with a K code of 2 immediately upon 

generation. 

30For ease of reference, the current RFS (i.e. 

RFS1) form may be viewed at the EPA Fuels 

Reporting Web site at the following URL: http:// 

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

(accessed November 16, 2009). These forms will be 

updated for RFS2. 

31For RFS1, this form is numbered RFS0300. 

32For RFS1, this form is numbered RFS0400. 

towards the cellulosic biofuel standard 

and not the advanced or renewable fuel 

standards. 

Moreover, under certain conditions it 

may be possible for the market price of 

general renewable fuel 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 waiver credits 

according to the statutory formula 

described in Section II.I.2 above. Under 

some conditions, this could result in a 

competitive disadvantage for cellulosic 

biofuel in comparison to corn ethanol, 

for example. 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 will be larger than for 

cellulosic ethanol producers. Under 

these conditions, while obligated parties 

may still purchase cellulosic ethanol 

volume and its associated RINs rather 

than waiver credits, cellulosic ethanol 

producers will 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 waiver credits. 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. 

Finally, in the NPRM we sought 

comment on a ‘‘dual RIN’’ approach to 

cellulosic biofuel. In this approach, both 

cellulosic biofuel RINs (with a D code 

of 3) and waiver credits would have 

only been 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 5). The producer would have 

only been 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.29 The cellulosic biofuel 

and its attached advanced biofuel RIN 

would then have competed 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 have been effectively 

limited by the pricing formula for 

waiver credits as described in Section 

II.I.2. However, this approach would 

have been a more significant deviation 

from the RIN generation and transfer 

program structure that was developed 

cooperatively with stakeholders during 

RFS1. It would have provided 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. 

Therefore, EPA is treating the transfer of 

cellulosic RINs in the same manner as 

the other required volumes. 

J. Changes to Recordkeeping and 

Reporting Requirements 

1. Recordkeeping 

Recordkeeping, including product 

transfer documents (PTDs), will support 

the enforcement of the use of RINs for 

compliance purposes. Parties are 

afforded significant freedom with regard 

to the form that PTDs take. Product 

codes may be used as long as they are 

understood by all parties, but they may 

not be used for transfers to truck carriers 

or to retailers or wholesale purchaserconsumers. 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. Parties must 

keep copies of records that relate to 

program flexibilities, such as small 

business-oriented provisions. Upon 

request, parties are responsible for 

providing their records to the 

Administrator or the Administrator’s 

authorized representative. We reserve 

the right to request to receive 

documents in a format that we can read 

and use. 

In Section III.A. of this preamble, we 

describe an EPA–Moderated 

Transaction System (EMTS) for RINs. 

The new system allows for ‘‘real-time’’ 

recording of transactions involving 

RINs. 

2. Reporting 

Producers and importers who 

generate or take ownership of RINs shall 

submit RIN Transaction Reports 30 and/ 

or RIN Generation Reports quarterly. 

Renewable fuel exporters and obligated 

parties shall submit their RIN 

Transaction Reports quarterly, and RIN 

owners shall submit their RIN 

Transaction Reports quarterly. EMTS 

will be used by all parties to record ‘‘real 

time’’ generation of RINs and 

transactions involving RINs starting July 

1, 2010. ‘‘Real time’’ means recordation 

within five (5) business days of 

generation or any transaction involving 

a RIN. 

Quarterly reports are to be submitted 

on the following schedule. Quarterly 

reports include RIN Activity Reports 

and, with EMTS, simplified reporting 

and certification of the RIN Generation 

and RIN Transaction Reports. 

TABLE II.J–1—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. 

Annual reports (covering January 

through December) would continue to 

be due on February 28. The only annual 

report is the Obligated Party Annual 

Compliance Report.31

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. EMTS will 

also make use of the CDX environment. 

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 proposed 

several changes to the RIN Generation 

Report.32 We proposed 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. This final rule 

adopts the proposed approach. All 

renewable fuel producers and importers 

above 10,000 gallons per year must 

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 is 

required to certify that his feedstock 

meets the definition of ‘‘renewable 

biomass.’’ If RINs are not generated, the 

producer or importer must state the 

reason for not generating RINs, such as 

they have documentation that states that 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14729 

33For RFS1, this form is numbered RFS0200. 

34See ‘‘Regulation of Fuel and Fuel Additives: 

Renewable Fuel Standard Program,’’ 72 FR 23900, 

23949–23950 (May 1, 2007) for a detailed 

discussion of attest engagement requirements under 

RFS1. 

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 to generate RINs as a renewable 

fuel. For each batch of renewable fuel 

produced, we require information about 

the types and volumes of feedstock used 

and the types and volumes of coproducts 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. In this final rule, we adopt 

the approach set forth in the notice of 

proposed rulemaking. 

In addition, we proposed two changes 

for the RIN Transaction Report.33 First, 

for reports of RINs assigned to a volume 

of renewable fuel, the volume of 

renewable fuel must be reported. 

Second, RIN price information must be 

submitted for transactions involving 

both separated RINs and RINs assigned 

to a renewable volume. This 

information was not collected under 

RFS1, but because we believe this 

information has great programmatic 

value to EPA, we proposed to collect it 

for RFS2. As we explained in the 

proposed rule, price information 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. Our 

incomplete knowledge regarding RIN 

pricing for RFS1 adversely affected our 

ability to assess the general health and 

direction of the market and overall 

liquidity of RINs. Because we believe 

the inclusion of price information in 

reports will be beneficial to both EPA 

and to regulated parties, this final rule 

includes that information element in 

reports, as well as incorporating it as 

part of the ‘‘real time’’ transactional 

information collected via EMTS. 

3. Additional Requirements for 

Producers of Renewable Natural Gas, 

Electricity, and Propane 

In addition to the general reporting 

requirement listed above, we are 

requiring an additional item of reporting 

for producers of renewable 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 are responsible for 

filing the same reports as other 

producers of RIN-generating renewable 

fuels, we are requiring that additional 

reporting for these producers 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 RIN generation reports and then 

maintain appropriate records that 

further identify the purchaser and the 

details of the transaction. We are not 

requiring 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. 

4. 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. We 

have found the information in attest 

engagements submitted under RFS1 to 

be extremely valuable as a compliance 

monitoring tool. The approach adopted 

in this final rule is identical to the 

approach adopted under the RFS1 

program,34 although the universe of 

obligated parties and renewable fuels 

producers is broader under this final 

rule for RFS2. 

As with the RFS1 program, an attest 

engagement must be conducted by an 

individual who is a Certified Public 

Accountant (CPA) or Certified Internal 

Auditor (CIA), who is independent of 

the party whose records are being 

reviewed, and who will follow agreedupon procedures to determine whether 

underlying records, reported items, and 

transactions agree. The CPA or CIA will 

generate a report as to their findings. 

We have received numerous questions 

and comments related to how attest 

engagements apply to foreign companies 

and whether or not a foreign accountant 

may perform the required agreed-upon 

procedures. EPA will accept an attest 

engagement performed by a foreign 

accountant who holds an equivalent 

credential to an American CPA or CIA. 

A written explanation as to the foreign 

accountant’s qualifications and the 

equivalency of the credential must 

accompany the attest engagement. 

Producers of renewable fuels, 

obligated parties, exporters, and any 

party who owns RINs must arrange for 

an annual attest engagement. The attest 

engagement report for any given year 

must be submitted to EPA by no later 

than May 31 of the following year. 

Section 80.1464 of the regulations 

specifies the attest engagement 

procedures to be followed. 

K. Production Outlook Reports 

Under this program we are requiring 

the submission, starting in 2010, of 

annual production outlook reports from 

all domestic renewable fuel producers, 

foreign renewable fuel producers who 

register to generate RINs, and importers 

of renewable fuels. These production 

outlook reports will be similar in nature 

to the pre-compliance reports required 

under the Highway and Nonroad Diesel 

programs. These reports will 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 will require 

information on: (1) Strategic planning; 

(2) Planning and front-end engineering; 

(3) Detailed engineering and permitting; 

(4) Procurement and construction; (5) 

Commissioning and startup; (6) 

Projected volumes; (7) Contracts 

currently in place (feedstocks, sales, 

delivery, etc.); and (8) Whether or not 

feedstocks have been purchased. The 

first 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). In the proposed rule, 

we asked for comment on the first five 

project phases, and whether or not they 

were appropriate for renewable fuels 

production. We also proposed 

additional phases in order to provide 

better specificity for ascertaining 

industry status. EPA plans to use this 

information in order to provide annual 

summary reports regarding such 

planned capacity. 

The full list of requirements for the 

production outlook reports is provided 

in the regulations at § 80.1449. The 

information submitted in the reports 

will be used to evaluate the progress 

that the industry is making towards the 

renewable fuels volume goals mandated 

by EISA. They will help EPA set the 

annual cellulosic biofuel standard and 

consider whether waivers would be 

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14730 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

appropriate with respect to the 

advanced biofuel, biomass-based diesel, 

and total renewable fuel standards (see 

Section II.I of this preamble for more 

discussion on this). Production outlook 

reports will be due annually by March 

31 (except that for the year 2010, the 

report will be due September 1) and 

each annual report must provide 

projected information, including any 

updated information from the previous 

year’s report. 

As mentioned in the preamble to the 

proposed rule, EPA currently receives 

data on projected flexible-fuel vehicle 

(FFV) sales and conversions from 

vehicle manufacturers. These are 

helpful in providing EPA with 

information regarding the potential 

market for renewable fuels. We 

requested comment on whether we 

should 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, the 

extent to which such information is 

already publicly available or can be 

purchased from a proprietary source, 

and the extent to which such publicly 

available or purchasable data would be 

sufficient for EPA to make its 

determination. We further requested 

comment on the parties that should be 

required to report to EPA, and data 

requirements. We believe that publicly 

available information on E15, E85, and 

other refueling facilities is sufficient for 

us to make a determination about the 

adequacy of such facilities to support 

the projected volumes that would be 

used to satisfy the RFS2 standards. 

Therefore, we are not finalizing such a 

requirement. 

While we understand that the types of 

projections we request in the Outlook 

Reports could be somewhat speculative 

in nature, we believe that the 

projections will provide us with the 

most reliable information possible to 

inform the annual RFS standards and 

waiver considerations. Further, we 

believe this information will be more 

useful to us than other public 

information that is released in other 

contexts (e.g., announcements for 

marketing purposes). As mentioned 

above in Section II.I, we believe that we 

can use this information to supplement 

other available information (such as 

volume projections from EIA) to help set 

the standard for the following year. 

Specifically, it will provide more 

accurate information for setting the 

cellulosic biofuel and biomass-based 

diesel standards, and any adjustments to 

the advanced biofuel and total 

renewable fuel standards. 

We received comments that both 

support and oppose the Production 

Outlook Reports, or some element of 

them. One commenter stated that EPA 

provided no reasonable explanation to 

require the information being requested 

for the reports; the commenter further 

stated that such information is not 

needed to assist parties to come into 

compliance. Another commenter stated 

that the renewable fuels industry cannot 

confidently project what will happen in 

2010, or even 2020, because there are 

too many unknowns, no previous 

history of renewable fuels mandates, 

and no sense of continued tax rebate. 

The commenter suggested that until the 

industry operates for a few years under 

the RFS2 carve-outs and the issues on 

the tax rebates for renewables are 

resolved, the industry cannot develop a 

meaningful outlook forecast. The 

commenter further suggested that EPA 

instead hire a consultant who can look 

at the big picture and provide a more 

meaningful evaluation than could the 

individual members of the biofuels 

industry. However, as discussed above, 

while these reports will have their 

limitations, we believe they will provide 

the best and most up to date information 

available for us to use in setting the 

standards and considering any waiver 

requests. We will of course also look to 

other publicly available information, 

and may consider using contractors to 

help out in this regard, but it cannot 

replace the need for the production 

outlook report data. 

A commenter noted that this 

provision is similar to reports required 

under the diesel program. The 

commenter further stated that if the 

required information can be captured by 

EMTS, the commenter fully supports 

this requirement. However, the 

commenter stated that it is opposed to 

some of the required elements of the 

reports for planned expanded or new 

production (strategic planning, planning 

and front-end engineering, detailed 

engineering and permitting, 

procurement and construction, and 

commissioning and start-up); these are 

an aspect of financial planning that the 

commenter believes EPA has no 

jurisdiction over and cannot derive 

basis from EISA in any form regardless 

of interpretation. As explained above, 

this information will be used by EPA to 

inform us for setting the standards on an 

annual basis and in responding to any 

waiver petitions. It will not be used to 

assess compliance with the program. 

The other provisions for registration, 

recordkeeping and reporting serve that 

purpose. 

Another commenter stated that the 

reports should be required, but that EPA 

should not rely too heavily upon the 

data (particularly for new biofuel 

technologies). Some commenters noted 

that they believe that requiring 

Production Outlook Reports is 

duplicative in nature and/or a burden to 

the industry. These commenters also 

believe that EPA already receives such 

information through the reporting that 

currently exists, and that EPA could 

also obtain this information from DOE’s 

Energy Information Administration 

(EIA) and the National Biodiesel Board 

(NBB). Other commenters expressed 

concern over reporting such 

confidential and strategic information 

(even as confidential business 

information (CBI)), and that information 

out to 2022 seems excessive and useless; 

and that the reports should be limited 

to just domestic and foreign producers 

of renewable fuels but not importers (as 

they tend to import renewable fuels 

based on variable economic conditions 

and will not likely have the ability to 

reliably predict their future import 

volumes). The information that 

currently exists from other sources is 

current and historical information. For 

the purposes of setting future standards, 

we need to have information on future 

plans and projections. We understand 

that reality will always be different from 

the projections, but they will still give 

us the best possible source of 

information. Furthermore, by having 

projections five years out into the 

future, and then obtaining new reports 

every year, we will be able to assess the 

trends in the data and reports to better 

utilize them over time. 

Some commenters have expressed 

concern that the information required 

for Production Outlook Reports is not 

needed, won’t provide useful 

information because it is speculative, or 

asks for information that could be 

sensitive/confidential. However, we 

continue to believe that such 

information is essential to our annual 

cellulosic biofuel standard setting, and 

consideration of whether waivers 

should be provided for other standards. 

All information submitted to EPA will 

be treated as confidential business 

information (CBI), and if used by EPA 

in a regulatory context will only be 

reported out in very general terms. As 

with our Diesel Pre-compliance Reports, 

we fully expect that the information will 

be somewhat speculative in the early 

reports, and we will weight it 

accordingly. As the program progresses, 

however, information submitted for the 

reports will continue to improve. We 

believe that any information, whether 

speculative or concrete, will be helpful 

for the purposes described above. Thus 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14731 

we are finalizing Production Outlook 

Reports, and the required elements at 

§ 80.1449. 

L. What Acts Are Prohibited and Who Is 

Liable for Violations? 

The prohibition and liability 

provisions under this rule are similar to 

those of the RFS1 program and other 

fuels programs in 40 CFR part 80. The 

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 is 

liable for violating that prohibition. 

Thus, for example, an obligated party is 

liable if the party failed to acquire 

sufficient RINs to meet its RVO. A party 

who produces or imports renewable 

fuels is liable for a failure to assign 

proper RINs to qualifying batches of 

renewable fuel produced or imported. 

Any party, including an obligated party, 

is liable for transferring a RIN that was 

not properly identified. 

In addition, any person who is subject 

to an affirmative requirement under this 

program is liable for a failure to comply 

with the requirement. For example, an 

obligated party is liable for a failure to 

comply with the annual compliance 

reporting requirements. A renewable 

fuel producer or importer is liable for a 

failure to comply with the applicable 

batch reporting requirements. Any party 

subject to recordkeeping or product 

transfer document (PTD) requirements 

is liable for a failure to comply with 

these requirements. Like other EPA 

fuels programs, this rule provides that a 

party who causes another party to 

violate a prohibition or fail to comply 

with a requirement may also 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, any person who violates 

any prohibition or requirement of this 

rule is subject to civil penalties of up to 

$37,500 per day and per each individual 

violation, plus the amount of any 

economic benefit or savings resulting 

from each violation. Under this rule, a 

failure to acquire sufficient RINs to meet 

a party’s renewable fuels obligation 

constitutes a separate day of violation 

for each day the violation occurred 

during the annual averaging period. 

As discussed above, the regulations 

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 address the 

consequences if an obligated party is 

found to have used invalid RINs to 

demonstrate compliance with its RVO. 

In this situation, the obligated party that 

used the invalid RINs will be required 

to deduct any invalid RINs from its 

compliance calculations. An obligated 

party is 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 is 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. 

III. Other Program Changes 

In addition to the regulatory changes 

we are finalizing today in response to 

comments received on the proposed 

rule and EISA (which are designed to 

implement the provisions of RFS2), 

there are a number of other changes to 

the RFS program that we are making. 

We believe that these changes will 

increase flexibility, simplify 

compliance, or address RIN transfer 

issues that have arisen since the start of 

the RFS1 program. Throughout the 

rulemaking process, we also 

investigated impacts on small 

businesses and we are finalizing 

provisions to address the impacts of the 

program on them. 

A. The EPA Moderated Transaction 

System (EMTS) 

The EPA Moderated Transaction 

System (EMTS) emerged as a result of 

our experiences with and lessons 

learned from implementing RFS1. 

Recognizing that the addition of 

significant volumes of renewable fuels 

and expansion of renewable fuel 

categories were adding complexity to an 

already stressed system, EMTS was 

introduced as a new approach for 

managing RINs in our NPRM. We 

received broad acceptance of the EMTS 

concept in the public comments as well 

as support for its expeditious 

implementation. This section describes 

the need for EMTS, implementation of 

EMTS, and an explanation of how 

EMTS will work. By implementing 

EMTS, we believe that we will be able 

to greatly reduce RIN-related errors 

while efficiently and accurately 

managing the universe of RINs. EMTS 

will save considerable time and 

resources for both industry and EPA. 

This is most evident considering that 

the system virtually eliminates multiple 

sources of administrative errors, 

resulting in a reduction of costs and 

effort expended to correct and 

regenerate product transfer documents, 

documentation and recordkeeping, and 

resubmitting reports to EPA. Use of 

EMTS will result in fewer report 

resubmissions and easier reporting for 

industry, while leaving fewer reports to 

be processed by EPA. Industry will 

spend less time and effort validating the 

RINs they procure with greater 

assurance and confidence in the RIN 

market. EPA will spend less time 

tracking down invalid RINs and 

working with regulated parties on 

complex remedial actions. This is 

possible because EMTS removes 

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. 

We received comments suggesting 

that EPA remove the attest engagement 

requirements and certain recordkeeping 

requirements due to the use of EMTS. 

While we believe that EMTS will 

simplify and reduce burdens on the 

regulated community, it is important to 

point out that EMTS is strictly a RIN 

tracking and managing tool designed to 

facilitate reporting under the Renewable 

Fuel Standard program. Product transfer 

documents are the commercial 

documents used to memorialize 

transactions of RINs between a buyer 

and a seller in the market. The EMTS 

will rely on references to these 

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14732 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

documents, which can take many forms, 

but it is not capable of replacing those 

documents. Attest engagements are used 

to verify that the records required to be 

kept by regulated parties, including 

information retained by a regulated 

party as well as information reported to 

EPA such as laboratory test results, 

contracts between renewable fuel/RIN 

buyers and sellers, feedstock 

documentation, etc. is correctly 

maintained or reported. The information 

reported via EMTS is but a subset of the 

information required to be maintained 

in a regulated party’s records, and both 

PTDs and attest engagements are 

necessary to ensure that the information 

collected and tracked in EMTS concurs 

with actual events. 

1. Need for the EPA Moderated 

Transaction System 

In implementing RFS1, we found that 

the 38-digit standardized RINs proved to 

be confusing to many parties in the 

distribution chain. Parties made various 

errors in generating and using RINs. For 

example, parties transposed digits 

within the RIN and incorrectly 

referenced volume numbering. Also, 

parties created alphanumeric RINs, 

despite the fact that RINs were 

supposed to consist of all numbers. 

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 usually involves 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 

was only on a quarterly basis, a RIN 

error could exist for several months 

before being discovered. 

Incorrect RINs are invalid RINs. If 

parties in the distribution system cannot 

track down and correct errors in a 

timely manner, then all downstream 

parties that traded the invalid RIN are 

in violation. Because RINs are the basic 

unit of compliance for the RFS program, 

it is important that parties have 

confidence when generating and using 

them. 

All parties in the RFS1 and the RFS2 

regulated community are required to use 

RINs. Under RFS2, we foresee that 

regulated party community will 

substantially expand. Newer regulated 

parties of an already complex system 

necessitate EMTS. These parties include 

renewable fuel producers and importers, 

obligated parties, exporters, and other 

RIN owners; (typically marketers of 

renewable fuels and blenders). Under 

RFS1, all RINs were used to comply 

with a single standard. With RFS2, there 

are four standards. RINs must be 

generated to identify one of the fuel 

categories: cellulosic biofuel, cellulosic 

diesel, biomass-based diesel, advanced 

biofuel, and renewable fuels (e.g., corn 

ethanol). (For a more detailed 

discussion of RINs, see Section II.A of 

this preamble.) The different types of 

RINs will be managed in the EMTS. 

2. Implementation of the EPA 

Moderated Transaction System 

We proposed that EMTS would be an 

opt-in for the calendar year 2010 and 

mandatory for calendar year 2011. We 

received many comments strongly 

supporting EMTS implementation with 

the start of the RFS2 program to ensure 

confidence and simplicity in an 

increasingly complex program. We also 

received comments that EMTS 

implementation with RFS2 is necessary 

so industry would not have to create a 

new system to handle RFS2 RINs for 

2010 and then move to EMTS for 2011 

while still handling RFS1 RINs. 

Potentially, three RIN transaction 

systems would exist during transition 

from RFS1 to RFS2 if EMTS could not 

be implemented with the start of the 

RFS2 program. EPA agrees that this 

three system issue would be an undue 

burden to industry as it would require 

industry to create two systems within a 

12 month period. EMTS development 

started with the introduction of the 

NPRM, and has been in beta testing 

since early November with a select 

group of different industry stakeholders. 

Industry feedback has been 

overwhelmingly strong for the 

implementation of EMTS with the start 

of RFS2. With this final rule, EPA 

decided that EMTS will start on the 

same date when RFS2 RINs are required 

to be generated. In addition, to ensure 

that parties will have enough time to 

incorporate RFS2 and EMTS 

requirements into private RIN tracking 

systems, the generation of RFS2 RINs 

will begin on July 1, 2010. Therefore, all 

RFS regulated parties are required to use 

EMTS starting July 1, 2010. 

RIN transactions are required to be 

verified and certified on a quarterly 

basis. EMTS will provide summaries for 

parties to verify, report, and certify 

transactions to EPA through the fuels 

reporting system, DCFuels. Additional 

information may be required to be 

added to the EMTS provided summary. 

This additional certification step allows 

parties to verification that the 

information sent to EMTS is accurate. 

However, parties may choose to review 

their data by checking their EMTS 

account at anytime. 

With EMTS, RIN transactions are 

required to be verified and certified on 

a quarterly basis. EMTS will provide 

summaries for parties to verify, report, 

and certify transactions to EPA through 

the fuels reporting system, DCFuels. 

Additional information may be required 

to be added to the EMTS provided 

report. This additional certification step 

allows parties to verify that the 

information sent to EMTS is accurate. 

However, parties may choose to review 

their data by checking their EMTS 

account at any time. 

3. How EMTS Will Work 

EMTS will be a closed, EPAmoderated system that provides a 

mechanism for screening RINs and a 

structured environment for conducting 

RIN transactions. ‘‘Screening’’ of RINs 

means that parties can have 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 received comments opposing the 

3 day time window for reporting 

transactions to the EMTS. One 

commenter requested 7 days from the 

event for sellers to report a transaction 

and 7 days after that for the buyer to 

accept the transaction. In order for this 

to be a ‘‘real time’’ system, we must 

require that the information comes in a 

timely manner. One commenter 

requested 10 days from the event to 

send information to EMTS. EPA has 

concluded that five days, or a business 

week, is an appropriate amount of time 

for both parties to receive or provide 

necessary documentation in order to 

interact with EMTS accurately and 

timely. ‘‘Real time’’ will be defined as 

within five (5) business days of a 

reportable event (e.g., generation and 

assignment of RINs, transfer of RINs). 

Parties who use EMTS must first 

register with EPA in accordance with 

the RFS2 registration program described 

in Section II.C of this preamble. Parties 

will also have to create an account (i.e., 

register) via EPA’s Central Data 

Exchange (CDX), as users will access 

EMTS via CDX. CDX is a secure and 

central electronic portal through which 

parties may submit compliance reports. 

Parties must establish an account with 

EMTS by July 1, 2010 or 60 days prior 

to engaging in any transaction involving 

RINs, whichever is later. Once 

registration occurs, individual accounts 

will be established within EMTS and 

the system will enable a party to submit 

transactions based on their registration 

information. 

In EMTS, the screening and 

assignment of RINs will be made at the 

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

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14733 

are generated through production or 

importation of renewable fuel. A 

renewable producer will electronically 

submit, in ‘‘real time,’’ a volume of 

renewable fuel produced or imported, as 

well as a number of the RINs generated 

and assigned. EMTS will automatically 

screen each batch and either reject the 

information or allow RINs created in the 

RIN generator’s account as one of the 

five types of RINs. 

We received comments supporting the 

RFS1 approach that allows producers 

and importers to generate RINs at the 

renewable fuel point of sale. EPA 

realizes that this is an industry practice 

and this flexibility will still be allowed 

for RIN generators, but only if applied 

consistently. 

After RINs have entered the system, 

parties may then trade them based on 

agreements outside of EMTS. One major 

advantage of EMTS, over the RFS1 

system, is that the system will simplify 

trading by allowing RINs to be traded 

generically. Only some specifying 

information will be needed to trade 

RINs, such as RIN quantity, fuel type, 

RIN assignment, RIN year, RIN price or 

price per gallon. The unique 

identification of the RIN will exist 

within EMTS, but parties engaging in 

RIN transactions will no longer have to 

worry about incorrectly recording or 

using 38-digit RIN numbers. The actual 

items of transactional information 

covered under RFS2 are very similar to 

those reported under RFS1. The RIN 

price is one of the new pieces of 

transactional information required to be 

submitted under RFS2. 

We received several adverse 

comments strongly opposing the 

collection of price information due to 

Confidential Business Information (CBI) 

concerns, other services being able to 

provide this information, marketplace 

delays and undue stress on the EMTS 

from disagreements in RIN price. We 

received one comment strongly 

supporting EPA collecting this 

information. EPA decided that the price 

information has great programmatic 

value because it will help us anticipate 

and appropriately react to market 

disruptions and other compliance 

challenges, assess and develop 

responses to potential waivers, and 

assist in setting future renewable fuel 

standards. In addition, EPA decided 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. Also, EPA will not require 

the matching of the exact RIN price to 

alleviate the burden of resubmission 

due to price mistakes. However, the 

price information must be accurate and 

rounded to the nearest cent (U.S. Dollar) 

at the time of sending the transactional 

information to EMTS. 

We received one comment requesting 

publication of security precautions 

taken by EPA to protect EMTS from 

attacks. EPA cannot provide security 

information to the public because 

providing such information may create 

security vulnerabilities. However, EMTS 

will be compliant with the appropriate 

security requirements for all federal 

agency information technology systems. 

Also 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 will 

offer the option for a buyer to accept or 

reject RINs from specific RIN generators 

or from classes of RIN generators. 

4. A Sample EMTS Transaction 

This sample illustrates how two 

parties may trade RINs in EMTS: 

(1) Seller logs into EMTS and posts a 

sale of 10,000 RINs to Buyer at X price. 

For this example, assume the RINs were 

generated in 2010 and were assigned to 

10,000 gallons of ‘‘Renewable fuel 

(D=6)’’. Seller’s RIN account for 

‘‘Renewable fuel (D=6)’’ is put into a 

‘‘pending’’ status of 10,000 with the 

posting of the sale to Buyer. Buyer 

receives automatic notification of the 

pending transaction. 

(2) Buyer logs into EMTS. Buyer sees 

the sale transaction pending. Assuming 

it is correct, Buyer accepts it. Upon 

acceptance, Buyer’s RIN account for 

‘‘Renewable fuel (D=6)’’ RINs is 

automatically increased by 10,000 2010 

assigned RINs sold at X price. 

(3) After Seller has posted the sale 

and Buyer has accepted it, EMTS 

automatically notifies both Buyer and 

Seller that the transaction has been fully 

completed. 

Under EMTS, the seller will always 

have to initiate any transaction. The 

specific amount of RINs are put into a 

pending status when the seller posts the 

sale. The buyer must confirm the sale in 

order to have the RINs transferred to the 

buyer’s account. Transactions will 

always be limited to available RINs. 

Notification will automatically be sent 

to both the buyer and the seller upon 

completion of the transaction. EPA 

considers any sale or transfer as 

complete upon acknowledgement by the 

buyer. We will also allow buyers to 

submit their acknowledgement prior to 

a seller initiating the transaction. 

However, these buy transactions will 

not initiate any RINs being put into a 

pending status from a seller’s account. 

Instead, the buy transactions will be 

queued and checked periodically to see 

if a ‘‘sell’’ transaction was posted by the 

seller. If a buy is posted without a 

matching sell transaction, then the seller 

will be notified that a buy transaction is 

pending. Both buy and sell transactions 

must be matched within a set number of 

days from the submission date or they 

will expire. Transactions will expire 7 

days after the submission of the file. 

Since both parties are required to 

submit information within 5 days, we 

allow the full 5 days to expire plus 2 

days in the case of late submissions. 

In summary, the advantage to 

implementing EMTS is that parties may 

engage in RIN transactions with a high 

degree of confidence, errors will be 

virtually eliminated, and everyone 

engaging in RIN transactions will have 

a simplified environment in which to 

work, which should minimize the level 

of resources needed for implementation. 

B. Upward Delegation of RIN-Separating 

Responsibilities 

Since the start of the RFS 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 rule, 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 

gasoline only. EISA mandates certain 

amounts of renewable fuels to be 

blended into all transportation fuels— 

which includes highway and 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 EPA fuels regulations) 

will now be regulated by the RFS 

program. 

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14734 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

Consequently, we believe it is 

appropriate, and thus we are finalizing 

as proposed, 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 is consistent with the fact that 

the RFS 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 

will eliminate undue burden on small 

parties who would otherwise not be 

regulated by this program. This 

provision is solely for the case of 

blenders who blend and trade less than 

125,000 total gallons of renewable fuel 

per year (i.e., a company that blends 

100,000 gallons and trades another 

100,000 gallons would not be able to use 

this provision) and is available to any 

blender who must separate RINs from a 

volume of renewable fuel under 

§ 80.1429(b)(2). 

We requested comment in the NPRM 

on this concept, the 125,000 gallon 

threshold, and appropriate 

documentation to authorize this upward 

delegation. In general, those that 

commented on this provision support 

the idea of upward delegation for small 

blenders, though one commenter stated 

that EPA should not allow small entities 

to delegate their RIN-related 

responsibilities upward. Those 

commenters that support the upward 

delegation provision stated that it 

should be limited to small blenders only 

and should only be for delegating to the 

party directly upstream. A few 

commenters stated that they believe the 

125,000 gallon threshold is appropriate; 

while others commented that it should 

be higher. We believe that the 125,000 

gallon limit strikes the correct balance 

between providing relief to small 

blenders, while still ensuring that nonobligated parties cannot unduly 

influence the RIN market. 

We did not receive any comments on 

appropriate documentation, however a 

couple commenters suggested that we 

retain the proposed annual 

authorization between the blender and 

the party directly upstream, as well as 

allowing a small blender to enter into 

arrangements with multiple suppliers 

on a transaction-by-transaction basis. 

Please see Chapter 5 of the Summary 

and Analysis of Comments Document 

for more discussion on the comments 

received and our responses to those 

comments. 

We are also finalizing, as stated in the 

preamble to the proposed rule, that for 

upstream delegation, both parties must 

sign a quarterly written statement 

(which must be included with the 

reporting party’s reports) authorizing 

the upward delegation. Copies of these 

statements must be retained as records 

by both parties. 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. This 

statement would apply to all volumes of 

renewable fuel transferred between the 

two parties. Thus, the two parties would 

enter into a contract stating that the 

supplier has RIN-separation 

responsibilities for all transferred 

volumes between the two parties, and 

no additional permissions from the 

small blender would be needed for any 

volumes transferred. A blender may 

enter into such an agreement with as 

many parties as they wish. 

C. Small Producer Exemption 

Under the RFS1 rule, 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. These producers and importers 

are also exempt from registration, 

reporting, recordkeeping, and attest 

engagement requirements. In the 

preamble to the proposed rule, we 

requested comment on whether or not 

this 10,000 gallon threshold was 

appropriate. One commenter suggested 

that we retain the 10,000 gallon 

threshold as-is. Another commenter 

supported the concept of less 

burdensome requirements for small 

producers, but suggested that these 

entities should, at a minimum, be 

required to generate RINs for all 

qualifying renewables. We are 

maintaining this exemption under the 

RFS2 rule for parties who produce or 

import less than 10,000 gallons of 

renewable fuel per year. 

In addition to the permanent 

exemption for those producers and 

importers who produce or import less 

than 10,000 gallons of renewable fuel 

per year, we are also finalizing a 

temporary exemption for renewable fuel 

producers who produce less than 

125,000 gallons of renewable fuel each 

year from new production facilities. 

These producers are not required to 

generate and assign RINs to batches of 

renewable fuel for a period of up to 

three years, beginning with the calendar 

year in which the production facility 

produces its first gallon of renewable 

fuel. Such producers are also exempt 

from registration, reporting, 

recordkeeping, and attest engagement 

requirements as long as they do not own 

RINs or voluntarily generate and assign 

RINs. This provision is intended to 

allow pilot and demonstration plants of 

new renewable fuel technologies to 

focus on developing the technology and 

obtaining financing during these early 

stages of their development without 

having to comply with the RFS2 

regulations. 

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. 

When renewable fuel volumes are being 

produced that exceed the RFS2 

standards, the rollover issue could 

undermine the ability of a limit on 

credit life to guarantee an ongoing 

market for renewable fuels. 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14735 

35Small refineries are also allowed to waive this 

exemption. 

To implement EISA’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. 

As described in the NPRM, 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. As 

a result we proposed to maintain the 

regulatory requirement for a 20% 

rollover cap under the new RFS2 

program, and to apply this cap 

separately to all four RVOs under RFS2. 

However, we took comment on 

changing the level of the cap to some 

alternative value lower or higher than 

20%. 

A lower cap could provide a greater 

incentive for parties with excess RINs to 

sell them rather than hold onto them, 

increasing the availability of RINs for 

parties that need them for compliance 

purposes. But a lower cap would also 

reduce flexibility for obligated parties 

attempting to minimize the costs of 

compliance with increasing annual 

volume requirements, particularly if 

there are concerns that the RIN market 

may be tighter in the future than it is 

currently. 

Conversely, the increasing annual 

volume requirements in EISA make it 

less likely that renewable fuel producers 

will overcomply, and as a result it is 

less likely that there will be an excess 

of RINs in the market. Under these 

circumstances, there is little 

opportunity for RINs to build up in the 

market, and the rollover cap would have 

less of an impact on the market as a 

whole. Thus a higher cap might be 

warranted. However, while a higher cap 

would create greater flexibility for some 

obligated parties, it could also create 

disruptions in the RIN market as parties 

with excess RINs would have a greater 

opportunity to hold onto them rather 

than sell them. Parties without direct 

access to RINs through the purchase and 

blending of renewable fuels would be 

placed at a competitive disadvantage in 

comparison to parties with excess RINs. 

In the extreme, removal of the cap 

entirely would allow obligated parties to 

roll over up to one year’s worth of their 

obligations indefinitely. 

In general, commenters on the NPRM 

reiterated the positions that they raised 

during development of the RFS1 

program. While one renewable fuel 

producer requested that the rollover cap 

be left at 20%, most producers 

requested that the rollover cap be 

reduced to 0%, such that compliance 

with the standards applicable in a given 

year could only be demonstrated using 

RINs generated in that year. In contrast, 

refiners requested that the rollover cap 

be either eliminated, such that any 

number of previous year RINs could be 

used for current year compliance, or at 

least raised to 40 or 50 percent. Small 

refiners requested that the cap be raised 

for small refiners only to accommodate 

the competitive disadvantage with 

respect to the RIN market that they 

believe they experience in comparison 

to larger refiners. 

Based on the comments received, we 

believe that the 20% level continues to 

provide the appropriate balance 

between, on the one hand, allowing 

legitimate RIN carryovers and protecting 

against potential supply shortfalls that 

could limit the availability of RINs, and 

on the other hand ensuring an annual 

demand for renewable fuels as 

envisioned by EISA. Therefore, we are 

continuing the 20% rollover cap for 

obligated parties for the RFS program. 

E. Small Refinery and Small Refiner 

Flexibilities 

This section discusses flexibilities for 

small refineries and small refiners for 

the RFS2 rule. As explained in the 

discussion of our compliance with the 

Regulatory Flexibility Act below in 

Section XI.C and in the Final Regulatory 

Flexibility Analysis in Chapter 7 of the 

RIA, we considered the impacts of the 

RFS2 regulations on small businesses 

(small refiners). 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 for this rule, 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 rulemaking docket. 

For the SBREFA process, we conducted 

outreach, fact-finding, and analysis of 

the potential impacts of our regulations 

on small business refiners. 

1. Background—RFS1 

a. Small Refinery Exemption 

CAA section 211(o)(9), 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, 2010.35

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. 

b. Small Refiner Exemption 

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 EPAct small refinery 

definition as noted above. 

2. Statutory Options for Extending 

Relief 

There are two provisions in section 

211(o)(9) that allow for an extension of 

the temporary exemption for small 

refineries beyond December 31, 2010. 

One provision 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 

automatic extension of at least two years 

for small refineries that DOE determines 

would be subject to such 

disproportionate hardship (per section 

211(o)(9)(A)(ii)). If the DOE study 

determines that such hardship exists, 

then section 211(o)(9)(A)(ii) (which was 

retained in EISA) provides that EPA 

shall extend the exemption for a period 

of at least two years. 

The second provision, at section 

211(o)(9)(B), authorizes EPA to grant an 

extension for a small refinery based 

upon disproportionate economic 

hardship, on a case-by-case basis. A 

small refinery may, at any time, petition 

EPA for an extension of the small 

refinery exemption on the basis of 

disproportionate economic hardship. 

EPA is to consult with DOE and 

consider the findings of the DOE small 

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14736 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

refinery study in evaluating such 

petitions. These petitions may be filed 

at any time, and EPA has discretion to 

determine the length of any exemption 

that may be granted in response. 

3. The DOE Study/DOE Study Results 

As discussed above, EPAct required 

that DOE perform a study by December 

31, 2008 on the impact of the renewable 

fuel requirements on small refineries 

(section 211(o)(9)(A)(ii)(I)), and whether 

or not the requirements would impose 

a disproportionate economic hardship 

on these refineries. 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 

regulation section 80.1456). DOE thus 

determined that small refineries would 

not be subject to disproportionate 

economic hardship under the proposed 

RFS2 program, and that the exemption 

should not, on the basis of the study, be 

extended for small refineries (including 

those small refiners who own refineries 

meeting the small refinery definition) 

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 

(pursuant to Section 211(o)(9)(B)). 

4. Ability To Grant Relief Beyond 

211(o)(9) 

The SBREFA panel made a number of 

recommendations for regulatory relief 

and additional flexibility for small 

refineries and small refiners. These are 

described in the Final Panel Report 

(located in the rulemaking docket), and 

summarized below. During the 

development of this final rule, we again 

evaluated the various options 

recommended by the Panel and also 

comments on the proposed rule. We 

also consulted the small refinery study 

prepared by DOE. 

As described in the Final Panel 

Report, EPA early-on identified 

limitations on its authority to issue 

additional flexibility and exemptions to 

small refineries. In section 211(o)(9) 

Congress specifically addressed the 

issue of an extension of time for 

compliance for small refineries, 

temporarily exempting them from 

renewable fuel obligations through 

December 31, 2010. As discussed above, 

the statute also includes two specific 

provisions describing the basis and 

manner in which further extensions of 

this exemption can be provided. In the 

RFS1 rulemaking, EPA considered 

whether it should provide additional 

relief to the limited number of small 

refiners who were not covered by the 

small refinery provision, by providing 

them a temporary exemption consistent 

with that provided by Congress for 

small refineries. EPA exercised its 

discretion under section 211(o)(3) and 

provided such relief. Thus, in RFS1, 

EPA did not modify the relief provided 

by Congress for small refineries, but did 

exercise its discretion to provide the 

same relief specified by statute to a few 

additional parties. 

In RFS2 we are faced with a different 

issue—the extent to which EPA should 

provide additional relief to small 

refineries beyond the relief specified by 

statute, and whether it should provide 

such further relief to small refiners as 

well. There is considerable overlap 

between entities that are small refineries 

and those that are small refiners. 

Providing additional relief just to small 

refiners would, therefore, also extend 

additional relief to at least a number of 

small refineries. Congress spoke directly 

to the relief that EPA may provide for 

small refineries, including those small 

refineries operated by small refiners, 

and limited that relief to a blanket 

exemption through December 31, 2010, 

with additional extensions if the criteria 

specified by Congress are met. EPA 

believes that an additional or different 

extension, relying on a more general 

provision in section 211(o)(3) would be 

inconsistent with Congressional intent. 

Further, we do not believe that the 

statute allows us the discretion to give 

relief to small refiners only—as this 

would result in a subset of small 

refineries (those that also qualify as 

small refiners) receiving relief that is 

greater than the relief already given to 

all small refineries under EISA. 

EPA also notes that the criteria 

specified by statute for providing a 

further compliance extension to small 

refineries is a demonstration of 

‘‘disproportionate economic hardship.’’ 

The statute provides that such hardship 

can be identified through the DOE 

study, or in individual petitions 

submitted to the Agency. However, the 

DOE study has concluded that no 

disproportionate economic hardship 

exists, at least under current conditions 

and for the foreseeable future under 

RFS2. Therefore, absent further 

information that may be provided 

through the petition process, there does 

not currently appear to be a basis under 

the statute for granting further 

compliance extensions to small 

refineries. If DOE revises its study and 

comes to a different conclusion, EPA 

can revisit this issue. 

5. Congress-Requested Revised DOE 

Study 

In their written comments, as well as 

in discussions we had with them on the 

proposed rule, small refiners indicated 

that they did not believe that EPA 

should rely on the results of the DOE 

small refinery study to inform any 

decisions on small refiner provisions. 

Small refiners generally commented that 

they believe that the study was flawed 

and that the conclusions of the study 

were reached without adequate analysis 

of, or outreach with, small refineries (as 

the majority of the small refiners own 

refineries that meet the Congressional 

small refinery definition). One 

commenter stated that such a limited 

investigation into the impact on small 

refineries could not have resulted in any 

in-depth analysis on the economic 

impacts of the program on these entities. 

Another commenter stated that it 

believes that DOE should be directed to 

reopen and reassess the small refinery 

study be June 30, 2010, as suggested by 

the Senate Appropriations Committee. 

We are aware that there have been 

expressions of concern from Congress 

regarding the DOE Study. Specifically, 

in Senate Report 111–45, the Senate 

Appropriations Committee ‘‘directed 

[DOE] to reopen and reassess the Small 

Refineries Exemption Study by June 30, 

2010,’’ noting a number of factors that 

the Committee intended that DOE 

consider in the revised study. The Final 

Conference Report 111–278 to the 

Energy & Water Development 

Appropriations Act (H.R. 3183), 

referenced the language in the Senate 

Report, noting that the conferees 

‘‘support the study requested by the 

Senate on RFS and expect the 

Department to undertake the requested 

economic review.’’ At the present time, 

however, the DOE study has not been 

revised. If DOE prepares a revised study 

and the revised study finds that there is 

a disproportionate economic impact, we 

will revisit the exemption extension at 

that point in accordance with section 

211(o)(9)(A)(ii). 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14737 

6. What We’re Finalizing 

a. Small Refinery and Small Refiner 

Temporary Exemptions 

As mentioned above, the RFS1 

program regulations exempt gasoline 

produced by small refineries from the 

renewable fuels standard through 

December 31, 2010 (at 40 CFR 80.1141), 

per EPAct. As EISA did not alter the 

small refinery exemption in any way, 

we are retaining this small refinery 

temporary exemption in the RFS2 

program without change (except for the 

fact that all transportation fuel produced 

by small refineries will be exempt, as 

EISA also covers diesel and nonroad 

fuels). 

Likewise, as we extended under RFS1 

the small refinery 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), we are also finalizing a 

continuation of the small refiner 

temporary exemption through December 

31, 2010. 

b. Case-by-Case Hardship for Small 

Refineries and Small Refiners 

As discussed in Section III.E.2, EPAct 

also 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 allow 

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 finalizing 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). We are also 

finalizing a case-by-case hardship 

provision for those small refiners that 

do not operate small refineries using our 

discretion under CAA section 

211(o)(3)(B). This provision will allow 

those small refiners that do not operate 

small refineries to apply for the same 

kind of hardship extension as a small 

refinery. In evaluating applications for 

this hardship provision EPA will take 

into consideration information gathered 

from annual reports and RIN system 

progress updates, as recommended by 

the SBAR Panel, as well as information 

provided by the petitioner and through 

consultation with DOE. 

c. Program Review 

During the SBREFA process, the small 

refiner Small Entity Representatives 

(SERs) also requested that EPA perform 

an annual program review, to begin one 

year before small refiners are required to 

comply with the program, to provide 

information on RIN system progress. As 

mentioned in the preamble to the 

proposed rule, we were concerned that 

such a review could lead to some 

redundancy with the notice of the 

applicable RFS standards that EPA will 

publish 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, and we proposed, 

that an update of RIN system progress 

(e.g., RIN trading, publicly-available 

information on RIN availability, etc.) be 

included in this annual notice. 

Based on comments received on the 

proposed rule, we believe that such 

information could be helpful to 

industry, especially to small businesses 

to help aid the proper functioning of the 

RIN market, especially in the first years 

of the program. However, during the 

development of the final rule, it became 

evident that there could be instances 

where we would want to report out RIN 

system information on a more frequent 

basis than just once a year. Thus we are 

finalizing that we will periodically 

report out elements of RIN system 

progress; but such information will be 

reported via other means (e.g., the RFS 

Web site (http://www.epa.gov/otaq/ 

renewablefuels/index.htm), EMTS 

homepage, etc.). 

7. Other Flexibilities Considered for 

Small Refiners 

During the SBREFA process, and in 

their comments on the proposed rule, 

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 costs), the desire 

for an annual RIN system review, and 

the difficulty in raising capital and 

competing for engineering resources to 

make capital improvements. 

The Panel recommended that EPA 

consider the issues raised by the small 

refiner 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 XI.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. Also, a complete discussion of 

comments received on the proposed 

rule regarding small refinery and small 

refiner flexibilities can be found in 

Chapter 5 of the Summary and Analysis 

of Comments document. 

a. Extensions of the RFS1 Temporary 

Exemption for Small Refiners 

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. 

This provided an exemption for small 

refineries (and small refiners) for the 

first five years of the RFS program. 

Small refiner SERs suggested that an 

additional temporary exemption for the 

RFS2 program would be beneficial to 

them in meeting the RFS standards as 

increased by Congress in EISA. The 

Panel recommended that EPA propose a 

delay in the effective date of the 

standards until 2014 (for a total of eight 

years) for small entities, to the extent 

allowed by the statute. 

During the development of both the 

Final Panel Report and the proposed 

rule, we evaluated various options for 

small refiners, including an additional 

temporary exemption for small refiners 

from the required RFS2 standards. As 

discussed above, we concluded that we 

do not have the statutory authority to 

provide such extensions through means 

other than those specified in the statute. 

Thus, further extensions will be as a 

result of any revised DOE study, or in 

response to a petition, pursuant to the 

authorities specified in section 

211(o)(9). 

We proposed to continue the 

temporary exemption finalized in 

RFS1—through December 31, 2010. 

Commenters that oppose an extension of 

the temporary exemption generally 

stated that an extension is not 

warranted, and some commenters 

expressed concerns about allowing 

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14738 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

provisions for small refiners. One 

commenter also stated that it believes 

that the small refinery exemption 

should not be extended and that the 

small refiner exemption should be 

eliminated completely. Two 

commenters supported the continuation 

of the exemption through December 31, 

2010 only, and one stated that it does 

not support an extension as it believes 

that all parties have been well aware of 

the passage of EISA and small refineries 

and small refiners should have been 

striving to achieve compliance by the 

end of 2010. Two commenters also 

expressed views that the exemption 

should not have been offered to small 

refiners in RFS1 as this was not 

provided by EPAct, and that an 

extension of the exemption should not 

be finalized for small refineries at all. 

The commenters further commented 

that an economic hardship provision 

was included in EPAct, and any 

exemption extension should be limited 

to such cases, and only to the specific 

small refinery (not small refiner) that 

has petitioned for such an extension. 

Commenters supporting an extension 

of the exemption commented that they 

believe that the statutes (EPAct and 

EISA) do not prohibit EPA from 

providing relief to regulated small 

entities on which the rule will have a 

significant economic impact, and that 

such a delay could lessen the burden on 

these entities. One commenter stated 

that it believes EPA denied or ignored 

much of the relief recommended by the 

Panel in the proposal. Another 

commenter stated that it believes EPA’s 

concerns regarding the legal authority 

are unsustainable considering EPA’s 

past exercises of discretion under the 

RFS1 program, and with the discretion 

afforded to EPA under section 211(o) of 

the CAA. Some commenters requested a 

delay until 2014 for small refiners. One 

additional commenter expressed 

support for an extension of the small 

refinery exemption only, and that these 

small refineries should be granted a 

permanent exemption. 

During the development of this final 

rule, we again evaluated the various 

options recommended by the Panel, the 

legality of offering an extension of the 

exemption to small refiners only, and 

also comments on the proposed rule. 

Specifically in the case of an extension 

of the exemption for small refiners, we 

also consulted the small refinery study 

prepared by DOE, as the statute directs 

us to use this as a basis for providing an 

additional two year exemption. As 

discussed above in Sections III.E.4 and 

5, we do not believe that we can provide 

an extension of the exemption 

considering the outcome of the DOE 

small refinery study, which did not find 

that there was a disproportionate 

economic hardship. Further, we do not 

believe that the statute allows us the 

discretion to give relief to a subset of 

small refineries (those that also qualify 

as small refiners) that is greater than the 

relief already given to all small 

refineries under EPAct. However, it is 

important to recognize that the 211(o)(9) 

small refinery provision does allow for 

extensions beyond December 31, 2010, 

as discussed above in Section III.E.2. 

Thus, refiners may apply for individual 

hardship relief. 

b. 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 stated in the 

NPRM that we had serious concerns 

about our legal authority to provide 

such a phase-in. 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. A phase-in approach 

would essentially result in different 

applicable percentages being applied to 

different obligated parties. Further, such 

a phase-in approach would provide 

more relief to small refineries operated 

by small refiners than that provided 

under the statutory small refinery 

provisions. 

Some commenters stated that they 

believe that EPA has the ability to 

consider a phase-in of the standards for 

small refiners. One commenter 

suggested that a temporary phase-in 

could help lessen the burden of 

regulation on small entities and promote 

compliance. Another commenter stated 

that it believes EPA’s legal concerns 

regarding a phase-in are unsustainable 

considering EPA’s past exercises of 

discretion under the RFS1 program and 

with the discretion afforded to EPA 

under section 211(o) of the CAA. 

After considering the comments on 

this issue, EPA continues to believe that 

allowing a phase-in of regulatory 

requirements for small refineries and/or 

small refiners would be inconsistent 

with the statute, for the reasons 

mentioned above. Any individual 

entities that are experiencing hardship 

that could justify a phase-in of the 

standards have the ability to petition 

EPA for individualized relief. Therefore 

we are not including a phase-in of 

standards for small refiners in today’s 

rule. 

c. RIN-Related Flexibilities 

The small refiner SERs requested that 

the RFS2 rule contain provisions for 

small refiners related to the RIN system, 

such as flexibilities in the RIN rollover 

cap percentage and allowing small 

refiners only to use RINs 

interchangeably. In the RFS1 rule, up to 

20% of a previous year’s RINs may be 

‘‘rolled over’’ and used for compliance in 

the following year. In the preamble to 

the proposed rule, we discussed the 

concept of allowing for flexibilities in 

the rollover cap, such as a higher RIN 

rollover cap for small refiners for some 

period of time or for at least some of the 

four standards. As 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, we requested comment on 

the concept of increasing the RIN 

rollover cap percentage for small 

refiners and an appropriate level of that 

percentage. In response to the Panel’s 

recommendation, we also sought 

comment on allowing small refiners to 

use the four types of RINs 

interchangeably. 

In their comments on the proposed 

rule, one small refiner commented that, 

in regards to small refiners’ concerns 

about RIN pricing and availability, there 

is no mechanism in the rule to address 

the possibility that the RIN market will 

not be viable. The commenter further 

suggested that more ‘‘durable’’ RINs are 

needed for small refiners that can be 

carried over from year to year, to 

alleviate some of the potentially market 

volatility for renewable fuels. Another 

commenter suggested that RINs should 

be interchangeable for small refiners, or 

alternatively, some mechanism should 

be implemented to ensure that RIN 

prices are affordable for small refiners. 

Further, with regard to interchangeable 

RINs, one commenter stated that small 

refiners do not have the staff or systems 

to manage and account for four different 

categories of RINs and rural small 

refiners will suffer economic hardship 

and disadvantage because of the 

unavailability of biofuels. The 

commenter also requested an increase in 

the rollover cap to 50% for small 

refiners. 

We are not finalizing additional RINrelated flexibilities for small refiners in 

today’s action. As highlighted in the 

NPRM, we continue to believe that the 

concept of interchangeable RINs for 

small refiners only fails to require the 

four different standards mandated by 

Congress (e.g., conventional biofuel 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14739 

36Equation was derived from R.E. Tate et al. ‘‘The 

Densities of Three Biodiesel Fuels at Temperatures 

up to 300 °C.’’, Department of Biological 

Engineering, Dalhousie University, April 2005. 

‘‘Fuel 85 (2006) 1004–1009, Table 1 for soy methyl 

ester.’’ 

37 74 FR 24943, May 26, 2009. 

could not be used instead of cellulosic 

biofuel or biomass-based diesel), and is 

not consistent with section 211(o) of the 

Clean Air Act. Essentially, it would 

circumvent the explicit direction of 

Congress in EISA to require that the four 

RFS2 standards be met separately. 

Further, given the findings from the 

DOE study that small refineries (and 

thus, most small refiners) do not 

currently face disproportionate 

economic hardship, and are not 

expected to do so as RFS2 is 

implemented, we do not believe that a 

basis exists to justify providing small 

refiners with a larger rollover cap than 

other regulated entities. Thus, small 

refiners will be held to the same RIN 

rollover cap as other obligated parties. 

F. Retail Dispenser Labeling for Gasoline 

With Greater Than 10 Percent Ethanol 

We proposed labeling requirements 

for fuel dispensers that handle greater 

than 10 volume percent ethanol blends 

which included the following text: For 

use only in flexible-fuel vehicles, May 

damage non-flexible-fuel vehicles, 

Federal law prohibits use in nonflexible-fuel vehicles. This proposal was 

primarily meant to help address 

concerns about the potential misfueling 

of non-flex-fuel vehicles with E85, in 

light of the anticipated increase in E85 

sales volumes in response to the RFS2 

program. All ethanol blends above 10 

volume percent were included due to 

the increasing industry focus on ethanol 

blender pumps that are designed to 

dispense a variety of ethanol blends 

(e.g., E30, and E40) for use in flex-fuel 

vehicles. 

Commenters stated that EPA should 

undertake additional analysis of the 

potential impacts from misfueling and 

what preventative measures might be 

appropriate before finalizing labeling 

requirements for >E10 blends. They also 

stated that EPA should coordinate any 

such labeling provisions with those 

already in place by the Federal Trade 

Commission. EPA is also currently 

evaluating a petition to allow the use of 

up to 15 volume percent ethanol in nonflex fuel vehicles. One potential result 

of this evaluation might be for EPA to 

grant a partial waiver that is applicable 

only for a subset of the current vehicle 

population. Under such an approach, a 

label for E15 fuel dispensers would be 

needed that identifies what vehicles are 

approved to use E15. 

Based on the public comments and 

the fact that EPA has not completed its 

evaluation of the E15 waiver petition, 

we believe that it is appropriate to defer 

finalizing labeling requirements for 

>E10 blends at this time. This will 

afford us the opportunity to complete 

our analysis of what measures might be 

appropriate to prevent misfueling with 

>E10 blends before this may become a 

concern in the context of the RFS2 

program. 

G. Biodiesel Temperature 

Standardization 

The volume of a batch of renewable 

fuel can change under extreme changes 

in temperature. The volume of a batch 

of renewable fuel can experience 

expansion as the temperature increases, 

or can experience contraction as 

temperature decreases. The Agency 

requires temperature standardization of 

renewable fuels at 60° Fahrenheit (°F) so 

renewable fuel volumes are accounted 

for on a uniform and consistent basis 

over the entire fuels industry. In the 

May 1, 2007 Renewable Fuels Standard 

(RFS) final rule the Agency required 

biodiesel temperature standardization to 

be completed as follows: 

Vs,b = Va,b × (¥0.0008008 × T + 1.0480) 

Where 

Vs,b = Standard Volume of biodiesel at 60 

degrees F, in gallons; 

Va,b = Actual volume of biodiesel, in gallons; 

T = Actual temperature of batch, in degrees 

F. 

This equation was based on data from 

a published research paper by Tate et 

al.36 Members of the petroleum industry 

have indicated that the current biodiesel 

temperature standardization equation in 

the regulations provides different results 

than that commonly used by both the 

petroleum and biodiesel industry for 

commercial trading of biodiesel. These 

commercial values are either based on 

American Petroleum Institute (API) 

tables for petroleum products or on 

empirical values from industry 

measurements at common temperatures 

and pressures observed in bulk fuel 

facilities. The difference between RIN 

calculated volumes and commercial 

sales volumes has created confusion 

within the record keeping system of 

both the petroleum and biodiesel 

industry. 

In the RFS2 proposed rule, the 

Agency proposed the temperature 

standardization of biodiesel remain 

unchanged from the RFS1 

requirements.37 The Agency received 

comments from Archer Daniels Midland 

Company (ADM), World Energy 

Alternatives, Marathon Petroleum 

Company (Marathon) and the National 

Biodiesel Board (NBB) to revise the 

biodiesel temperature standardization 

equation. 

Both ADM and NBB agreed on the 

necessity for biodiesel temperature 

standardization at 60 °F. ADM and NBB 

commented on several empirical 

calculations which have been developed 

specific to biodiesel temperature 

standardization since the 2007 RFS1 

final rule. These include a 2004 data set 

developed by the Minnesota Department 

of Commerce and the Renewable Energy 

Group and updated in 2008; information 

embedded in the European Biodiesel 

Specification EN 14214; and 

information from the Alberta Research 

Council. The table below provides 

values from NBB for 1000 gallons of 

biodiesel standardized to a temperature 

at 60 °F for these empirical calculations, 

along with the current EPA equation, 

and the American Petroleum Institute 

(API) Refined Products Table 6. 

TABLE III.G–1—NBB COMPARISON OF

BIODIESEL TEMPERATURE STANDARDIZATION CALCULATIONS TO 60 °F 

FOR 1000 GALLONS OF BIODIESEL

AT 90 °F 

Gallons 

2007 EPA Biodiesel Formula ..... 975 .28 

2008 Minnesota (Hedman) data 986 .270 

API Refined Products Table 6 

(biodiesel density @ 7.359) .... 986 .625 

Alberta Research Council ........... 986 .238 

EN 14214 data ........................... 986 .401 

2004 Minnesota Renewable Energy Group data ...................... 986 .830 

As illustrated by the results from the 

above table, the values for the various 

biodiesel temperature standardization 

empirical calculations are within 1 

gallon of agreement of each other for a 

1000 gallon biodiesel batch, except for 

the current biodiesel temperature 

standardization equation in the 

regulations. 

To ensure consistency in RIN 

generation, ADM commented EPA 

should adopt only one biodiesel 

temperature standardization calculation. 

ADM commented that all biodiesel 

temperature standardization 

calculations developed, including the 

API Refined Products Table 6, are in 

very close agreement with each other 

and the differences between them all are 

insignificant. They further commented 

the API Refined Products Table 6 has 

provided a uniform measurement of 

volume for years for the entire liquid 

fuels industry. Thus, ADM believes the 

API Refined Products Table 6 should be 

adopted for biodiesel to be consistent 

with the calculation of sales volumes. 

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14740 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

38AEO 2007 was only used to derive renewable 

fuel volume projections for the primary reference 

case. AEO 2009 was used for future crude oil cost estimates and for estimating total transportation 

fuel energy use. 

Finally ADM comments adoption of the 

API Refined Products Table 6 would 

allow for easier verification within the 

marketplace, eliminate the need for 

calculating one volume for sales and 

trades and another for RINs, and 

prevents the entire distribution network 

from facing the financial burden of 

reprogramming existing meters that 

already are based on the API Refined 

Products Table 6. 

NBB commented that earlier surveys 

from its members indicate a fifty-fifty 

split between members using the API 

Refined Products Table 6 or some 

variation of the current EPA biodiesel 

formula for biodiesel temperature 

standardization. Some NBB members 

indicated that the API Refined Products 

Table 6 was more commonly used by 

the petroleum industry and embedded 

into the meters, pumps and accounting 

systems of the petroleum industry. 

Companies already using the API 

Refined Products Table 6 would have a 

reduction in required paperwork with 

RIN generation and tracking because 

already existing commercial documents 

could serve that purpose and they thus 

could eliminate or reduce their current 

dual tracking system. Other NBB 

members have already embedded the 

current EPA biodiesel equation within 

their accounting and sales systems and 

would like to continue using that type 

of biodiesel temperature standardization 

approach rather than the API Refined 

Products Table 6. The NBB 

recommended EPA revise its current 

equation in the regulations to the 2008 

Hedman biodiesel temperature 

standardization equation. Thus, NBB 

commented EPA should provide 

flexibility to their members by allowing 

the use of either the API Refined 

Products Table 6 or the use of a 

biodiesel temperature standardization 

equation. 

Marathon commented the regulations 

allow for the standardization of volume 

for other renewable fuels to be 

determined by an appropriate formula 

commonly accepted by the industry 

which may be reviewed by the EPA for 

appropriateness. They recommended 

that EPA extend this courtesy to 

biodiesel. 

The Agency acknowledges that the 

current biodiesel temperature 

standardization equation is likely not 

correct for biodiesel temperature 

standardization at ambient temperatures 

observed in the fuel distribution system. 

Based on the comments received, the 

Agency is amending the regulations to 

allow for two ways for biodiesel 

temperature standardization: (1) The 

American Petroleum Institute Refined 

Products Table 6B, as referenced in 

ASTM D1250–08, entitled, ‘‘Standard 

Guide for Use of the Petroleum 

Measurement Tables’’, and (2) a 

biodiesel temperature standardization 

equation that utilizes the 2008 data 

generated by the Minnesota Department 

of Commerce and the Renewable Energy 

Group. These two methods for biodiesel 

temperature standardization are within 

one gallon of agreement of each other 

for a 1000 gallon biodiesel batch and 

thus in very close agreement. Both ADM 

and NBB acknowledged that the 

differences between these two methods 

are insignificant and the resulting 

corrected volumes from these two 

methods of calculation are within 

accuracy tolerances of any metered 

measurement. Thus, the Agency 

believes the allowance of both of these 

methods for biodiesel temperature 

standardization will increase flexibility 

while still providing for a consistent 

generation and accounting of biodiesel 

RINs over the entire fuel delivery 

system. 

IV. Renewable Fuel Production and Use 

An assessment of the impacts of 

increased volumes of renewable fuel 

must begin with an analysis 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 an 

assessment of the potential feedstocks 

and renewable fuels that could 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 cases for 

analysis purposes. As new technologies, 

feedstocks, and fuels continue to 

develop on a daily basis, markets may 

appear differently from our projections. 

Although actual volumes and feedstocks 

may differ, we believe the projections 

made for our control cases are within 

the range of possible predictions for 

which the standards are met and allow 

for an assessment of the potential 

impacts of the increases in renewable 

fuel volumes that meet the requirements 

of EISA. 

A. Overview of Renewable Fuel 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 reference 

and control cases from which 

subsequent analyses are based. The 

reference cases are projections of 

renewable fuel volumes without the 

enactment of EISA and are described in 

Section IV.A.1. The control cases are 

projections of the volumes and types of 

renewable fuel that might be used in the 

future to comply with the EISA volume 

mandates. For the NPRM we had 

focused on one primary control case 

(see Section IV.A.2) whereas for the 

final rule we have expanded the 

analysis to include two additional 

sensitivity cases (see Section IV.A.3). 

Based on the public comments received 

as well as new information, we have 

updated the primary control case 

volumes from the NPRM to reflect what 

we believe could be a more likely set of 

volumes to analyze. We assume in each 

of the cases the same ethanolequivalence basis as was used in the 

RFS1 rulemaking to meet the standard. 

Volumes are listed in tables for this 

section in both straight-gallons and 

ethanol-equivalent gallons (i.e., times 

1.5 for biodiesel or 1.7 for cellulosic 

diesel and renewable diesel). The 

volumes included in this section are for 

2022. For intermediate years, refer to 

Section 1.2 of the RIA. 

1. Reference Cases 

Our primary reference case renewable 

fuel volumes are based on the Energy 

Information Administration’s (EIA) 

Annual Energy Outlook (AEO) 2007 

reference case projections.38 While AEO 

2007 is not as up-to-date as AEO 2008 

or AEO 2009, we chose to use AEO 2007 

because later versions of AEO already 

include the impact of increased 

renewable fuel volumes under EISA as 

well as fuel economy improvements 

under CAFE as required in EISA, 

whereas AEO 2007 did not. 

For the final rule we have also 

assessed a number of the impacts 

relative to a reference case assuming the 

mandated renewable fuel volumes 

under RFS1 from the Energy Policy Act 

of 2005 (EPAct). This allows for a more 

complete assessment of the impacts of 

the EISA volume mandates, especially 

when combined with the impacts 

assessment conducted for the RFS1 

rulemaking (though many factors have 

changed since then). Table IV.A.1–1 

summarizes the 2022 renewable fuel 

volumes for the AEO 2007 and the RFS1 

reference cases (listed in both straight 

volumes and ethanol-equivalent 

volumes). 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14741 

39Comments received from Advanced Biofuels 

Association, Testimony on June 9, 2009 suggesting 

a number of advanced biofuel technologies will be 

able to produce renewable diesel, jet fuels, gasoline, 

and gasoline component fuels (e.g. butanol, isooctane). Similar comments were received from the 

New York State Department of Environmental 

Conservation (Docket EPA–HQ–OAR–2005–0161–

2143), OPEI and AllSAFE (Docket EPA–HQ–OAR– 

2005–0161–2241), and the Low Carbon Synthetic 

Fuels Association (Docket EPA–HQ–OAR–2005– 

0161–2310). 

TABLE IV.A.1–1—REFERENCE CASE RENEWABLE FUEL VOLUMES IN 2022 

[Billion gallons] 

Source/volume type 

Advanced biofuel Non-advanced 

biofuel 

Total renewable 

fuel 

Cellulosic biofuel Biomass-based 

diesel a

Other advanced 

biofuel 

Cellulosic eth- Corn ethanol 

anol c FAME biodiesel b Imported ethanol 

AEO 2007 Straight Volume ............................. 0.25 0.38 0.64 12.29 13.56 

AEO 2007 Ethanol-Equivalent ......................... 0.25 0.58 0.64 12.29 13.76 

RFS 1 Straight Volume .................................... 0.00 0.30 0.00 7.05 7.35 

RFS 1 Ethanol-Equivalent ............................... 0.00 0.45 0.00 7.05 7.50 

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

bOnly fatty acid methyl ester (FAME) biodiesel volumes were considered. 

c Under the RFS1 reference case, we assumed the 250-million gallon cellulosic standard set by EPAct would be met primarily by corn ethanol 

plants utilizing 90% biomass for energy, thus actual production of cellulosic biofuel is zero. AEO 2007 reference case assumes actual production 

of cellulosic biofuel and therefore assumed to be 0.25 billion gallons. 

2. Primary Control Case 

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 increased volumes 

of renewable fuel, we projected a set of 

reasonable renewable fuel volumes 

based on our projection of fuels that 

could come to market. 

Although actual volumes and 

feedstocks will be different, we believe 

the projections made for our control 

cases are within the range of possible 

predictions for which the standards are 

met and allow for an assessment of the 

potential impacts of increased volumes 

of renewable fuel. Table IV.A.2–1 

summarizes the fuel types used for the 

primary control case and their 

corresponding volumes for the year 

2022. 

TABLE IV.A.2–1—PRIMARY CONTROL CASE PROJECTED RENEWABLE FUEL VOLUMES IN 2022 

[Billion gallons] 

Volume type 

Advanced biofuel Non-advanced 

biofuel Total renewable fuel Cellulosic biofuel Biomass-based diesel a Other advanced biofuel 

Corn ethanol Cellulosic 

ethanol 

Cellulosic 

diesel b

FAMEc biodiesel NCRD d Other biodiesel eImported 

ethanol 

Straight Volume ............... 4.92 6.52 0.85 0.15 0.82 2.24 15.00 30.50 

Ethanol-Equivalent ........... 4.92 11.08 1.28 0.26 1.23 2.24 15.00 36.00 

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

b Cellulosic Diesel includes at least 1.96 billion gallons (3.33 billion ethanol-equivalent gallons) from Fischer-Tropsch Biomass-to-Liquids (BTL) 

processes based on EIA’s forecast and an additional 4.56 billion gallons (7.75 billion ethanol-equivalent gallons) from this or other types of cellulosic diesel processes. cFatty acid methyl ester (FAME) biodiesel. 

d Non-Co-processed Renewable Diesel (NCRD). 

eOther Biodiesel is biodiesel that could be produced in addition to the amount needed to meet the biomass-based diesel standard.

The following subsections detail our 

rationale for projecting the amount and 

type of fuels needed to meet EISA as 

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

biofuel we have assumed that by 2022 

on a straight-volume basis about half 

would come from cellulosic ethanol and 

the other half from cellulosic diesel. On 

an ethanol-equivalent volume basis, 

cellulosic diesel would make up almost 

70% of the 16 billion gallons cellulosic 

biofuel standard. 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 by cellulosic biofuel 

and biomass-based diesel is assumed to 

come mainly from imported sugarcane 

ethanol with a smaller amount from 

additional biodiesel sources. The total 

renewable fuel volume not required to 

be comprised of advanced biofuels is 

assumed to be met with corn ethanol 

with small amounts of other grain 

starches and waste sugars. 

The main difference between the 

volumes used for the NPRM and the 

volumes used for the FRM is the 

inclusion of cellulosic diesel for the 

FRM. The NPRM made the simplifying 

assumption that the cellulosic biofuel 

standard would be met entirely with 

cellulosic ethanol. However, due to 

growing interest and recent 

developments in hydrocarbon-based or 

so-called ‘‘drop-in’’ renewable fuels as 

well as butanol, and marketplace 

challenges for consuming high volumes 

of ethanol, we have included 

projections of more non-ethanol 

renewables in our primary control case 

for the final rule.39 In the future, this 

could include various forms of ‘‘green 

hydrocarbons’’ (i.e., cellulosic gasoline, 

diesel and jet) and higher alcohols, but 

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14742 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

40Sapphire Energy plans for 135 MMgal by 2018 

and 1 Bgal by 2025; Petrosun plans for 30 MMgal/ 

yr facility; Solazyme plans for 100 MMgal by 2012/ 

13; U.S. Biofuels plans for 4 MMgal by 2010 and 

50 MMgal by full scale. Only several companies 

have thus far revealed production plans, and more 

are announced each day. It is important to realize 

that future projections are highly uncertain, and we 

have taken into account the best information we 

could acquire at the time. 

for analysis purposes, we have modeled 

it as cellulosic diesel fuel. We describe 

these fuels in greater detail in Section 

IV.B–D. We have also included some 

algae-derived biofuels in our FRM 

analyses given the large interest and 

potential for such fuels. We have 

continued to assume zero volume for 

renewable fuels or blendstocks such as 

biogas, jatropha, palm, imported 

cellulosic biofuel, and other alcohols or 

ethers in our control cases. Although we 

have not included these renewable fuels 

and blendstocks in our impact analyses, 

it is important to note that they can still 

be counted under our program if they 

meet the lifecycle thresholds and 

definitions for renewable biomass, and 

recent information suggests that some of 

them may be likely. 

a. Cellulosic Biofuel 

As discussed in our NPRM, whether 

cellulosic biofuel is ethanol will depend 

on a number of factors, including 

production costs, the form of tax 

subsidies, credit programs, and factors 

influencing the blending of biofuel into 

the fuel pool. It will also depend on the 

relative demand for gasoline and diesel 

fuel. As a result of our analyses on 

ethanol consumption (see Section IV.D) 

and continual tracking of the industry’s 

interest in hydrocarbon-based 

renewables (see Section IV.B), we have 

decided to analyze a cellulosic biofuel 

standard made up of both cellulosic 

ethanol and cellulosic diesel fuels. 

For assessing the impacts of the RFS2 

standards, we used AEO 2009 (April 

release) cellulosic ethanol volumes (4.92 

billion gallons), as well as the cellulosic 

biomass-to-liquids (BTL) diesel volumes 

(1.96 billion gallons) using FischerTropsch (FT) processes. We consider 

BTL diesel from FT processes as a 

subset of cellulosic diesel. In order to 

reach a total of 16 billion ethanolequivalent gallons, we assumed that an 

additional 4.56 billion gallons of 

cellulosic diesel could be produced 

from other cellulosic diesel processes. 

Refer to Section 1.2 of the RIA for more 

discussion. 

b. Biomass-Based Diesel 

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 could 

potentially contribute to the biomassbased diesel category, we have assumed 

for our analyses that the fuel produced 

through Fischer-Tropsch (F–T) or other 

processes and its corresponding 

feedstocks (cellulosic biomass) are 

already accounted for in the cellulosic 

biofuel category discussed previously in 

Section IV.A.2.a. 

FAME and RD processes can both 

utilize vegetable oils, rendered fats, and 

greases, and thus will generally compete 

for the same feedstock pool. We have 

based RD volumes on our forecast of 

industry plans, and expect these plants 

to use rendered fats as feedstock. Most 

biodiesel plants now have the capability 

to use vegetable or animal fats as 

feedstock, and thus our analysis 

assumes biodiesel will be made from a 

mix of inputs, depending on local 

availability, economics, and season. 

Refer to Section 1.1 of the RIA for more 

detail on FAME and RD feedstocks 

Renewable diesel production can be 

further classified as co-processed or 

non-co-processed, depending on 

whether the renewable material is 

mixed with petroleum during the 

hydrotreating operations. EISA 

specifically forbids co-processed RD 

from being counted as biomass-based 

diesel, but it can still count toward the 

total advanced biofuel requirement. At 

this time, based on current industry 

plans, we expect most, if not all, RD will 

be non-co-processed (that is, nonrefinery operations). 

Perhaps the feedstock with the 

greatest potential for providing large 

volumes of oil for the production of 

biomass-based diesel is algae. 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 feedstocks. 

For all three control cases, we have 

chosen to include 100 million gallons of 

algae-based biodiesel by 2022. We 

believe this is reasonable given several 

announcements from the algae industry 

about their production plans.40

Although algae to biofuel companies 

can focus 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. For more detail on algae as a 

feedstock, refer to Section 1.1 of the 

RIA. 

During the comment period, we 

received information from stakeholders 

on alternative biodiesel feedstocks such 

as camelina and pennycress, to name a 

few. These feedstocks are currently 

being researched due to their potential 

for lower agricultural inputs and higher 

oil yields than traditional vegetable oil 

feedstocks as well as their use in 

additional crop rotations (i.e., winter 

cover crops) on a given area of land. We 

acknowledge that as we learn more 

about the challenges and benefits to the 

use of newer feedstocks, these could be 

used in the future towards meeting the 

biomass-based diesel standard under the 

RFS2 program provided they meet the 

lifecycle thresholds and definitions for 

renewable biomass. For the purpose of 

our impacts analysis, however, we have 

chosen not to include these feedstocks 

in our analyses at this time. 

c. Other Advanced Biofuel 

As defined in EISA, advanced biofuel 

includes the cellulosic biofuel and 

biomass-based diesel categories that 

were mentioned in Sections IV.A.2.a 

and IV.A.2.b above. However, EISA 

requires greater volumes of advanced 

biofuel than just the volumes required 

of these fuels. It is entirely possible that 

greater volumes of cellulosic biofuel and 

biomass-based diesel than required by 

EISA could be produced in the future. 

Our control case assumes that the 

cellulosic biofuel volumes will not 

exceed those required under EISA. We 

do assume, however, that additional 

biodiesel than that needed to meet the 

biomass-based diesel volume will be 

used to meet the total advanced biofuel 

volume. Despite additional volumes 

assumed from biodiesel, to fully meet 

the total advanced biofuel volume 

required under EISA, other types of 

advanced biofuel are necessary through 

2022. 

We have assumed for our control case 

that the most likely sources of advanced 

fuel other than cellulosic biofuel and 

biomass-based diesel would be from 

imported sugarcane ethanol and 

perhaps limited amounts of coprocessed renewable diesel. 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 advanced biofuel standards, we 

assumed it would make up the 

difference not met by cellulosic biofuel, 

biomass-based diesel and additional 

biodiesel categories (see Table IV.A.2– 

1). The amount of imported ethanol 

required by 2022 is approximately 2.2 

Bgal. 

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41Based on total transportation ethanol reported 

in EIA’s September 2009 Monthly Energy Review 

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

dnav/pet/hist/mfeimus1a.htm). 

42Based on ethanol projected in EIA’s October 

2009 Short Term Energy Outlook less projected 

imports. Actual year-end data for 2009 was 

unavailable at the time of this FRM assessment. 

As discussed in the NPRM, other 

potential advanced biofuels could 

include for example, U.S. domestically 

produced sugarcane ethanol, 

biobutanol, and biogas. While we have 

not chosen to reflect these fuels in our 

control case, they can still be counted 

under our program assuming they meet 

the lifecycle thresholds and other 

definitions under the program. 

d. Other Renewable Fuel 

The remaining portion of total 

renewable fuel not met with advanced 

biofuel was assumed to come from cornbased ethanol (including small amounts 

from other grains and waste sugars). 

EISA effectively sets a limit for 

participation in the RFS program of 15 

Bgal of corn ethanol, and we are 

assuming for our analysis that sufficient 

corn ethanol will be produced to meet 

the 15–Bgal limit that either meets the 

20% GHG threshold or is grandfathered. 

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 

(2010–2015) in which we project that 

some fuels could compete favorably 

with corn ethanol (e.g., biodiesel and 

imported ethanol). Refer to Section 1.2 

of the RIA for more details on interim 

years. Beginning around 2016, fuels 

qualifying as advanced biofuels likely 

will be devoted to meeting the 

increasingly stringent volume mandates 

for advanced biofuel. It is also important 

to note that more than 15 Bgal of corn 

ethanol could be produced and RINs 

generated for that volume under the 

RFS2 regulations. However, obligated 

parties would not be required to 

purchase more than 15 Bgal worth of 

non-advanced biofuel RINs, e.g. corn 

ethanol RINs. 

3. Additional Control Cases Considered 

Since there is significant uncertainty 

surrounding what fuels will be 

produced to meet the 16 billion gallon 

cellulosic biofuel standard, we have 

decided to investigate two other 

sensitivity cases for our cost and 

emission impact analyses conducted for 

the rule. The first case, we refer to as the 

‘‘low-ethanol’’ control case and assume 

only 250 million gallons of cellulosic 

ethanol (from AEO 2007 reference case). 

The rest of the 16 billion gallon 

cellulosic biofuel standard is made up 

of cellulosic diesel as shown in Table 

IV.A.3–1. The second case, we refer to 

as the ‘‘high-ethanol’’ control case and 

assume the entire 16 billion gallon 

cellulosic biofuel standard is met with 

cellulosic ethanol, also shown in Table 

IV.A.3–1. 

TABLE IV.A.3–1—CONTROL CASE PROJECTED RENEWABLE FUEL VOLUMES IN 2022 

[Billion gallons] 

Case/volume type 

Advanced biofuel Non-advanced 

biofuel Total renewable fuel Cellulosic biofuel Biomass-based diesel a Other advanced biofuel 

Corn ethanol Cellulosic 

ethanol 

Cellulosic 

diesel b

FAMEc biodiesel NCRD d Other biodiesel eImported 

ethanol 

Low-Ethanol Straight Volume ............................... 0.25 9.26 0.85 0.15 0.82 2.24 15.00 28.57 

Low-Ethanol EthanolEquivalent ..................... 0.25 15.75 1.28 0.26 1.23 2.24 15.00 36.00 

High-Ethanol Straight Volume ............................... 16.00 0.00 0.85 0.15 0.82 2.24 15.00 35.06 

High-Ethanol EthanolEquivalent ..................... 16.00 0.00 1.28 0.26 1.23 2.24 15.00 36.00 

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

b Cellulosic Diesel includes 1.96 billion gallons (3.33 ethanol-equivalent billion gallons) from Fischer-Tropsch Biomass-to-Liquids (BTL) processes and 7.30 billion gallons (12.42 ethanol-equivalent billion gallons) from other types of cellulosic diesel processes for the Low-Ethanol case 

and zero cellulosic diesel in the High-Ethanol Case. cFatty acid methyl ester (FAME) biodiesel. 

d Non-Co-processed Renewable Diesel (NCRD). 

eOther Biodiesel is biodiesel that could be produced in addition to the amount needed to meet the biomass-based diesel standard.

In comparison, our primary control 

case described in Section IV.A.2, could 

be considered a ‘‘mid-ethanol’’ control 

case, as the cellulosic ethanol and diesel 

volumes analyzed are in between the 

low-ethanol and high-ethanol cases 

described in this section. We believe the 

addition of these sensitivity cases is 

useful in understanding the potential 

impacts of the renewable fuels 

standards. Refer to Section 1.2 of the 

RIA for more detail on three control 

cases analyzed as part of this rule. 

B. Renewable Fuel Production 

1. Corn/Starch Ethanol 

The majority of domestic biofuel 

production currently comes from plants 

processing corn and other similarly 

processed grains in the Midwest. 

However, there are a handful of plants 

located outside the Corn Belt and a few 

plants processing simple sugars from 

food or beverage waste. In this section, 

we summarize the present state of the 

corn/starch ethanol industry and 

discuss how we expect things to change 

in the future under the RFS2 program. 

a. Historic/Current Production 

The United States is currently the 

largest ethanol producer in the world. In 

2008, the U.S. produced nine billion 

gallons of fuel ethanol for domestic 

consumption, the majority of which 

came from locally grown corn.41 The 

nation is currently on track for 

producing over 10 billion gallons by the 

end of 2009.42 Although the U.S. 

ethanol industry has been in existence 

since the 1970s, it has rapidly expanded 

in recent years due to the phase-out of 

methyl tertiary butyl ether (MTBE), 

elevated crude oil prices, state mandates 

and tax incentives, the introduction of 

the Federal Volume Ethanol Excise Tax 

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43On 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 

ethanol blender credit replaced the former fuel 

excise tax exemption, blender’s credit, and pure 

ethanol fuel credit. However, the 2008 Farm Bill 

modified the alcohol credit so that corn ethanol gets 

a reduced credit of $0.45/gal and cellulosic biofuel 

gets a credit of $1.01/gal. 

44On May 1, 2007, EPA published a final rule (72 

FR 23900) implementing the Renewable Fuel 

Standard required by EPAct (also known as RFS1). 

RFS1 requires that 4.0 billion gallons of renewable 

fuel be blended into gasoline/diesel by 2006, 

growing to 7.5 billion gallons by 2012. 

45Based on total transportation ethanol reported 

in EIA’s September 2009 Monthly Energy Review 

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

dnav/pet/hist/mfeimus1a.htm). 

46Our November 2009 corn/starch ethanol 

industry characterization was based on a variety of 

sources including plant lists published online by 

the Renewable Fuels Association and Ethanol 

Producer Magazine (updated October 22, 2009), 

information from ethanol producer Web sites 

including press releases, and follow-up 

correspondence with producers. 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. 

47Two plants in Michigan and one in each of the 

other three states. All company information based 

on GreenShift’s Q2 2009 SEC filing available at 

http://www.greenshift.com/pdf/ 

GERS_Form10Q_Q209_FINAL.pdf. 

Credit (VEETC),43 the implementation 

of the existing RFS1 program,44 and the 

new volume requirements established 

under EISA. As shown in Figure IV.B.1– 

1, U.S. ethanol production has grown 

exponentially over the past decade. 

As of November 2009 there were 180 

corn/starch ethanol plants operating in 

the U.S. with a combined production 

capacity of approximately 12 billion 

gallons per year.46 This does not include 

idled ethanol plants, discussed later in 

this subsection. The majority of today’s 

ethanol production (91.5% by volume) 

comes from 155 plants relying 

exclusively on corn. Another 8.3% 

comes from 18 plants processing a blend 

of corn and/or similarly processed 

grains (milo, wheat, or barley). The 

remainder comes from seven small 

plants processing waste beverages or 

other waste sugars and starches. 

Of the 173 plants processing corn 

and/or other similarly processed grains, 

162 utilize dry-milling technologies and 

the remaining 11 plants rely on wetmilling processes. Dry mill ethanol 

plants grind the entire kernel and 

generally produce only one primary coproduct: 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 

plants using front-end fractionation to 

produce food-grade corn oil or back-end 

extraction to produce fuel-grade corn oil 

for the biodiesel industry. A company 

called GreenShift has corn oil extraction 

facilities located at five ethanol plants 

in Michigan, Indiana, New York and 

Wisconsin.47 Collectively, these 

facilities are designed to extract in 

excess of 7.3 million gallons of corn oil 

per year. Primafuel Solutions is another 

company offering corn oil extraction 

technologies to make existing ethanol 

plants more sustainable. For more 

information on corn oil extraction and 

other advanced technologies being 

pursued by today’s corn ethanol 

industry, refer to Section 1.4.1 of the 

RIA. 

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 


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48According to our November 2009 corn ethanol 

plant assessment, the average wet mill plant 

capacity is 125 million gallons per year—almost 

twice that of the average dry mill plant capacity (65 

million gallons per year). For more on average plant 

sizes, refer to Section 1.5 of the RIA. 

49Some plants pull steam directly from a nearby 

utility. 

50Facilities were assumed to burn natural gas if 

the plant boiler fuel was unspecified or unavailable 

on the public domain. 

51 Includes corrections from NPRM based on new 

information obtained on Cargill plants and Blue 

Flint ethanol plant. 

52CHP assessment based on information provided 

by EPA’s Combined Heat and Power Partnership, 

literature searches and correspondence with 

ethanol producers. 

53For more on CHP technology, refer to Section 

1.4.1.3 of the RIA. 

54Based on information provided by Bruce 

Woerner at Airgas on August 14, 2009. 

55Company-owned plants were assumed to be all 

those companies not denoted as locally-owned 

based on Renewable Fuels Association (RFA), 

Ethanol Biorefinery Locations (updated October 22, 

2009). For more on average plant sizes, refer to 

Section 1.5.1 of the RIA. 

plants are generally more costly to build 

but are larger in size on average.48 As 

such, 11.4% of the current grain ethanol 

production comes from the 11 

previously mentioned wet mill 

facilities. 

The remaining seven ethanol plants 

process waste beverages or waste 

sugars/starches and operate differently 

than their grain-based counterparts. 

These small production facilities do not 

require milling and operate simpler 

enzymatic fermentation processes. 

Ethanol production is a relatively 

resource-intensive process that requires 

the use of water, electricity, and steam. 

Steam needed to heat the process is 

generally produced on-site or by other 

dedicated boilers.49 The ethanol 

industry relies primarily on natural gas. 

Of today’s 180 ethanol production 

facilities, an estimated 151 burn natural 

gas 50 (exclusively), three burn a 

combination of natural gas and biomass, 

one burns natural gas and coal (although 

natural gas is the primary fuel), one 

burns a combination of natural gas, 

landfill biogas and wood, and two burn 

natural gas and syrup from the process. 

We are aware of 17 plants that burn coal 

as their primary fuel and one that burns 

a combination of coal and biomass.51

Our research suggests that three corn 

ethanol plants rely on a combination of 

waste heat and natural gas and one 

plant does not have a boiler and relies 

solely on waste heat from a nearby 

power plant. Overall, our research 

suggests that 27 plants currently utilize 

cogeneration or combined heat and 

power (CHP) technology, although 

others may exist.52 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.53

During the ethanol fermentation 

process, large amounts of carbon 

dioxide (CO2) gas are released. In some 

plants the CO2 is vented into the 

atmosphere, but where local markets 

exist, it is captured, purified, and sold 

to the food processing industry for use 

in carbonated beverages and flashfreezing applications. We are currently 

aware of 40 fuel ethanol plants that 

recover CO2 or have facilities in place to 

do so. According to Airgas, a leading gas 

distributor, the U.S. ethanol industry 

currently recovers 2 to 2.5 million tons 

of CO2 per year which translates to 

about 5–7% of all the CO2 produced by 

the industry.54

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 180 

ethanol production facilities, 163 are 

located in the 15 states comprising 

PADD 2. For a map of the government’s 

Petroleum Administration for Defense 

Districts or PADDs, refer to Figure 

IV.B.1–2. 

As a region, PADD 2 accounts for over 

94% (or 11.3 billion gallons) of today’s 

estimated ethanol production capacity, 

followed by PADD 3 (2.4%), PADDs 4 

and 1 (each with 1.3%) and PADD 5 

(0.8%). For more information on today’s 

ethanol plant locations, refer to Section 

1.5.1 of the RIA. 

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, these 

facilities account for about 80% of 

today’s online ethanol production 

capacity.55 Furthermore, nearly 30% of 

the total domestic product comes from 

40 plants owned by just three different 

companies—POET Biorefining, Archer 

Daniels Midland (ADM), and Valero 

Renewables. Valero entered the ethanol 

industry in March of 2009 when it 

acquired seven ethanol plants from 


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56 Valero recently announced that it has purchase 

agreements in place to acquire the last two Verasun 

plants in Linden, IN and Bloomington, OH and the 

former Renew Energy plant in Jefferson Junction, 

WI. 

57Based on refinery information provided at 

http://www.valero.com/OurBusiness/OurLocations/. 

58Based on our November 2009 corn/starch 

ethanol industry characterization. We are aware of 

at least one plant that has come back online since 

then. 

59EIA, Annual Energy Outlook 2009—ARRA 

Update (Table 12). 

60Sources include Renewable Fuels Association, 

Ethanol Biorefinery Locations (updated October 22, 

2009) and Ethanol Producer Magazine, Producing, 

Not Producing, Under Construction, and 

Expansions lists (last modified on October 22, 2009) 

in addition to information gathered from producer 

Web sites and follow-up correspondence. 

61Tate and Lyle is currently in the process of 

building a 115 MGY wet mill corn ethanol plant in 

Fort Dodge, IA. 

62One manure biogas plant that is currently idled 

and another that was under construction but is now 

on hold. 

63The two coal fired plants are the 

aforementioned dry mill expansion projects 

currently underway at existing ADM sites. These 

projects commenced construction on or before 

December 19, 2007 and would therefore should 

likely be grandfathered under the RFS2 rule. For 

more on our grandfathering assessment, refer to 

Section 1.5.1.4 of the RIA. 

64Official Statistics of the U.S. Department of 

Commerce, U.S. ITC. 

65Approximately 19,000 gallons directly from 

Brazil in the month of June 2009 and 4 million 

gallons from Brazil in the month of November 2009, 

zero gallons reported from November 2008–May 

2009 and July 2009–October 2009. 

66Lundell, Drake, ‘‘Brazilian Ethanol Export 

Surge to End; U.S. Customs Loophole Closed Oct. 

former ethanol giant, Verasun. The oil 

company currently has agreements in 

place to purchase three more ethanol 

plants that would bring the company’s 

ethanol production capacity to 1.1 

billion gallons per year.56 However, 

ethanol plants are much smaller than 

petroleum refineries. Valero’s smallest 

petroleum refinery in Ardmore, OK has 

about twice the throughput of all its 

ethanol plants combined.57 Still, as 

obligated parties under RFS1 and RFS2, 

the refining industry continues to show 

increased interest in biofuels. Suncor 

and Murphy Oil recently joined Valero 

as the second and third oil companies 

to purchase idled U.S. ethanol plants. 

Many refiners are also supporting the 

development of cellulosic biofuels and 

algae-based biodiesel. 

b. Forecasted Production Under RFS2 

As highlighted earlier, domestic 

ethanol production is projected to grow 

to over 10 billion gallons in 2009. And 

with over 12 billion gallons of capacity 

online as of November 2009, ethanol 

production should continue to grow in 

2010, provided plants continue to 

produce at or above today’s production 

levels. In addition, despite current 

market conditions (i.e., poor ethanol 

margins), the ethanol industry is 

expected to grow in the future under the 

RFS2 program. Although there is not a 

set corn ethanol requirement, EISA 

allows for 15 billion gallons of the 36- 

billion gallon renewable fuel standard to 

be met by conventional biofuels. We 

expect that corn ethanol will fulfill this 

requirement, provided it is more cost 

competitive than imported ethanol or 

cellulosic biofuel in the marketplace. 

In addition to the 180 aforementioned 

corn/starch ethanol plants currently 

online, 27 plants are presently idled.58

Some of these are smaller ethanol plants 

that have been idled for quite some 

time, whereas others are in a more 

temporary ‘‘hot idle’’ mode, ready to be 

restarted. In response to the economic 

downturn, a number of ethanol 

producers have idled production, halted 

construction projects, sold off plants 

and even filed for Chapter 11 

bankruptcy protection. Some corn 

ethanol companies have exited the 

industry all together (e.g., Verasun) 

whereas others are using bankruptcy as 

a means to protect themselves from 

creditors as they restructure their 

finances with the goal of becoming 

sustainable. 

Crude oil prices are expected to 

increase in the future making corn 

ethanol more economically viable. 

According to EIA’s AEO 2009, crude oil 

prices are projected to increase from 

about $80/barrel (today’s price) to $116/ 

barrel by 2022.59 As oil and gas prices 

rebound, we expect that the biofuels 

industry will as well. Since our April 

2009 industry assessment used for the 

NPRM, at least nine corn ethanol plants 

have come back online. 

For analysis purposes, we assumed 

that all 27 idled corn/starch ethanol 

plants would resume operations by 2022 

under the RFS2 program. We also 

assumed that a total of 11 new ethanol 

plants and two expansion projects 

currently under construction or in 

advanced stages of planning would 

come online.60 This includes two large 

dry mill expansion projects currently 

underway at existing ADM wet mill 

plants and two planned combination 

corn/cellulosic ethanol plants that 

received funding from DOE. While 

several of these projects are delayed or 

on hold at the moment, we expect that 

these facilities (or comparable 

replacement projects) would eventually 

come online to get the nation to 

approximately 15 billion gallons of corn 

ethanol production capacity. 

Almost 100% of conventional ethanol 

plant growth is expected to come from 

facilities processing corn or other 

similarly processed grains. And not 

surprisingly, the majority of growth 

(approximately 70% by volume) is 

expected to originate from PADD 2. 

However, growth is expected to occur in 

all PADDs. With the exception of one 

facility,61 all new corn/grain ethanol 

plants are expected to utilize dry 

milling technologies and the majority of 

new production is expected to come 

from plants burning natural gas. 

However, we anticipate that two manure 

biogas plants,62 one biomass-fired plant, 

and two coal-fired ethanol plants will be 

added to the mix.63 Of these new and 

returning idled plants, we’re aware of 

five facilities currently planning to use 

CHP technology, bringing the U.S. total 

to 32. 

The above predictions are based on 

the industry’s current near-term 

production plans. However, we 

anticipate additional growth in 

advanced ethanol production 

technologies under the RFS2 program. 

Forecasted fuel prices are projected to 

drive corn ethanol producers to 

transition from conventional boiler fuels 

to biomass feedstocks. In addition, fossil 

fuel/electricity prices will likely 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 RIA. 

2. Imported Ethanol 

As discussed in the proposal, 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. Between 

years 2000 and 2008, the volume of 

ethanol imported into the U.S. has 

ranged from 46–720 million gallons per 

year. So far this year, from January 

through November 2009, imported 

ethanol has only reached 197 million 

gallons.64 As the data show, the volume 

of imported ethanol can fluctuate 

greatly. 

In the past, the majority of volume has 

originated from countries that are part of 

the Caribbean Basin Initiative. Direct 

Brazilian imports have also made up a 

sizeable portion of total ethanol 

imported into the U.S. However, 

recently there have been relatively small 

amounts of direct imports of ethanol 

from Brazil.65 This indicates that 

current market conditions have made 

importing Brazilian ethanol directly to 

the U.S. uneconomical. Part of the 

reason for this decline in imports is the 

cessation of the duty drawback that 

became effective on October 1, 2008, but 

also changes in world sugar prices.66

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1,’’ Ethanol and Biodiesel News, Issue 45, November 

4, 2008. 

67Renewable Fuels Association (RFA), ‘‘2008 

World Fuel Ethanol Production, ’’ http:// 

www.ethanolrfa.org/industry/statistics/#E, March 

31, 2009. 

68 Ibid. 

69UNICA, ‘‘Sugarcane Industry in Brazil: Ethanol 

Sugar, Bioelectricity’’ Brochure, 2008. 

70EurObserv’ER, ‘‘Biofuels Barometer’’ July 2009, 

http://www.eurobserv-er.org/pdf/baro192.pdf. 

71EPE, ‘‘Plano Nacional de Energia 2030,’’ 

Presentation from Mauricio Tolmasquim, 2007. 

72UNICA, ‘‘Sugarcane Industry in Brazil: Ethanol, 

Sugar, Bioelectricity,’’ 2008. 

73USEPA 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). 

74Other 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. 

It is difficult to project the potential 

volume of future ethanol imports to the 

U.S. based purely on historical data. 

Rather, it is necessary to assess future 

import potential by analyzing the major 

players for foreign ethanol production 

and consumption. 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.67 Consumption of 

fuel ethanol is also dominated by the 

United States and Brazil with 

approximately 9.6 and 4.9 billion 

gallons consumed in each country, 

respectively.68 69 The EU consumed 

approximately 0.9 billion gallons of fuel 

ethanol in 2008.70

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. 

Due to uncertainties in the future 

demand for ethanol domestically and 

internationally, uncertainties in the 

actual investments made in the 

Brazilian ethanol industry, as well as 

uncertainties in future sugar prices, 

there appears to be a wide range of 

Brazilian production and domestic 

consumption estimates. The most 

current and complete estimates indicate 

that total Brazilian ethanol exports will 

likely reach 3.8–4.2 billion gallons by 

2022.71 72 73 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 about 2.2 billion gallons 

(see Table IV.A.2–1), or approximately 

55% of total Brazilian ethanol export 

estimates. This is aggressive, yet within 

the bounds of reason, therefore, we have 

made this simplifying assumption for 

the purposes of further analysis. 

Generally speaking, Brazilian ethanol 

exporters will seek routes to countries 

with the lowest costs for transportation, 

taxes, and tariffs. With respect to the 

U.S., the most likely route is through the 

Caribbean Basin Initiative (CBI).74

Brazilian ethanol entering the U.S. 

through CBI countries is not currently 

subject to the 54 cent/gal imported 

ethanol tariff and yet receives the 45 

cent/gal ethanol blender credit. In 

addition to the U.S., other countries also 

have similar tariffs on imported ethanol. 

Refer to Section 1.5.2 of the RIA for 

more details. 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 2021 was 19.2 Bgal (under the 

primary control case), then 

approximately 1.21 Bgal of ethanol 

could enter the U.S. through CBI 

countries in 2022. 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. To meet our advanced 

biofuel standard, we assumed 1.03 Bgal 

of sugarcane ethanol would be imported 

directly to the U.S. in 2022. 

3. Cellulosic Biofuel 

The majority of the biofuel currently 

produced in the United States comes 

from plants processing first-generation 

feedstocks like corn, plant oils, 

sugarcane, etc. Non-edible cellulosic 

feedstocks have the potential to greatly 

expand biofuel production, both 

volumetrically and geographically. 

Research and development on cellulosic 

biofuel technologies has exploded over 

the last few years, and plants to 

commercialize a number of these 

technologies are already beginning to 

materialize. The $1.01/gallon tax credit 

for cellulosic biofuel that was 

introduced in the 2008 Farm Bill and 

recently became effective, is also 

offering much incentive to this 

developing industry. In addition to 

today’s RFS2 program which sets 

aggressive goals for cellulosic biofuel 

production, the Department of Energy 

(DOE), Department of Agriculture 

(USDA), Department of Defense (DOD) 

and state agencies are helping to spur 

industry growth. 

a. Current State of the Industry 

There are a growing number of biofuel 

producers, biotechnology companies, 

universities and research institutes, 

start-up companies as well as refiners 

investigating cellulosic biofuel 

production. The industry is currently 

pursuing a wide range of feedstocks, 

conversion technologies and fuels. 

There is much optimism surrounding 

the long-term viability of cellulosic 

ethanol and other alcohols for gasoline 

blending. There is also great promise 

and growing interest in synthetic 

hydrocarbons like gasoline, diesel and 

jet fuel as ‘‘drop in’’ petroleum 

replacements. Some companies intend 

to start by processing corn or sugarcane 

and then transition to cellulosic 

feedstocks while others are focusing 

entirely on cellulosic materials. 

Regardless, cellulosic biofuel 

production is beginning to materialize. 

We are currently aware of over 35 

small pilot- and demonstration-level 

plants operating in North America. 

However, the main focus at these 

facilities is research and development, 

not commercial production. Most of the 

plants are rated at less than 250,000 

gallons per year and that’s if they were 

operated at capacity. Most only operate 

intermittently for the purpose of 

demonstrating that the technologies can 

be used to produce transportation fuels. 

The industry as a whole is still working 

to increase efficiency, improve yields, 

reduce costs and prove to the public, as 

well as investors, that cellulosic biofuel 

is both technologically and 

economically feasible. 

As mentioned above, a variety of 

feedstocks are being investigated for 

cellulosic biofuel production. There is a 

great deal of interest in urban waste 

(MSW and C&D debris) because it is 

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75For more information on federal support for 

biofuels, refer to Section 1.5.3.3 of the RIA. 

76Bell Bio-Energy is currently investigating other 

locations for turning MSW into diesel fuel 

according to an October 14, 2009 conversation with 

JC Bell. 

77Letter from Richard Newell, EIA Administrator 

to Lisa Jackson, EPA Administrator dated October 

29, 2009 (Table 2). 

virtually free and abundant in many 

parts of the country, including large 

metropolitan areas where the bulk of 

fuel is consumed. There is also a lot of 

interest in agricultural residues (corn 

stover, rice and other cereal straws) and 

wood (forest thinnings, wood chips, 

pulp and paper mill waste and yard 

waste). However, researchers are still 

working to find viable harvesting and 

storage solutions. Others are 

investigating the possibility of growing 

dedicated energy crops for cellulosic 

biofuel production, e.g., switchgrass, 

energy cane, sorghum, poplar, 

miscanthus and other fast-growing trees. 

While these crops have tremendous 

potential, many are starting with the 

feedstocks that are available today with 

the mentality that once the industry has 

proven itself, it will be easier to secure 

growing contracts and start producing 

energy crops. For more information on 

cellulosic feedstock availability, refer to 

preamble Section IV.B.3.d and Section 

1.1.2 of the RIA. 

The industry is also pursuing a 

number of different cellulosic 

conversion technologies and biofuels. 

Most of the technologies fall into one of 

two categories: biochemical or 

thermochemical. Biochemical 

conversion involves the use of acids 

and/or enzymes to hydrolyze cellulosic 

materials into fermentable sugars and 

lignin. Thermochemical conversion 

involves the use of heat to convert 

biomass into synthesis gas or pyrolysis 

oil for upgrading. A third technology 

pathway is emerging that involves the 

use of catalysts to depolymerize or 

reform the feedstocks into fuel. The 

technologies currently being considered 

are capable of producing cellulosic 

alcohols or hydrocarbons for the 

transportation fuel market. Many 

companies are also researching the 

potential of co-firing biomass to produce 

plant energy in addition to biofuels. For 

a more in-depth discussion on cellulosic 

technologies, refer to Section 1.4.3 of 

the RIA. 

b. Setting the 2010 Cellulosic Biofuel 

Standard 

The Energy Independence and 

Security Act (EISA) set aggressive 

cellulosic biofuel targets beginning with 

100 million gallons in 2010. However, 

EISA also supplied EPA with cellulosic 

biofuel waiver authority. For any 

calendar year in which the projected 

cellulosic biofuel production is less 

than the minimum applicable volume, 

EPA can reduce the standard based on 

the volume expected to be available that 

year. EPA is required to set the annual 

cellulosic standard by November 30th 

each year and should consider the 

annual estimate made by EIA by 

October 31st of each year. We are setting 

the 2010 standard as part of this final 

rule. 

Setting the cellulosic biofuel standard 

for 2010 represents a unique challenge. 

As discussed above, the industry is 

currently characterized by a wide range 

of companies mostly focused on 

research, development, demonstration, 

and financing their developing 

technologies. In addition, while we are 

finalizing a requirement that producers 

and importers of renewable fuel provide 

us with production outlook reports 

detailing future supply estimates (refer 

to § 80.1449), we do not have the benefit 

of this valuable cellulosic supply 

information for setting the 2010 

standard. Finally, since today’s 

cellulosic biofuel production potential 

is relatively small, and the number of 

potential producers few (as described in 

more detail below), the overall volume 

for 2010 can be heavily influenced by 

new developments, either positive or 

negative associated with even a single 

company, which can be very difficult to 

predict. This is evidenced by the 

magnitude of changes in cellulosic 

biofuel projections and the potential 

suppliers of these fuels since the 

proposal. 

In the proposal, we did a preliminary 

assessment of the cellulosic biofuel 

industry to arrive at the conclusion that 

it was possible to uphold the 100 

million gallon standard in 2010 based 

on anticipated production. At the time 

of our April 2009 NPRM assessment, we 

were aware of a handful of small pilot 

and demonstration plants that could 

help meet the 2010 standard, but the 

largest volume contributions were 

expected to come from Cello Energy and 

Range Fuels. 

Cello Energy had just started up a 20 

million gallon per year (MGY) cellulosic 

diesel plant in Bay Minette, AL. EPA 

staff visited the facility twice in 2009 to 

confirm that the first-of-its-kind 

commercial plant was mechanically 

complete and poised to produce 

cellulosic biofuel. It was assumed that 

start-up operations would go as planned 

and that the facility would be operating 

at full capacity by the end of 2009 and 

that three more 50 MGY cellulosic 

diesel plants planned for the Southeast 

could be brought online by the end of 

2010. 

At the time of our assessment, we 

were also anticipating cellulosic biofuel 

production from Range Fuels’ first 

commercial-scale plant in Soperton, GA. 

The company received a $76 million 

grant from DOE to help build a 40 MGY 

wood-based ethanol plant and they 

broke ground in November 2007. In 

January 2009, Range was awarded an 

$80 million loan guarantee from 

USDA.75 With the addition of this latest 

capital, the company seemed well on its 

way to completing construction of its 

first 10 MGY phase by the end of 2009 

and beginning production in 2010. 

Since our April 2009 industry 

assessment there have been a number of 

changes and delays in production plans 

due to technological, contractual, 

financial and other reasons. Cello 

Energy and Range Fuels have delayed or 

reduced their production plans for 2010. 

Some of the small plants expected to 

come online in 2010 have pushed back 

production to the 2011–2012 timeframe, 

e.g., Clearfuels Technology, Fulcrum 

River Biofuels, and ZeaChem. Alltech/ 

Ecofin and RSE Pulp & Chemical, two 

companies that were awarded DOE 

funding back in 2008 to build smallscale biorefineries appear to be 

permanently on hold or off the table. In 

addition, Bell Bio-Energy, a company 

that received DOD funding has since 

abandoned plans to produce cellulosic 

diesel from MSW at U.S. military 

bases.76

At the same time, there has also been 

an explosion of new companies, new 

business relationships, and new 

advances in the cellulosic biofuel 

industry. Keeping track of all of them is 

a challenge in and of it self as the 

situation can change on a daily basis. 

EIA recently provided EPA with their 

first cellulosic biofuel supply estimate 

required under CAA section 

211(o)(7)(D)(i). In a letter to the 

Administrator dated October 29, 2009, 

they arrived at a 5.04 million gallon 

estimate for 2010 based on publicly 

available information and assumptions 

made with respect production capacity 

utilization.77 A summary of the plants 

they considered is shown below in 

Table IV.B.3–1. 

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78Based on information provided by Lori Litzen, 

Environmental Permit Engineer at KL Energy on 

December 10, 2009. 

79Based on Web site information, comments 

submitted in response to our proposal, and a 

follow-up phone call with Iogen Executive VP, Jeff 

Passmore on December 17, 2009. 

TABLE IV.B.3–1—EIA’S PROJECTED CELLULOSIC BIOFUEL PLANT PRODUCTION CAPACITIES FOR 2010 

Online Company Location Product 

Capacity 

(million 

gallons) 

Expected 

utilization (%) 

Production 

(million 

gallons) 3

2007 ......................... KL Process Design .. Upton, WY ................ Ethanol ..................... 1.5 10 0.15 

2008 ......................... Verenium .................. Jennings, LA ............ Ethanol ..................... 1.4 10 0.14 

2008 ......................... Terrabon ................... Bryan, TX ................. Bio-Crude ................. 0.93 10 0.09 

2010 ......................... Zeachem .................. Boardman, OR ......... Ethanol ..................... 1.5 10 0.15 

2010 ......................... Cello Energy ............ Bay Minette, AL ....... Diesel ....................... 20.0 10 1 2.00 

2010 ......................... Range Fuels ............. Soperton, GA ........... Ethanol ..................... 5.0 2 50 2.5 

Total .................. .................................. .................................. .................................. 30.35 ........................ 5.04 

Notes: 1. Cello Energy is assigned a 10-percent utilization factor as they have not been able to run on a continuous basis long enough to 

apply for a Synthetic Minor Operating Permit or produce significant amounts of fuel during 2009. 2. It is estimated that only half the 2010 projected capacity (10 million gallons per year) will be a qualified fuel. 3. The production from these facilities in 2009 is not surveyed by EIA or EPA. 

In addition to receiving EIA’s 

information and coordinating with them 

and other offices in DOE, we have 

initiated meetings and conversations 

with over 30 up-and-coming advanced 

biofuel companies to verify publicly 

available information, obtain 

confidential business information, and 

better assess the near-term cellulosic 

biofuel production potential for use in 

setting the 2010 standard. What we have 

found is that the cellulosic biofuel 

landscape has continued to evolve. 

Based on information obtained, not only 

do we project significantly different 

production volumes on a company-bycompany basis, but the list of potential 

producers of cellulosic biofuel in 2010 

is also significantly different than that 

identified by EIA. 

Overall, our industry assessment 

suggests that it is difficult to rely on 

commercial production from small pilot 

or demonstration-level plants. The 

primary purpose of these facilities is to 

prove that a technology works and 

demonstrate to investors that the 

process is capable of being scaled up to 

support a larger commercial plant. 

Small plants are cheaper to build to 

demonstrate technology than larger 

plants, but the operating costs ($/gal) are 

higher due to their small scale. As a 

result, it’s not economical for most of 

these facilities to operate continuously. 

Most of these plants are regularly shut 

down and restarted as needed as part of 

the research and development process. 

Due to their intermittent nature, most of 

these plants operate at a fraction of their 

rated capacity, some less than the 10% 

utilization rate assumed by EIA. In 

addition, few companies plan on 

making their biofuel available for 

commercial sale. 

However, there are at least two 

cellulosic biofuel companies currently 

operating demonstration plants in the 

U.S. and Canada that could produce fuel 

commercially in 2010. The first is KL 

Energy Corporation, a company we 

considered for the NPRM with a 1.5 

MGY cellulosic ethanol plant in Upton, 

WY. This plant was considered by EIA 

and is included in Table IV.B.3–1. The 

second is Iogen’s cellulosic ethanol 

plant in Ottawa, Canada with a 0.5 MGY 

capacity. Iogen’s commercial 

demonstration plant was referenced by 

EIA as a potential foreign source for 

cellulosic biofuel but was not included 

in their final table. In addition to these 

online demonstration plants, there are 

three additional companies not on EIA’s 

list that are currently building 

demonstration-level cellulosic biofuel 

plants in North America that are 

scheduled to come online in 2010. This 

includes DuPont Danisco Cellulosic 

Ethanol and Fiberight, companies 

building demonstration plants in the 

U.S. and Enerkem, a company building 

a demonstration plant in Canada. Cello 

Energy’s plant in Bay Minette, AL 

continues to offer additional potential 

for cellulosic biofuel in 2010. And 

finally, Dynamotive, a company that 

currently has two biomass-based 

pyrolysis oil production plants in 

Canada is another potential source of 

cellulosic biofuel in 2010. All seven 

aforementioned companies are 

discussed in greater detail below along 

with Range Fuels. 

KL Energy Corporation (KL Energy), 

through its majority-owned Western 

Biomass Energy, LLC (WBE) located in 

Upton, WY, is designed to convert wood 

products and wood waste products into 

ethanol. Since the end of construction 

in September 2007, equipment 

commissioning and process revisions 

continued until the October 2009 

startup. The plant was built as a 1.5 

MGY demonstration plant and was 

designed to both facilitate research and 

operate commercially. It is KL Energy’s 

intent that WBE’s future use will 

involve the production and sale of small 

but commercial-quality volumes of 

ethanol and lignin co-product. The 

company’s current 2010 goal is for WBE 

to generate RINs under the RFS2 

program.78

Iogen is responsible for opening the 

first commercial demonstration 

cellulosic ethanol plant in North 

America. Iogen’s plant located in 

Ottawa, Canada has been producing 

cellulosic ethanol from wheat straw 

since 2004. Like KL Energy, Iogen has 

slowly been ramping up production at 

its 0.5 MGY plant. According to the 

company’s Web site, they produced 

approximately 24,000 gallons in 2004 

and 34,000 gallons in 2005. Production 

dropped dramatically in 2006 and 2007 

but came back strong with 55,000 

gallons in 2008. Iogen recently 

produced over 150,000 gallons of 

ethanol from the demonstration plant in 

2009. Iogen also recently became the 

first cellulosic ethanol producer to sell 

its advanced biofuel at a retail service 

station in Canada. Their cellulosic 

ethanol was blended to make E10 

available for sale to consumers at an 

Ottawa Shell station. Iogen also recently 

announced plans to build its first 

commercial scale plant in Prince Albert, 

Saskatchewan in the 2011/2012 

timeframe. Based on the company’s 

location and operating status, Iogen 

certainly has the potential to participate 

in the RFS2 program. However, at this 

time, we are not expecting them to 

import any cellulosic ethanol into the 

U.S. in 2010.79

DuPont Danisco Cellulosic Ethanol, 

LLC (DDCE), a joint venture between 

DuPont and Danisco, is another 

potential source for cellulosic biofuel in 

2010. DDCE received funding from the 

State of Tennessee and the University of 

Tennessee to build a small 0.25 MGY 

demonstration plant in Vonore, TN to 

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80Based on a December 16, 2009 telephone 

conversation with DDCE Director of Corporate 

Communications, Jennifer Hutchins and follow-up 

e-mail correspondence. 

81Refer to December 4, 2009 DOE press release 

entitled, ‘‘Recovery Act Announcement: Secretaries 

Chu and Vilsack Announce More Than $600 

Million Investment in Advanced Biorefinery 

Projects.’’ 

82Based on an October 14, 2009 meeting with 

Enerkem and follow-up telephone conversation 

with VP of Government Affairs, Marie-Helene 

Labrie on December 14, 2009. 

83Based on a December 15, 2009 telephone 

conversation with Fiberight CEO, Craig Stuart-Paul 

and follow-up e-mail correspondence. 

84Based on a November 9, 2009 telephone 

conversation with Cello Energy CEO, Jack Boykin. 

85According to Dynamotive’s Web site, the 

Guelph plant has a capacity to convert 200 tonnes 

of biomass into BioOil per day. If all modules are 

fully operational, the plant has the ability to process 

66,000 dry tons of biomass per year with an energy 

output equivalent to 130,000 barrels of oil. The 

West Lorne plant has a capacity to convert 130 

tonnes of biomass into BioOil per day which, if 

proportional to the Guelph plant, translates to an 

energy-equivalent of 84,500 barrels of oil. 

According to a November 3, 2009 press release, 

Dynamotive has contracts in place to supply a U.S.- 

based client with at least nine shipments of BioOil 

in 2010. 

86Based on a November 5, 2009 telephone 

conversation with Range Fuels VP of Government 

Affairs, Bill Schafer. 

87For more information, refer to Section 1.5.3.2 

of the RIA. 

pursue switchgrass-to-ethanol 

production. According to DDCE, 

construction commenced in October 

2008 and the plant is now mechanically 

complete and undergoing start-up 

operations. The facility is scheduled to 

come online by the end of January and 

the company hopes to operate at or 

around 50% of production capacity in 

2010. According to the DDCE, the 

objective in Vonore is to validate 

processes and data for commercial 

scale-up, not to make profits. However, 

the company does plan to sell the 

cellulosic ethanol it produces.80

Enerkem is another company 

pursuing cellulosic ethanol production. 

The Canadian-based company was 

recently announced as a recipient of a 

joint $50 million grant from DOE and 

USDA to build a 10 MGY woody 

biomass-to-ethanol plant in Pontotoc, 

MS.81 The U.S. plant is not scheduled 

to come online until 2012, but Enerkem 

is currently building a 1.3 MGY 

demonstration plant in Westbury, 

Quebec. According to the company, 

plant construction in Westbury started 

in October 2007 and the facility is 

currently scheduled to come online 

around the middle of 2010. While it’s 

unclear at this time whether the 

cellulosic ethanol produced will be 

exported to the United States, Enerkem 

has expressed interest in selling its fuel 

commercially.82

Additional cellulosic biofuel could 

come from Fiberight, LLC (Fiberight) in 

2010. We recently became aware of this 

start-up company and contacted them to 

learn more about their process and 

cellulosic biofuel production plans. 

According to Fiberight, they have been 

operating a pilot-scale facility in 

Lawrenceville, VA for three years. They 

have developed a proprietary process 

that not only fractionates MSW but 

biologically converts the non-recyclable 

portion into cellulosic ethanol and 

biochemicals. Fiberight recently 

purchased a shut down corn ethanol 

plant in Blairstown, IA and plans to 

convert it to become MSW-to-ethanol 

capable. According to the company, 

construction is currently underway and 

the goal is to bring the 2 MGY 

demonstration plant online by February 

or March, 2010. If the plant starts up 

according to plan, the company intends 

on making cellulosic ethanol 

commercially available in 2010 and 

generating RINS under the RFS2 

program. Fiberight’s long-term goal is to 

expand the Blairstown plant to a 5–8 

MGY capacity and build other small 

commercial plants around the country 

that could convert MSW into fuel.83

Cello Energy, a company considered 

in the proposal, continues to be another 

viable source for cellulosic biofuel in 

2010. Despite recent legal issues which 

have constrained the company’s capital, 

Cello Energy is still pursuing cellulosic 

diesel production. According to the 

company, they are currently working to 

resolve materials handling and 

processing issues that surfaced when 

they attempted to scale up production to 

20 MGY from a previously operated 

demonstration plant. As of November 

2009, they were waiting for new 

equipment to be ordered and installed 

which they hoped would allow for 

operations to be restarted as early as 

February or March, 2010. Cello’s other 

planned commercial facilities are 

currently on hold until the Bay Minette 

plant is operational.84

Another potential supplier of 

cellulosic biofuel is Dynamotive Energy 

Systems (Dynamotive) headquartered in 

Vancouver, Canada. Dynamotive 

currently has two plants in West Lorne 

and Guelph, Ontario that produce 

biomass-based pyrolysis oil (also known 

as ‘‘BioOil’’) for industrial applications. 

The BioOil production capacity between 

the two plants is estimated at around 9 

MGY, but both plants are currently 

operating at a fraction of their rated 

capacity.85 However, according to a 

recent press release, Dynamotive has 

contracts in place to supply a U.S.-based 

client with at least nine shipments of 

BioOil in 2010. If Dynamotive’s BioOil 

is used as heating oil or upgraded to 

transportation fuel, it could potentially 

count towards meeting the cellulosic 

biofuel standard in 2010. 

As for the Range Fuels plant, 

construction of phase one in Soperton, 

GA is about 85% complete, with startup planned for mid-2010. However, 

there have been some changes to the 

scope of the project that will limit the 

amount of cellulosic biofuel that can be 

produced in 2010. The initial capacity 

has been reduced from 10 to 4 million 

gallons per year. In addition, since they 

plan to start up the plant using a 

methanol catalyst they are not expected 

to produce qualifying renewable fuel in 

2010. During phase two of their project, 

currently slated for mid-2012, Range 

plans to expand production at the 

Soperton plant and transition from a 

methanol to a mixed alcohol catalyst. 

This will allow for a greater alcohol 

production potential as well as a greater 

cellulosic biofuel production 

potential.86

Overall, our most recent industry 

assessment suggests that there could 

potentially be over 30 MGY of cellulosic 

biofuel production capacity online by 

the end of 2010.87 However, since most 

of the plants are still under construction 

today, the amount of cellulosic biofuel 

produced in 2010 will be contingent 

upon when and if these plants come 

online and whether the projects get 

delayed due to funding or other reasons. 

In addition, based on our discussions 

with the developing industry, it is clear 

that we cannot count on demonstration 

plants to produce at or near capacity in 

2010, or in their first few years of 

operation for that matter. The amount of 

cellulosic biofuel actually realized will 

depend on whether the process works, 

the efficiency of the process, and how 

regularly the plant is run. As mentioned 

earlier, most small plants, including 

commercial demonstration plants, are 

not operated continuously. As such, we 

cannot base the standard on these plants 

running at capacity—at least until the 

industry develops further and proves 

that such rates are achievable. We 

currently estimate that production from 

first-of-its kind plants could be 

somewhere in the 25–50% range in 

2010. Together, the implementation 

timelines and anticipated production 

levels of the plants described above 

brings the cellulosic biofuel supply 

estimate to somewhere in the 6–13 

million gallon range for 2010. 

In addition, it is unclear how much 

we can rely on Canadian plants for 

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88Although BlueFire is still working on obtaining 

financing to build its first demonstration plant, it 

has received two installments of federal funding 

towards its first planned commercial-scale plant. 

The 19 MGY plant planned for Fulton, MS 

(originally planned for Southern California) was 

awarded $40 million from DOE on February 28, 

2008 and another $81.1 million from DOE and 

USDA on December 4, 2009. 

cellulosic biofuel in 2010. Although we 

currently receive some conventional 

biofuel imports from Canada and many 

of the aforementioned Canadian 

companies have U.S. markets in mind, 

the country also has its own renewable 

fuel initiatives that could keep much of 

the cellulosic biofuel produced from 

coming to the United States, e.g., Iogen. 

Finally, it’s unclear whether all fuel 

produced by these facilities will qualify 

as cellulosic biofuel under the RFS2 

program. Several of the companies are 

producing fuels or using feedstocks 

which may not in fact qualify as 

cellulosic biofuel once we receive their 

detailed registration information. 

Factoring in these considerations, the 

cellulosic biofuel potential from the six 

more likely companies described above 

could result in several different 

production scenarios in the 

neighborhood of the recent EIA 

estimate. We believe this estimate of 5 

million gallons or 6.5 ethanolequivalent million gallons represents a 

reasonable yet achievable level for the 

cellulosic biofuel standard in 2010 

considering the degree of uncertainty 

involved with setting the standard for 

the first year. As mentioned earlier, we 

believe standard setting will be easier in 

future years once the industry matures, 

we start receiving production outlook 

reports and there is less uncertainty 

regarding feasibility of cellulosic biofuel 

production. 

c. Current Production Outlook for 2011 

and Beyond 

Since the proposal, we have also 

learned about a number of other 

cellulosic biofuel projects in addition to 

those described above. This includes 

commercial U.S. production plans by 

Coskata, Enerkem and Vercipia. 

However, production isn’t slated to 

begin until 2011 or later and the same 

is true for most of the other larger plants 

we’re aware of that are currently under 

development. Nonetheless, while 

cellulosic biofuel production in 2010 

may be limited, it is remarkable how 

much progress the industry has made in 

such a short time, and there is a 

tremendous growth opportunity for 

cellulosic biofuels over the next several 

years. 

Most of the cellulosic biofuel 

companies we’ve talked to are in 

different stages of proving their 

technologies. Regardless of where they 

are at, many have fallen behind their 

original commercialization schedules. 

As with any new technology, there have 

been delays associated with scaling up 

capacity, i.e., bugs to work out going 

from pilot to demonstration to 

commercialization. However, most are 

saying it’s not the technologies that are 

delaying commercialization, it is lack of 

available funding. Obtaining capital has 

been very challenging given the current 

recession and the banking sector’s 

financial difficulties. This is especially 

true for start-up companies that do not 

have access to capital through existing 

investors, plant profits, etc. From what 

we understand, banks are looking for 

cellulosic companies to be able to show 

that their plants are easily ‘‘scalable’’ or 

expandable to commercial size. Many 

are only considering companies that 

have built plants to one-tenth of 

commercial scale and have logged many 

hours of continuous operation. 

The government is currently trying to 

help in this area. To date, the 

Department of Energy (DOE) and the 

Department of Agriculture (USDA) have 

allocated over $720 million in federal 

funding to help build pilot and 

demonstration-scale biorefineries 

employing advanced technologies in the 

United States. The largest installment 

from Recovery Act funding was recently 

announced on December 4, 2009 and 

includes funding for a series of larger 

commercial demonstration plants 

including cellulosic ethanol projects by 

Enerkem and INEOS New Planet 

BioEnergy, LLC. DOE has also issued 

grants to help fund some of the first 

commercial cellulosic biofuel plants. 

Current recipients include Abengoa 

Bioenergy, BlueFire Ethanol 88 and 

POET Biorefining in addition to Range 

Fuels. DOE and USDA are also issuing 

loan guarantees to help support the upand-coming cellulosic biofuels industry 

and funding research and development. 

Many states are also providing 

assistance. For more information on 

government support for biofuels, refer to 

Section 1.5.3.3 of the RIA. 

The refining industry is also helping 

to fund cellulosic biofuel R&D efforts 

and some of the first commercial plants. 

Many of the major oil companies have 

invested in advanced second-generation 

biofuels over the past 12–18 months. A 

few refiners (e.g., BP and Shell) have 

even entered into joint ventures to 

become cellulosic biofuel producers. 

General Motors and other vehicle/ 

engine manufacturers are also providing 

financial support to help with research 

and development. 

A summary of some of the cellulosic 

biofuel companies with near-term 

commercialization plans in North 

America is provided in Table IV.B.3–2. 

The capacities presented represent 

maximum annual average throughput 

based on each company’s current 

production plans. However, as noted, 

capacity does not necessarily translate 

to production. Actual production of 

cellulosic biofuel will likely be well 

below capacity, especially in the early 

years of production. We will continue to 

track these companies and the cellulosic 

biofuel industry as a whole throughout 

the duration of the RFS2 program. In 

addition, we will continue to 

collaborate with EIA in annual standard 

setting. A more detailed discussion of 

the plants corresponding to these 

company estimates is provided in 

Section 1.5.3 of the RIA. 

BILLING CODE 6560–50–P 

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89 It is important to note that our original plant 

siting analysis for cellulosic ethanol facilities used 

the most current version of outputs from FASOM 

at the time, which was from April 2008. The siting 

analysis was used to inform the air quality 

modeling, which requires long leadtimes. Since 

then, FASOM has been updated to reflect better 

assumptions. Therefore, the version used for the 

FRM in Section VIII on economic impacts is 

different from the one used for the plant siting 

analysis in the NPRM. We do not believe that the 

differences between the two versions are enough to 

have a major impact on the plant siting analysis. 

BILLING CODE 6560–50–C 

d. Feedstock Availability 

A wide variety of feedstocks can be 

used for cellulosic biofuel production, 

including: Agricultural residues, 

forestry biomass, certain renewable 

portions of municipal solid waste and 

construction and demolition waste (i.e., 

separated food, yard and incidental, and 

post-recycled paper and wood waste as 

discussed in Section II.B.4) and energy 

crops. These feedstocks are currently 

much more difficult to convert into 

biofuel than traditional corn/starch 

crops or at least require new and 

different processes because of the more 

complex structure of cellulosic material. 

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 determine the most 

economical volume of agriculture 

residues, energy crops, and forestry 

resources (see Section VIII for more 

details on the FASOM) used to meet the 

standard. We supplemented these 

estimates with feedstock assessment 

estimates for the biomass portions of 

municipal solid waste and construction 

and demolition waste.89

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 


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90EPA. Municipal Solid Waste Generation, 

Recycling, and Disposal in the United States: Facts 

and figures for 2008. 

91Wiltsee, G., ‘‘Urban Wood Waste Resource 

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

Renewable Energy Laboratory, November 1998. 

92Biocycle, ‘‘The State of Garbage in America,’’ 

Vol. 49, No. 12, December 2008, p. 22. 

93Assuming 90 gal/dry ton ethanol conversion 

yield for urban waste in 2022. 94Chambers, J., ‘‘Hurricane Katrina’s Carbon 

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

318, 2007. 

95Elbehri, 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. 

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

Stover Supplies,’’ American Society of Agronomy 

99:1–11, 2007. 

cellulosic biofuel by 2022. Refer to 

Section IV.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 incurs a fee for its 

disposal may be among the first to be 

used. Urban wastes are used in a variety 

of ways. Most commonly, wastes are 

ground into mulch, dumped into landfills, or incinerated. We describe two 

components of urban waste, municipal 

solid waste (MSW) and construction 

and demolition (C&D) debris, below. 

MSW consists of paper, glass, metals, 

plastics, wood, yard trimmings, food 

scraps, rubber, leather, textiles, etc. The 

portion of MSW that can qualify as 

renewable biomass under the program is 

discussed in Section II.B.4.d. The bulk 

of the biogenic portion of MSW that can 

be converted into biofuel is cellulosic 

material such as wood, yard trimmings, 

paper, and much of food wastes. Paper 

made up approximately 31% of the total 

MSW generated in 2008.90 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. 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 a total of 44.5 

million dry tons of MSW (wood, yard 

trimmings, paper, and food waste) 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.91 92 Between the proposal and 

this final rule, we have updated the 

assumptions noted above based on 

newer reports. It should be noted, 

however, that our estimates of urban 

waste availability have not changed 

significantly between the proposal and 

the final rule. We assumed that 

approximately 26 million dry tons (of 

the total 44.5 million dry tons) could be 

used to produce biofuels. However, 

many areas of the U.S. (e.g., much of the 

Rocky Mountains) have such sparse 

resources that an MSW and C&D 

cellulosic facility would not likely be 

justifiable. We did assume that in areas 

with other 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 2.3 

ethanol-equivalent billion gallons of 

fuel.93 Note that some processes are 

likely to also process other portions of 

MSW (e.g., plastics, rubbers) into fuel, 

but we have only accounted for the 

portion expected to qualify as renewable 

fuel and produce RINs. 

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.94

Katrina also generated over 100 million 

tons of residential debris, not including 

the commercial sector. Much of this 

waste would likely be disposed of and 

therefore go unused. Collection of this 

material for the generation of biofuel 

could be a better alternative use for this 

waste. While we acknowledge this 

material could provide a large source in 

the short-term, natural disasters are 

highly variable, making it hard to 

predict amounts of material available in 

the future. Thus, for our analyses we 

have not included natural disaster 

renewable biomass in our estimates. 

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 residues are 

corn stover (the stalks, leaves, and/or 

cobs) and straw from wheat, rice, barley, 

and oats. These U.S. crops and others 

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.95 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 raise 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 shows that under 

current rotation and tillage practices, 

about 30% of corn 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.96 The same study shows that if 

farmers convert to no-till corn 

management and total stover production 

does 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 

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97Wilhelm, W.W. et al., ‘‘Corn Stover to Sustain 

Soil Organic Carbon Further Constrains Biomass 

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

98Assuming 92.3 gal/dry ton ethanol conversion 

yield for corn stover in 2022. 

99Bagasse 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 and sorghum 

being an agricultural feedstock. 

100Smith, 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. 

101USDA-Forest Service. ‘‘Timber Products 

Output Mapmaker Version 1.0.’’ 2004. 

102Assuming 16 Bgal cellulosic biofuel total, 2.3 

Bgal from Urban Waste; 13.7 Bgal of cellulosic 

biofuel for ag residues, forestry biomass, and/or 

energy crops would be needed. 

103Beside 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. 

104Biomass 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. 

erosion.97 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 no 

stover is removable on conventional 

tilled lands, 35% of stover is removable 

on conservation tilled lands, and 50% is 

removable on 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 by region due to local differences. 

Given the current understanding of 

sustainable removal rates, we believe 

that such assumptions are reasonably 

justified. Based on our research, we also 

note that calculating 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. 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 sitespecific 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, 

however, we had limited data on which 

to accurately apply this approach and 

therefore assumed the removal 

guidelines based on tillage practices. 

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 (4.9 ethanolequivalent Bgal).98 Smaller 

contributions are expected to come from 

other crop residues including sugarcane 

bagasse (0.6 ethanol-equivalent Bgal), 

wheat residues (0.1 ethanol-equivalent 

Bgal), and sweet sorghum pulp (0.1 

ethanol-equivalent Bgal).99

The U.S. also 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.100 Logging 

residues are produced in conventional 

harvest operations, forest management 

activities, and clearing operations. In 

2004, these operations generated 

approximately 67 million dry tons of 

forest residues that were left uncollected 

at harvest sites.101 Other feedstocks 

include those from other removal 

residues, thinnings from timberland, 

and primary mill residues. 

For the NPRM, FASOM was not able 

to model forestry biomass as a potential 

feedstock. As a result, we relied on 

USDA-Forest Service (FS) for 

information on the forestry sector at the 

time. For the final rule, we were able to 

incorporate the forestry sector model in 

FASOM. 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, our modeling of forestry 

biomass excluded such material. The 

FASOM model estimated that 

approximately 0.1 ethanol-equivalent 

billion gallons would be produced from 

forestry biomass 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 for energy 

purposes. Various perennial plants have 

been researched as potential dedicated 

feedstocks, including switchgrass, 

mixed prairie grasses, hybrid poplar, 

miscanthus, energy cane, energy 

sorghum, and willow trees. Refer to 

Section 1.1.2.2 of the RIA for more 

information on the benefits and 

challenges with using dedicated energy 

crops. 

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 (7.9 ethanol-equivalent Bgal).102

FASOM covers all cropland and 

pastureland in production in the 48 

contiguous United States. For the 

NPRM, FASOM did not contain all 

categories of grassland and rangeland 

captured in USDA’s Major Land Use 

data sets. For the final rule, FASOM 

accounts for all major land categories, 

including forestland and rangeland. All 

crop production, including dedicated 

energy crops, takes place on cropland. 

Land categories that can be converted to 

cropland production include cropland 

pasture, forest pasture, and forestland. 

More detail can be found in Chapter VIII 

of this preamble. Furthermore, we 

constrained FASOM to be consistent 

with the 2008 Farm Bill and assumed 32 

million acres would stay in 

Conservation Reserve Program (CRP).103

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 to meet EISA could be 

significant, similar to our FASOM 

modeling results for the final rule.104

iv. Summary of Cellulosic Feedstocks 

for 2022 

Table IV.B.3–3 summarizes our 

internal estimate of the types of 

cellulosic feedstocks projected to be 

used and their corresponding volume 

contribution to 16 billion gallons 

cellulosic biofuel by 2022 for the 

purposes of our impacts assessment. 

The majority of feedstock is projected to 

come from dedicated energy crops. 

Other feedstocks include agricultural 

residues, forestry biomass, and urban 

waste. 

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105 Volumes are represented here as ethanolequivalent volumes, a mix of diesel and ethanol 

volumes as described in Section IV.A, above. 106See 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 II.B.2, as published in the 

Federal Register Vol. 72, No. 83, p. 23917. 

107For more detailed discussion of the definition 

of coprocessing and its implications for compliance 

with EISA, see Section II.B.1 of this preamble. 

108Capacity data taken from National Biodiesel 

Board as of November 2009. 

109Assessment of plant capital cost based on 

USDA production cost models. A publication 

describing USDA modeling of biodiesel production 

costs can be found in Bioresource Technology 

97(2006) 671–8. 

110Capacity data taken from National Biodiesel 

Board as of November 2009. Production, import, 

and export figures taken from EIA Monthly Energy 

Review, Table 10.4 as of December 2009. 

TABLE IV.B.3–3—CELLULOSIC FEEDSTOCKS ASSUMED TO MEET EISA IN

2022 105

Feedstock 

Volume 

(ethanolequivalent 

Bgal) 

Agricultural Residues ................ 5.7 

Corn Stover ....................... 4.9 

Sugarcane Bagasse .......... 0.6 

Wheat Residue .................. 0.1 

Sweet Sorghum Pulp ........ 0.1 

Forestry Biomass ...................... 0.1 

Urban Waste ............................. 2.3 

Dedicated Energy Crops 

(Switchgrass) ........................ 7.9 

Total ...................................... 16.0 

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 

storage stability) for which the engines 

have been designed. The definition of 

biodiesel given in applicable regulations 

is sufficiently broad to be inclusive of 

both fuels.106 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 

the RFS2 volume requirements.107

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 

processes are at various stages of 

development, but due to uncertainty on 

production timelines, we didn’t include 

these fuels in the biomass-based diesel 

impact assessments. 

a. Historic and Projected Production 

i. Biodiesel 

As of November 2009, the aggregate 

production capacity of biodiesel plants 

in the U.S. was estimated at 2.8 billion 

gallons per year across approximately 

191 facilities.108 (However, at the time 

of this writing it is anticipated that 

capacity utilization will be 

approximately 17% for calendar year 

2009.) 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 IV.B.4–1 gives data on U.S. 

biodiesel production and use for recent 

years, including net domestic use after 

accounting for imports and exports. 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 

along a path of more small, privatelyowned plants in comparison to the 

ethanol industry, with median size less 

than 10 million gallons/yr.109 These 

small plants, with relatively low costs 

other than feedstock, have generally 

been able to survive producing well 

below their nameplate capacities. 

TABLE IV.B.4–1—SUMMARY OF U.S. BIODIESEL PRODUCTION AND USE

[Million gallons] 110

Year 

Domestic 

production 

capacity 

Domestic total production 

Apparent 

capacity 

utilization 

(percent) 

Net domestic biodiesel use 

Net 

domestic 

use as 

percent of 

production 

2004 ........................................... 245 28 .............................................. 11 27 .............................................. 96 

2005 ........................................... 395 91 .............................................. 23 91 .............................................. 100 

2006 ........................................... 792 250 ............................................ 32 261 ............................................ 104 

2007 ........................................... 1,809 490 ............................................ 27 358 ............................................ 73 

2008 ........................................... 2,610 776 ............................................ 30 413 ............................................ 53 

2009 ........................................... 2,806 475 (est.) .................................. 17 296 (est.) .................................. 62 

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. 

During 2004–2006, demand for 

biodiesel grew rapidly, but the trend of 

increasing sales was quickly surpassed 

by construction and start-up of new 

plants Since then, periods of high 

commodity prices followed by reduced 

demand for transportation fuel during 

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111 Ibid. 112 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. 

113 2008 capacity data taken from National 

Biodiesel Board; production figures taken from EIA 

Monthly Energy Review, Table 10.4 as of October 

2009. 

the economic downturn have caused 

additional strain on the industry beyond 

the overcapacity situation. Biodiesel 

producers were able to find additional 

markets overseas, and a significant 

portion of the 2007 and 2008 production 

was exported to Europe where fuel 

prices and additional tax subsidies 

helped offset high feedstock costs. 

However, the EU enacted a tariff to 

protect domestic producers early in 

2009, after which exports dropped to a 

small fraction of production.111 We 

understand there may be some 

additional export markets developing 

within North America, but given the 

uncertainty at this time, we do not 

account for any biodiesel exports in our 

projections. 

To perform our impacts analyses for 

this rule, 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 

industry capacity to be much closer to 

1.67 billion gallons per year by 2022 

(based on the volume requirements to 

meet the standard; see Section IV.A.2). 

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.112 Going forward 

producers will compete for feedstocks 

and markets may consolidate. During 

this period the number of operating 

plants is expected to shrink, with 

surviving plants utilizing 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 85%. Table IV.B.4–2 

summarizes this forecast. See Section 

1.5.4 of the RIA for more details. 

TABLE IV.B.4–2—SUMMARY OF PROJECTED BIODIESEL INDUSTRY CHARACTERIZATION USED IN OUR ANALYSES 113

2008 2022 

Total production capacity on-line (million gal/yr) ............................................................................................................................. 2,610 1,968 

Number of operating plants ............................................................................................................................................................. 176 121 

Median plant size (million gal/yr) ..................................................................................................................................................... 5 5 

Total biodiesel production (million gal) ............................................................................................................................................ 776 1,670 

Average plant utilization .................................................................................................................................................................. 0.30 0.85 

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. 

As a result of the oxygen and olefins 

in the feedstock being removed, 

renewable diesel has storage, stability, 

and shipping properties equivalent to 

petroleum diesel. This allows renewable 

diesel fuel to be shipped in existing 

petroleum pipelines used for 

transporting fuels, thus avoiding a 

significant issue with distribution of 

biodiesel. For more on fuel distribution, 

refer to Section IV.C. 

Considering that this industry is still 

in development and that there are no 

long-term projections of production 

volume, we base our volume estimate of 

150 MMgal/yr primarily on recent 

industry project announcements 

involving proven technology. Due to the 

current status of tax incentives, we 

project all of this fuel will be produced 

at stand-alone facilities. 

b. Feedstock Availability 

Publically available industry 

information along with agricultural 

commodity modeling we have done for 

this rule (see Section VIII.A) suggests 

that the three largest sources of 

feedstock for biodiesel will be rendered 

animal fats, soy oil, and corn oil 

extracted from dry mill ethanol 

facilities. Renewable diesel plants are 

expected to use solely animal fats due 

to the fact that these feedstocks are 

cheaper than vegetable oils and the 

process can handle them without issue. 

Comments we have received from a 

large rendering company suggest there 

will be adequate fats and greases 

feedstocks to supply biofuels as well as 

other historical uses. Table IV.B.4–3 

summarizes the feedstock types, process 

types, and volumes projected to be used 

in 2022 for biodiesel and renewable 

diesel. More details on feedstock 

sources and volumes are presented in 

Section 1.1.3 of the RIA. 

TABLE IV.B.4–3—SUMMARY OF PROJECTED BIODIESEL AND RENEWABLE DIESEL FEEDSTOCK USE IN 2022 

[MMgal] 

Feedstock type 

Base 

catalyzed 

biodiesel 

Acidpretreatment 

biodiesel 

Renewable 

diesel 

Virgin vegetable oil ...................................................................................................................... 660 ........................ ........................

Corn oil from ethanol production ................................................................................................. ........................ 680 ........................

Rendered animal fats and greases ............................................................................................. ........................ 230 150 

Algae oil or other advanced source ............................................................................................ 100 ........................ ........................

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114The prescribed blending ratio for a given 

biofuel is based on vehicle compatibility and 

emissions considerations. Some biofuels may be 

found to be suitable for use without the need for 

blending with petroleum-based fuel. 

115Shipment of ethanol in pipelines that carry 

distillate fuels as well as gasoline presents 

additional challenges. 

116Unit trains are composed of 70 to 100 rail cars 

that are dedicated to shuttle back and forth from 

production facilities downstream receipt facilities 

near petroleum terminals. 

117A facility exists in Iowa to consolidate rail cars 

of ethanol from some ethanol plants that are not 

large enough to support unit train service by 

themselves. 

118Existing unit train receipt facilities have 

primarily followed this model. 

119Manifest rail shipment refers to the shipment 

of rail cars of biofuels in trains that also carry other 

products. 

120At least one current ethanol unit train receipt 

facility has a pipeline link to a nearby terminal. To 

the extent that additional unit train receipt facilities 

could accomplish the final link to petroleum 

terminals by pipeline, this would significantly 

reduce the need for shipment by tank truck. 

121Trans-loading refers to the direct transfer of 

the contents of a rail car to a tank truck without the 

intervening delivery into a storage tank. 

C. Biofuel Distribution 

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 

country. In contrast, most biofuel is 

produced in the heartland of the 

country and needs to be shipped to the 

coasts, flowing roughly in the opposite 

direction of petroleum-based fuels. In 

addition, while some renewable fuels 

such as hydrocarbons may be 

transparent to the distribution system, 

the physical/chemical nature of other 

renewable fuels may limit the extent to 

which they can be shipped/stored 

fungibly with petroleum-based fuels. 

The vast majority of biofuels are 

currently shipped by rail, barge and 

tank truck to petroleum terminals. All 

biofuels are currently blended with 

petroleum-based fuels prior to use.114

Most biofuel blends can be used in 

conventional vehicles. However, E85 

can only be used in flex-fuel vehicles, 

requires specially constructed retail 

dispensing/storage equipment, and may 

require special blendstocks at terminals. 

These factors limit the ability of biofuels 

to utilize the existing petroleum fuel 

distribution infrastructure. Hence, the 

distribution of renewable fuels raises 

unique concerns and in many instances 

requires the addition of new 

transportation, storage, blending, and 

retail equipment. 

1. Biofuel Shipment to Petroleum 

Terminals 

Ethanol currently is 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. A short 

gasoline pipeline in Florida is currently 

shipping batches of ethanol, and other 

more extensive pipeline systems have 

feasibility studies underway.115 Thus, 

existing petroleum pipelines in some 

areas of the country may play an 

increasing role in the shipment of 

ethanol. Evaluations are also currently 

underway regarding the feasibility of 

constructing a new dedicated ethanol 

pipeline from the Midwest to the East 

coast. We expect that cellulosic 

distillate fuels will not have materials 

compatibility issues with the existing 

petroleum fuel distribution 

infrastructure. Thus, there may be more 

opportunity for cellulosic distillate fuel 

to be shipped by pipeline. However, the 

location of both ethanol and cellulosic 

distillate production facilities relative to 

the origination points for existing 

petroleum pipelines will be a limiting 

factor regarding the extent to which 

pipelines can be used. 

Our analysis of the shipment of 

ethanol and cellulosic distillate fuels to 

petroleum terminals is based on the 

projections of the location of biofuel 

production facilities and end use areas 

contained in the NPRM. We assume that 

the majority of ethanol and cellulosic 

distillate fuel would be produced in the 

Midwest, and that both fuels would be 

shipped to petroleum terminals in a 

similar fashion (by rail, barge, and tank 

truck). To the extent which new biofuel 

production facilities are more dispersed 

than projected in the NPRM, there may 

be more opportunity for both fuels to be 

used closer to their point of 

manufacture. This potential benefit 

would primarily apply to cellulosic 

ethanol and distillate production 

facilities given that such facilities have 

yet to be constructed, whereas most 

corn-ethanol production facilities have 

already been constructed in the 

Midwest. 

Biodiesel is currently not typically 

shipped by pipeline due to concerns 

that it may contaminate jet fuel that is 

shipped on the same pipeline and 

potential incompatibility with pipeline 

gaskets and seals. Kinder Morgan’s 

Plantation pipeline is currently 

shipping B5 blends on segments of its 

system that do not handle jet fuel. The 

shipment of biodiesel by pipeline may 

become more widespread and might be 

expanded to systems that handle jet 

fuel. However, the relatively small 

production volumes from individual 

biodiesel plants and the widespread 

location of such production facilities 

will tend to limit the extent to which 

biodiesel may be shipped by pipeline. 

Due to the uncertainties regarding the 

extent to which pipelines might 

participate in the transportation of 

biofuels in the future, we assumed that 

biofuels will continue to be transported 

by rail, barge, and truck to petroleum 

terminals as the vast majority of biofuel 

volumes are today. To the extent that 

pipelines do play an increasing role in 

the distribution of ethanol, this may 

improve reliability in supply and reduce 

distribution costs. Apart from increased 

shipment by pipeline, biofuel 

distribution, and in particular ethanol 

distribution can be further optimized 

primarily through the expanded use of 

unit trains.116 We anticipate that the 

vast majority of ethanol and cellulosic 

distillate facilities will be sized to 

facilitate unit train service.117 We do not 

expect that biodiesel facilities will be of 

sufficient size to justify shipment by 

unit train. In the NPRM, we projected 

that unit train receipt facilities would be 

located at petroleum terminals and 

existing rail terminals. Based on 

industry input regarding the logistical 

hurdles in locating unit train receipt 

facilities at petroleum/existing rail 

terminals, we expect that such facilities 

will be constructed on dedicated 

property with rail access that is as close 

to petroleum terminals as practicable.118

Shipment of biofuels by manifest rail 

to existing rail terminals will continue 

to be an important means of supplying 

biofuels to distant markets where the 

volume of the production facility and/ 

or the local demand is not sufficient to 

justify shipment by unit train.119

Shipments by barge will also play an 

important role in those instances where 

production and demand centers have 

water access and in some cases as the 

final link from a unit train receipt 

facility to a petroleum terminal. Direct 

shipment by tank truck from production 

facilities to petroleum terminals will 

also continue for shipment over 

distances shorter than 200 miles. 

We project that most biofuel volumes 

shipped by rail will be delivered to 

petroleum terminals by tank truck.120

We expect that this will always be the 

case for manifest rail shipments. In the 

NPRM, we projected that trans-loading 

of biofuels from rail cars to tank trucks 

would be an interim measure until 

biofuel storage tanks were 

constructed.121 Based on industry input, 

we now expect trans-loading will be a 

long-term means of transferring manifest 

rail car shipments of biofuels received at 

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122See Section 1.6 of the RIA for additional 

discussion of the challenges in distributing biofuels 

from the production/import facility to the end user. 

123 Vessels that transport biodiesel will need to be 

heated/insulated in cold climates to prevent gelling. 

124Some terminals are avoiding the need for 

heated/insulated biodiesel facilities by storing high 

biodiesel blends (e.g. B50) for blending with 

petroleum-based diesel fuel. 

125The Independent Fuel Terminal Operators 

Association represents terminals in the Northeast. 126Minimum volatility specifications were 

established by ASTM to address safety and vehicle 

driveability considerations. 

127See Section 1.6 of the RIA for a discussion of 

the potential distribution of butane to petroleum 

terminals for blending with E85 and Section 4.2 for 

the potential costs. 

128Such a new fuel might have a lower ethanol 

concentration of 60% and a maximum ethanol 

concentration of 85%. 

129EPA may consider reevaluating its policies 

regarding the blendstocks used in the manufacture 

of E85 to facilitate this practice. 

130See Section 1.6 of the RIA for a discussion of 

the projected number of E85 refueling facilities that 

would be needed. There would need to be a total 

of 24,265 E85 retail facilities under the primary 

scenario, 4,500 of which are projected to have been 

placed in service absent the RFS2 standards under 

the AEO reference case. Our analysis assumes the 

installation of new dispensers and underground 

storage tank (UST) systems for E85. EPA’s Office of 

Underground Storage Tanks requires that UST 

existing rail terminals to tank trucks for 

delivery to petroleum terminals. We 

also anticipate that trans-loading will be 

used at some unit train receipt facilities, 

although we expect that most of these 

facilities will install biofuel storage 

tanks from which tank trucks will be 

filled for delivery to petroleum 

terminals. Imported biofuels will 

typically be received and be further 

distributed by tank truck from 

petroleum terminals that already have 

receipt facilities for waterborne fuel 

shipments. 

We anticipate that the deployment of 

the necessary distribution infrastructure 

to accommodate the shipment of 

biofuels to petroleum terminals is 

achievable.122 We believe that 

construction of the requisite rail cars, 

barges, tank trucks, tank truck and rail/ 

barge/truck receipt facilities is within 

the reach of corresponding construction 

firms.123 Although shipment of biofuels 

by rail represents a major fraction of all 

biofuel ton-miles, it is projected to 

account for approximately 0.4% of all 

rail freight by 2022. 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. 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 under EISA. 

2. Petroleum Terminal Accommodations 

Terminals will need to install 

additional storage capacity to 

accommodate the volume of biofuels 

that we anticipate will be used in 

response to the RFS2 standards. 

Petroleum terminals will also need to 

install truck receipt facilities for 

biofuels and equipment to blend 

biofuels into petroleum-based fuels. 

Upgrades to barge receipt facilities to 

handle deliveries of biofuels may also 

be needed at petroleum terminals with 

water access. Biodiesel storage and 

blending facilities will need to be 

insulated/heated in cold climates to 

prevent biodiesel from gelling.124

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.125 Overall demand for fuel 

used in motor vehicles is expected to 

remain relatively constant through 2022. 

Thus, much of the increased demand for 

biofuel storage could be accommodated 

by modifying storage tanks previously 

used for the gasoline and petroleumbased diesel fuels that would displaced 

by biofuels. 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. 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 storage of 

biofuels. However, we believe that there 

would be few such situations. 

In the NPRM, we stated the current 

EPA policy that the RFG and antidumping regulations currently require 

certified gasoline to be blended with 

denatured ethanol to produce E85. We 

also stated that 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. 

Commenters questioned these 

statements. As we are not taking any 

action in this final rule with respect to 

policies surrounding E85, we will 

consider these comments outside the 

context of this rule. 

3. Potential Need for Special 

Blendstocks at Petroleum Terminals for 

E85 

ASTM International is considering a 

proposal to lower the minimum ethanol 

concentration in E85 to facilitate 

meeting ASTM minimum volatility 

specifications in cold climates and 

when only low vapor pressure gasoline 

is available at terminals.126 Commenters 

have stated that the current proposal to 

lower the minimum ethanol 

concentration to 68 volume percent may 

not be sufficient for this purpose. ASTM 

International may consider an 

additional proposal to further decrease 

the minimum ethanol concentration. 

Absent such an adjustment, a highvapor pressure petroleum-based 

blendstock such as butane would need 

to be supplied to most petroleum 

terminals to produce E85 that meets 

minimum volatility specifications. In 

such a case, butane would need to be 

transported by tank truck from 

petroleum refineries to terminals and 

storage and blending equipment would 

be needed at petroleum terminals.127

Instead of lowering the minimum 

ethanol concentration of E85, some 

stakeholders are discussing establishing 

a new high-ethanol blend for use in flexfuel vehicles. Such a fuel would have a 

minimum ethanol concentration that 

would be sufficient to allow minimum 

volatility specifications to be satisfied 

while using finished gasoline that is 

already available at petroleum 

terminals.128 E85 would continue to be 

marketed in addition to this new fuel for 

use in flex-fuel vehicles when E85 

minimum volatility considerations 

could be satisfied. 

We believe that industry will resolve 

the concerns over the ability to meet the 

minimum volatility needed for highethanol blends used in flex-fuel vehicles 

in a manner that will not necessitate the 

use of high-vapor pressure blendstocks 

in their manufacture. Nevertheless, 

petroleum terminals may find it 

advantageous to blend butane into E85 

because of the low cost of butane 

relative to gasoline provided that the 

cost benefit outweighs the associated 

butane distribution costs.129

4. Need for Additional E85 Retail 

Facilities 

The number of additional E85 retail 

facilities needed to consume the volume 

of ethanol used under EISA varies 

substantially depending on the control 

case. Under our primary mid-ethanol 

scenario, we estimate that by 2022 an 

additional 19,765 E85 retail facilities 

would be needed relative to the AEO 

reference case to enable the 

consumption of the ethanol that we 

project would be used in E85.130 Under 

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systems must be compatible with the fuel stored. 

Authorities who Have Jurisdiction (such as local 

fire marshals) typically require that fuel dispensers 

be listed by an organization such as Underwriters 

Laboratories. 

131See http://ulstandardsinfonet.ul.com/ 

outscope/0087A.html. 

132The Model T was also capable of running on 

kerosene. 

133EIA, Monthly Energy Review, September 2009 

(Table 10.2b). 

134Letter from Richard Newell, EIA 

Administrator to Lisa Jackson, EPA Administrator 

dated October 29, 2009 (Table 1). 

135Based on comments provided by NPRA (EPA– 

HQ–OAR–2005–0161–2124.1). 

136Based on average E85 and regular unleaded 

gasoline prices reported at http:// 

www.fuelgaugereport.com/on November 23, 2009. 

137EIA, Annual Energy Outlook 2009—ARRA 

Update (Table 2). 

the high-ethanol scenario, we estimate 

that an additional 23,809 E85 facilities 

would be needed and that 4,500 E85 

facilities that would otherwise be in 

place would need to be upgraded to 

include more E85 dispensers by 2022. 

Whereas under the low-ethanol volume 

scenario, we project that 11,677 

additional E85 facilities would be 

needed by 2022. 

On average, approximately 1,520 

additional E85 facilities will be needed 

each year from 2010 through 2022 under 

our primary scenario. Under the high 

and low ethanol scenarios, an additional 

1,820 and 900 E85 retail facilities per 

year respectively would be needed. 

Under the high ethanol case and to a 

lesser extent under the primary case, 

this represents an aggressive timeline 

for the addition of new E85 facilities 

given that there are approximately 2,000 

E85 retail facilities in service today. 

Nevertheless, we believe the addition of 

these new E85 facilities may be possible 

for the industries that manufacture and 

install E85 retail equipment. 

Underwriters Laboratories requires that 

E85 refueling dispenser systems must be 

certified as complete units.131 To date, 

no complete E85 dispenser systems 

have been certified by UL. We 

understand that all the fuel dispenser 

components with the exception of the 

hoses that connect to the refueling 

nozzle have successfully passed the 

necessary testing. There does not appear 

to be a technical difficulty in finding 

hoses that can pass the required testing. 

Therefore, we anticipate this situation 

will be resolved once the demand for 

new E85 facilities is demonstrated. 

Hence, we believe that the current lack 

of a UL certification for complete E85 

dispenser systems will not impede the 

installation of the additional E85 

facilities that we projected will be 

needed. 

Petroleum retailers expressed 

concerns about their ability to bear the 

cost installing the needed E85 refueling 

equipment given that most retailers are 

small businesses and have limited 

capital resources. They also expressed 

concern regarding their ability to 

discount the price of E85 relative to E10 

sufficiently to persuade flexible fuel 

vehicle owners to choose E85 given the 

lower energy density of ethanol. Today’s 

rule does not contain a requirement for 

retailers to carry E85. We understand 

that retailers will only install E85 

facilities if they can be assured of 

sufficient E85 throughput to recover 

their capital costs. The current 

projections regarding the future cost of 

gasoline relative to ethanol indicate that 

it may be possible to price E85 in a 

competitive fashion to E10. Thus, 

demand for E85 may be sufficient to 

encourage retailers to install the needed 

E85 refueling facilities. 

D. Ethanol Consumption 

1. Historic/Current Ethanol 

Consumption 

Ethanol and ethanol-gasoline blends 

have a long history as automotive fuels. 

In fact, the well-known Model-T was 

capable of running on both ethanol and 

gasoline.132 However, inexpensive 

crude oil prices kept ethanol from 

making a significant presence in the 

transportation sector until the end of the 

20th century. Over the past decade, 

ethanol use has grown rapidly due to 

oxygenated fuel requirements, MTBE 

bans, tax incentives, state mandates, the 

first federal renewable fuels standard 

(‘‘RFS1’’), and rising crude oil prices. 

Although the cost of crude has come 

down since reaching record levels in 

2008, uncertainty surrounding pricing 

and the environmental implications of 

fossil fuels continue to drive ethanol 

use. 

A record 9.5 billion gallons of ethanol 

were blended into U.S. gasoline in 2008 

and EIA is forecasting additional growth 

in the years to come.133 According to 

their recently released Short-Term 

Energy Outlook (STEO), EIA is 

forecasting 0.7 million barrels of daily 

ethanol use in 2009, which equates to 

10.7 billion gallons. The October 2009 

STEO projects that total ethanol usage 

(domestic production plus imports) will 

reach 12.1 billion gallons by 2010.134

The National Petrochemical and 

Refiners Association (NPRA) estimates 

that ethanol is currently blended into 

about 75 percent of all gasoline sold in 

the United States.135 The vast majority 

is blended as E10 or 10 volume percent 

ethanol, although a small amount is 

blended as E85 for use in flexible fuel 

vehicles (FFVs). 

Complete saturation of the gasoline 

market with E10 is referred to as the 

ethanol ‘‘blend wall.’’ The height of the 

blend wall in any given year is directly 

related to gasoline demand. In AEO 

2009, EIA projects that gasoline demand 

will peak around 2013 and then start to 

taper off due to vehicle fuel economy 

improvements. Based on the primary 

ethanol growth scenario we’re 

forecasting under today’s RFS2 program, 

the nation is expected to hit the 14–15 

billion gallon blend wall by around 

2014 (refer ahead to Figure IV.D.2–1), 

although it could be sooner if gasoline 

demand is lower than expected. It could 

also be lower if projected volumes of 

non-ethanol renewables do not 

materialize and ethanol usage is higher 

than expected. 

Over the years there have been several 

policy attempts to increase FFV sales 

including Corporate Average Fuel 

Economy (CAFE) credits and 

government fleet alternative-fuel vehicle 

requirements. As a result, there are an 

estimated 8 million FFVs on the road 

today, up from just over 7 million in 

2008. While this is not insignificant in 

terms of growth, FFVs continue to make 

up less than 4 percent of the total 

gasoline vehicle fleet. In addition, E85 

is only currently offered at about 1 

percent of gas stations nationwide. 

Ethanol consumption is currently 

limited by the number of FFVs on the 

road and the number of E85 outlets or, 

more specifically, the number of FFVs 

with access to E85. Still many FFV 

owners with access to E85 are not 

choosing it because it is currently priced 

almost 40 cents per gallon higher than 

conventional gasoline on an energy 

equivalent basis.136 According to EIA, 

only 12 million gallons of E85 were 

consumed in 2008.137

To meet today’s RFS2 requirements 

we are going to need to see growth in 

FFV and E85 infrastructure as well as 

changes in retail pricing and consumer 

behavior. However, the amount of 

change needed is proportional to the 

amount of ethanol observed under the 

RFS2 program. As explained in Section 

IV.A, EPA expects total ethanol demand 

could be anywhere from 17.5 to 33.2 

billion gallons in 2022, depending on 

the amount of non-ethanol cellulosic 

biofuels that are realized. The lowethanol case would require only 

moderate changes in FFV/E85 

infrastructure and refueling whereas the 

high-ethanol case would require very 

dramatic changes and likely a mandate. 

For the final rule, we have chosen to 

focus our impact analyses on the 

primary mid-ethanol case of 22.2 billion 

gallons. A discussion of how this 

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138EIA, Annual Energy Outlook 2009—ARRA 

Update (Table 2). 

139The gasoline energy demand forecast provided 

in AEO 2009—ARRA Update is reasonably 

consistent with the recently Proposed Rulemaking 

To Establish Light-Duty Vehicle Greenhouse Gas 

Emission Standards and Corporate Average Fuel 

Economy Standards (referred to hereafter as the 

‘‘Light-Duty Vehicle GHG Rule.’’ For more 

information on the Light-Duty Vehicle GHG Rule, 

refer to 74 FR 49454 (September 28, 2009). 

volume of ethanol could be consumed 

in 2022 with expanded FFV/E85 

infrastructure is presented below. As 

expected, the infrastructure changes 

required under this FRM scenario are 

less extreme than those highlighted in 

the proposal based on a predominant 

ethanol world (34.2 billion gallons of 

ethanol). However, there are additional 

technological, logistical and financial 

barriers that will need to be overcome 

with respect to commercialization of 

BTL and non-ethanol cellulosic 

biofuels. For more on cellulosic diesel 

technologies, distribution impacts, and 

production costs, refer to Sections 1.4, 

1.6 and 4.1 of the RIA. 

2. Increased Ethanol Use Under RFS2 

Under the primary ethanol growth 

scenario considered as part of today’s 

rule, ethanol consumption will need to 

be about three times higher than RFS1 

levels, more than twice as much as 

today’s levels, and 9 billion gallons 

higher than the ethanol predicted to 

occur in 2022 absent RFS2 (according to 

AEO 2007). To get to 22.2 billion gallons 

of ethanol use according to the potential 

ramp-up described in Section 1.2 of the 

RIA, the nation is predicted to hit the 

blend wall in 2014 as shown below in 

Figure IV.D.2–1. 

As shown above, we are anticipating 

almost 14 billion gallons of non-ethanol 

advanced biofuels under today’s RFS2 

program. But overall, ethanol is 

expected to continue to be the nation’s 

primary biofuel with over 22 billion 

gallons in 2022. To get beyond the blend 

wall and consume more than 14–15 

billion gallons of ethanol, we are going 

to need to see increases in the number 

FFVs on the road, the number of E85 

retailers, and the FFV E85 refueling 

frequency. 

It is possible that conventional 

gasoline (E0) could continue to co-exist 

with E10 and E85 for quite some time. 

However, for analysis purposes, we 

have assumed that E10 would replace 

E0 as expeditiously as possible and that 

all subsequent ethanol growth would 

come from E85. Furthermore, we 

assumed that no ethanol consumption 

would come from the mid-level ethanol 

blends (e.g., E15) under our primary 

control case since they are not currently 

approved for use in non-FFVs. However, 

as a sensitivity analysis, we have 

examined the impacts that E15 would 

have on ethanol consumption (refer to 

Section IV.D.3). 

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 provided by EIA in 

the AEO 2009 final release.138 AEO 

2009 takes the fuel economy 

improvements set by EISA into 

consideration and also assumes a slight 

dieselization of the light-duty vehicle 

fleet.139 It also takes the recession’s 

impacts on driving patterns into 

consideration. The result is a 25% 

reduction in the projected 2022 gasoline 


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140EIA, Annual Energy Outlooks 2007 & 2009— 

ARRA Update (Table 2). 

141EIA, Annual Energy Outlook 2009—ARRA 

Update (Table 47). 

142Rulemaking to Establish Light-Duty Vehicle 

GHG Emission Standards and Corporate Average 

Fuel Economy Standards, 74 FR 49454 (September 

28, 2009). 

143EIA, Annual Energy Outlook 2009—ARRA 

Update (Table 47). 

144Ethanol Producer Magazine, ‘‘Automakers 

Maintain FFV Targets in Bailout Plans.’’ February 

2009. This is consistent with information provided 

in GM and Chrysler’s restructuring plans submitted 

to the U.S. Department of Treasury on February 17, 

2009. 

145Based on 2008 FFV certification data and 2009 

projections based on the National Ethanol Vehicle 

Coalition, 2009 FFV Purchasing Guide. 

146A copy of H.R. 1476 can be found at: 

http://www.opencongress.org/bill/111-h1476/text. 

147NEVC Web site, accessed on November 23, 

2009. 

148Based on National Petroleum News gasoline 

station estimate of 161,768 in 2008. 

149For a more detailed discussion on how we 

derived our one-in-four reasonable access 

assumption, refer to Section 1.6 of the RIA. 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 

RIA. 

150Computed as percent of stations with E85 

(2,101/161,768 as of November 2009 or 1,733/ 

161,768 as of August 2008) divided by 25% (onein-four stations). 

151The following states have adopted the plan: 

Illinois, Indiana, Iowa, Kansas, Michigan, 

Minnesota, Missouri, Ohio, South Dakota and 

Wisconsin. For more information, visit: http:// 

www.midwesterngovernors.org/resolutions/

Platform.pdf. 

152http://frwebgate.access.gpo.gov/cgi-bin/

getdoc.cgi?dbname=111_cong_bills&docid=f:

h1enr.pdf. 

energy demand from AEO 2007 (a preEISA world) to AEO 2009.140 EIA 

essentially has total gasoline energy 

demand (petroleum-based gasoline plus 

ethanol) flattening out, and even slightly 

decreasing, as we move into the future. 

b. Projected Growth in Flexible Fuel 

Vehicles 

Over one million FFVs were sold in 

both 2008 and 2009 according to EPA 

certification data. Despite the recession 

and current state of the auto industry, 

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 automakers 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. 

To measure the impacts of increased 

volumes of renewable fuel, we 

considered three different FFV 

production scenarios that might 

correspond to the three biofuel control 

cases analyzed for the final rule. For all 

three cases, we assumed that total lightduty vehicle sales would follow AEO 

2009 trends. The latest EIA report 

suggests lower than average sales in 

2008–2013 (less than 16 million 

vehicles per year) before rebounding 

and growing to over 17 million vehicles 

by 2019.141 These vehicle projections 

are consistent with EPA’s recently 

proposed Light-Duty Vehicle GHG 

Rule.142

Although we assumed total vehicle 

and car/truck sales would be the same 

in all three cases, we assumed varying 

levels of FFV production. For our lowethanol control case, we assumed steady 

business-as-usual FFV growth according 

to AEO 2009 predictions.143 For our 

primary mid-ethanol control case, we 

assumed increased FFV sales under the 

presumption that GM, Ford and 

Chrysler (referred to hereafter as the 

‘‘Detroit 3’’) would follow through with 

their commitment to produce 50% FFVs 

by 2012. Despite the current state of the 

economy and the hardships facing the 

auto industry (GM and Chrysler filed for 

bankruptcy earlier this year), the Detroit 

3 appear to still be moving forward with 

their voluntary FFV commitment.144

Under our primary control case, we 

assumed that non-domestic FFVs sales 

would track around 2%, consistent with 

today’s production/plans.145 Finally, for 

our high-ethanol control case, we 

assumed a theoretical 80% FFV 

mandate based on the Open Fuel 

Standard Act of 2009 that was 

reintroduced in Congress on March 12, 

2009.146 Given today’s reduced vehicle 

sales and gasoline demand, we believe 

a mandate would be the only viable 

means for consuming 32.2 billion 

gallons of ethanol in 2022. 

Under our primary mid-ethanol 

control case, total FFV sales are 

estimated at just over 4 million vehicles 

per year in 2017 and beyond. This is 

less aggressive than the assumptions 

made in the NPRM. At that time, we 

were expecting more cellulosic ethanol 

which could justify higher FFV 

production assumptions. We assumed 

that not only would the Detroit 3 fulfill 

their 50% by 2012 FFV production 

commitment, non-domestic automakers 

might follow suit and produce 25% FFV 

in 2017 and beyond. We also assumed 

that annual light-duty vehicle sales 

would continue around the historical 16 

million vehicle mark resulting in 6 

million FFVs in 2017 and beyond. 

Based on our revised vehicle/FFV 

production assumptions coupled with 

vehicle survival rates, VMT, and fuel 

economy estimates applied in the 

recently proposed Light-Duty Vehicle 

GHG Rule, the maximum percentage of 

fuel (gasoline/ethanol mix) that could 

feasibly be consumed by FFVs in 2022 

would be about 20% (down from 30% 

in the NPRM). For more information on 

our FFV production assumptions and 

fuel fraction calculations, refer to 

Section 1.7.2 of the RIA. 

c. Projected Growth in E85 Access 

According to the National Ethanol 

Vehicle Coalition (NEVC), there are 

currently 2,100 gas stations offering E85 

in 44 states plus the District of 

Columbia.147 While this represents 

significant industry growth, it still only 

translates to 1.3% of U.S. retail stations 

nationwide carrying the fuel.148 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.149

Accordingly, just over 5% of the nation 

currently has reasonable access to E85, 

up from 4% in 2008 (based on a midyear NEVC pump estimate).150

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, 10 Midwest states have 

adopted a progressive Energy Security 

and Climate Stewardship Platform.151

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, the 

American Recovery and Reinvestment 

Act of 2009 (ARRA or Recovery Act) 

recently increased 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.152

Given the growing number of 

subsidies, it is clear that E85 

infrastructure will continue to expand 

in the future. However, like FFVs, we 

expect that E85 station growth will be 

somewhat proportional to the amount of 

ethanol realized under the RFS2 

program. As such, we analyzed three 

different E85 growth scenarios for the 

final rule that could correspond to the 

three different RFS2 control cases. As an 

upper bound for our high-ethanol 

control case, we maintained the 70% 

access assumption we applied for the 

NPRM. This is roughly equivalent to all 

urban areas in the United States offering 

reasonable (one-in-four-station) access 

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153For 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. 

154Based on average vehicle miles traveled (VMT) 

and in-use fuel economy (MPG) for FFVs in the fleet 

in 2008. For more information on FFV E85 fuel 

consumption calculations, refer to Section 1.7.4 of 

the RIA. 

155EIA, Annual Energy Outlook 2009—ARRA 

Update (Table 17). 

156NEVC, ‘‘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. 

157Based on our assumption that denatured 

ethanol has an average lower heating value of 

77,012 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 2009 assumption, E85 was assumed to 

contain 74 vol% ethanol and 26 vol% gasoline on 

average. 

158Based on average E85 and regular unleaded 

gasoline prices reported at http:// 

www.fuelgaugereport.com/ on November 23, 2009. 

159EIA, Annual Energy Outlook 2009—ARRA 

Update (Table 12). 

160http://www.dtnethanolcenter.com/ 

index.cfm?show=10&mid=32. 

161http://www.growthenergy.org/2009/e15/ 

Waiver%20Cover%20Letter.pdf. Additional 

to E85.153 For our other control cases we 

assumed access to E85 would be lower 

with the logic that retail stations (the 

majority of which are independently 

owned and operated and net around 

$30,000 per year) would not invest in 

more E85 infrastructure than what was 

necessary to meet the RFS2 

requirements. For our primary midethanol control case we assumed 

reasonable access would grow from 4% 

in 2008 to 60% in 2022 and for our lowethanol control case we assumed that 

access would only grow to 40% by 

2022. As discussed in Section IV.C, we 

believe these E85 growth scenarios are 

possible based on our assessment of 

distribution infrastructure capabilities. 

d. Required Increase in E85 Refueling 

Rates 

As mentioned earlier, there were just 

over 7 million FFVs on the road in 2008. 

If all FFVs refueled on E85 100% of the 

time, this would translate to about 8.3 

billion gallons of E85 use.154 However, 

E85 usage was only around 12 million 

gallons in 2008.155 This means that, on 

average, FFV owners were only tapping 

into about 0.15% 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 4% E85 

refueling frequency for those FFVs that 

had reasonable access to the fuel. 

There are several reasons behind 

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.156 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 

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).157 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 (discussed in 

more detail in the subsection that 

follows). 

To comply with the RFS2 program 

and consume 22.2 billion gallons of 

ethanol by 2022 (under our primary 

ethanol control case), 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 would need to 

fill up on it as often as 58% of the time, 

a significant increase from today’s 

estimated 4% 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 an online fuel price 

survey, E85 is currently priced almost 

40 cents per gallon or about 15% lower 

than regular grade conventional 

gasoline.158 But this is still about 30 

cents per gallon higher than 

conventional gasoline on an energyequivalent basis. 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. Overall, we estimate that 

E85 would need to be priced about 25% 

lower than E10 at retail in 2022 in order 

for it to make sense to consumers. 

However, ultimately it comes down to 

what refiners are willing to pay for 

ethanol blended as E85. The more 

ethanol you try to blend as E85, the 

more devalued ethanol becomes as a 

gasoline blendstock. Changes to state 

and Federal excise tax structures could 

help promote ethanol blending as E85. 

Similarly, high crude prices make E85 

look more attractive. According to EIA’s 

AEO 2009, crude oil prices are expected 

to increase from about $80 per barrel 

(today’s price) to $116/barrel by 

2022.159 Based on our retail cost 

calculations, ethanol would have to be 

priced around $2/gallon or less in order 

to be attractive to refiners for E85 

blending in 2022. According to the DTN 

Ethanol Center, the current rack price 

for ethanol is around $2.20/gallon.160

However, as explained in Section 4.4 of 

the RIA, we project that the average 

ethanol delivered price will come down 

in the future under the RFS2 program. 

Therefore, while gasoline refiners and 

markets will always have a greater profit 

margin selling ethanol in low-level 

blends to consumers based on volume, 

they should be able to maintain a profit 

selling it as E85 based on energy content 

in the future. 

Once the nation gets past the blend 

wall, more ethanol will need to be 

blended as E85 and less as E10. FFV 

owners who were formerly refueling on 

gasoline will need to start filling up on 

E85. Under our primary control case, we 

expect that 12.9 billion gallons of 

ethanol would be blended as E10 and 

9.3 billion gallons would be blended as 

E85 to reach the 22.2 billion gallons in 

2022. For more on our ethanol 

consumption feasibility and retail cost 

calculations, including discussion of the 

other two control cases, refer to Section 

1.7 of the RIA. 

3. Consideration of >10% Ethanol 

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 ethanol by volume.161 On April 

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supporting documents are available on the Growth 

Energy Web site. 

162Refer to 74 FR 18228 (April 21, 2009). 

163Refer to 74 FR 23704 (May 20, 2009). 

164http://www.epa.gov/OMS/regs/fuels/additive/ 

lettertogrowthenergy11-30-09.pdf. 

165According to EIA’s 2008 Petroleum Annual 

Outlook (Table 45), midgrade and premium 

comprise 13.5% of total gasoline sales. 

21, 2009, EPA issued a Federal Register 

notice announcing receipt of the Growth 

Energy waiver application and soliciting 

comment on all aspects of it.162 On May 

20, 2009, EPA issued an additional 

Federal Register notice extending the 

public comment period by an additional 

60 days.163 The comment period ended 

on July 20, 2009, and EPA is now 

evaluating the waiver application and 

considering the comments which were 

submitted. 

In a letter dated November 30, 2009, 

EPA notified the applicant that, because 

crucial vehicle durability information 

being developed by the Department of 

Energy would not be available until 

mid-2010, EPA would be delaying its 

decision on the application until a 

sufficient amount of this information 

could be included in its analysis so that 

the most scientifically supportable 

decision could be made.164 As the 

current Growth Energy waiver 

application is still under review, EPA 

believes it is appropriate to address 

aspects of the mid-level blend waiver in 

its decision announcement on the 

waiver application as opposed to 

dealing with the comments and 

evaluation of the potential waiver in the 

preamble of today’s final rule. 

Although EPA has yet to make a 

waiver decision, since its approval 

could have a significant impact on our 

analyses that are based on the use of 

E85, as a sensitivity analysis, we have 

evaluated the impacts that E15 could 

have on ethanol consumption 

feasibility. More specifically, we have 

assessed the impacts of a partial waiver 

for newer technology vehicles 

consistent with the direction of EPA’s 

November 30, 2009 letter. We assumed 

that E10 would need to continue to coexist for legacy and non-road equipment 

based on consumer demand regardless 

of any waiver decision. For analysis 

purposes, we assumed E10 would be 

marketed as premium-grade gasoline 

(the universal fuel), E15 would be 

marketed as regular-grade gasoline (to 

maximize ethanol throughput) and, like 

today, midgrade would be blended from 

the two fuels to make a 12.5 vol% blend 

(E12.5). In addition, we assumed that 

some E15-capable vehicles would 

continue to choose E10 or E12.5 based 

on our knowledge of today’s premium 

and midgrade sales.165

In the event of a partial waiver, it is 

unclear how long it would take for E15 

to be fully deployed or whether it would 

ever be available nationwide. For 

analysis purposes, we assumed that E15 

would be fully phased in and available 

at all retail stations nationwide by the 

time the nation hit the blend wall, or 

around 2014 for our primary control 

case shown in Figure IV.D.3–1. 

As modeled, a partial waiver for E15 

could increase the ethanol consumption 

potential from conventional vehicles to 

about 19 billion gallons. Under our 

primary control case (shown in Figure 

IV.D.3–1), E15 could postpone the blend 

wall by up to five years, or to 2019. 

Although E15 would fall short of 

meeting the RFS2 requirements under 

this scenario, it could provide interim 

relief while the county ramps up nonethanol cellulosic biofuel production 

and expands E85/FFV infrastructure. 

Under our high-ethanol control case, a 

partial waiver for E15 could eliminate 


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the need for FFV or E85 infrastructure 

mandates. Under our low-ethanol 

control case, E15 could eliminate the 

need for additional FFV/E85 

infrastructure all together. For more 

information, refer to Section 1.7.6 of the 

RIA. 

V. Lifecycle Analysis of Greenhouse 

Gas Emissions 

A. Introduction 

As recognized earlier in this 

preamble, a significant aspect of the 

RFS2 program is the requirement that a 

fuel meet a specific lifecycle greenhouse 

gas (GHG) emissions threshold for 

compliance for each of four types of 

renewable fuels. This section describes 

the methodology used by EPA to 

determine the lifecycle GHG emissions 

of biofuels, and the petroleum-based 

transportation fuels that they replace. 

EPA recognizes that this aspect of the 

RFS2 regulatory program has received 

particular attention and comment 

throughout the public comment period. 

Therefore, this section also will describe 

the enhancements made to our approach 

in conducting the lifecycle analysis for 

the final rule. This section will highlight 

areas where we have incorporated new 

scientific data that has become available 

since the proposal as well as the 

approach the Agency has taken to 

recognize and quantify, where 

appropriate, the uncertainty inherent in 

this analysis. 

1. Open and Science-Based Approach to 

EPA’s Analysis 

Throughout the development of EPA’s 

lifecycle analysis, the Agency has 

employed a collaborative, transparent, 

and science-based approach. EPA’s 

lifecycle methodology, as developed for 

the RFS2 proposal, required breaking 

new scientific ground and using 

analytical tools in new ways. The work 

was generally recognized as state of the 

art and an advance on lifecycle 

thinking, specifically regarding the 

indirect impacts of biofuels. 

However, the complexity and 

uncertainty inherent in this work made 

it extremely important that we seek the 

advice and input of a broad group of 

stakeholders. In order to maximize 

stakeholder outreach opportunities, the 

comment period for the proposed rule 

was extended to 120 days. In addition 

to this formal comment period, EPA 

made multiple efforts to solicit public 

and expert feedback on our approach. 

Beginning early in the NPRM process 

and continuing throughout the 

development of this final rule, EPA held 

hundreds of meetings with stakeholders, 

including government, academia, 

industry, and non-profit organizations, 

to gather expert technical input. Our 

work was also informed heavily by 

consultation with other federal agencies. 

For example, we have relied on the 

expert advice of USDA and DOE, as well 

as incorporating the most recent inputs 

and models provided by these Agencies. 

Dialogue with the State of California 

and the European Union on their 

parallel, on-going efforts in GHG 

lifecycle analysis also helped inform 

EPA’s methodology. As described 

below, formal technical exchanges and 

an independent, formal peer review of 

the methodology were also significant 

components of the Agency’s outreach. A 

key result of our outreach effort has 

been awareness of new studies and data 

that have been incorporated into our 

final rule analysis. 

Technology Exchanges: Immediately 

following publication of the proposed 

rule, EPA held a two-day public 

workshop focused specifically on 

lifecycle analysis to assure full 

understanding of the analyses 

conducted, the issues addressed, and 

the options discussed. The workshop 

featured EPA presentations on each 

component of the methodology as well 

as presentations and discussions by 

stakeholders from the renewable fuel 

community, federal agencies, 

universities, and environmental groups. 

The Agency also took advantage of 

opportunities to meet in the field with 

key, affected stakeholders. For example, 

the Agency was able to twice participate 

in meetings and tours in Iowa hosted by 

the local renewable fuel and agricultural 

community. As described in this 

section, one of the many outcomes of 

these meetings was an improved 

understanding of agricultural and 

biofuel production practices. 

As indicated in the proposal, our 

lifecycle results were particularly 

impacted by assumptions about land 

use patterns and emissions in Brazil. 

During the public comment process we 

were able to update and refine these 

assumptions, including the 

incorporation of new, improved sources 

of data based on Brazil-specific data and 

programs. In addition, the Agency 

received more recent trends on Brazilian 

crop productivity, areas of crop 

expansion, and regional differences in 

costs of crop production and land 

availability. Lastly, we received new 

information on efforts to curb 

deforestation allowing the Agency to 

better predict this impact through 2022. 

Peer Review: To ensure the Agency 

made its decisions for this final rule on 

the best science available, EPA 

conducted a formal, independent peer 

review of key components of the 

analysis. The reviews were conducted 

following the Office of Management and 

Budget’s peer review guidance that 

ensures consistent, independent 

government-wide implementation of 

peer review, and according to EPA’s 

longstanding and rigorous peer review 

policies. In accordance with these 

guidelines, EPA used independent, 

third-party contractors to select highly 

qualified peer reviewers. The reviewers 

selected are leading experts in their 

respective fields, including lifecycle 

assessment, economic modeling, remote 

sensing imagery, biofuel technologies, 

soil science, agricultural economics, and 

climate science. They were asked to 

evaluate four key components of EPA’s 

methodology: (1) Land use modeling, 

specifically the use of satellite data and 

EPA’s proposed land conversion GHG 

emission factors; (2) methods to account 

for the variable timing of GHG 

emissions; (3) GHG emissions from 

foreign crop production (both the 

modeling and data used); and (4) how 

the models EPA relied upon are used 

together to provide overall lifecycle 

estimates. 

The advice and information received 

through this peer review are reflected 

throughout this section. EPA’s use of 

higher resolution satellite data is one 

example of a direct outcome of the peer 

review, as is the Agency’s decision to 

retain its reliance upon this data. The 

reviewers also provided 

recommendations that have helped to 

inform the larger methodological 

decisions presented in this final rule. 

For example, the reviewers in general 

supported the importance of assessing 

indirect land use change and 

determined that EPA used the best 

available tools and approaches for this 

work. However, the review also 

recognized that no existing model 

comprehensively simulates the direct 

and indirect effects of biofuel 

production both domestically and 

internationally, and therefore model 

development is still evolving. The 

uncertainty associated with estimating 

indirect impacts and the difficulty in 

developing precise results also were 

reflected in the comments. In the long 

term, this peer review will help focus 

EPA’s ongoing lifecycle analysis work as 

well as our future interactions with the 

National Academy of Science and other 

experts. 

Altogether, the many and extensive 

public comments we received to the 

rule docket, the numerous meetings, 

workshops and technical exchanges, 

and the scientific peer review have all 

been instrumental to EPA’s ability to 

advance our analysis between proposal 

and final and to develop the 

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166Clean Air Act Section 211(o)(1). 

methodological and regulatory approach 

described in this section. 

2. Addressing Uncertainty 

The peer review, the public comments 

we have received, and the analysis 

conducted for the proposal and updated 

here for the final rule, indicate that it is 

important to take into account indirect 

emissions when looking at lifecycle 

emissions from biofuels. It is clear that, 

especially when considering commodity 

feedstocks, including the market 

interactions of biofuel demand on 

feedstock and agricultural markets is a 

more accurate representation of the 

impacts of an increase in biofuels 

production on GHG emissions than if 

these market interactions are not 

considered. 

However, it is also clear that there are 

significant uncertainties associated with 

these estimates, particularly with regard 

to indirect land use change and the use 

of economic models to project future 

market interactions. Reviewers 

highlighted the uncertainty associated 

with our lifecycle GHG analysis and 

pointed to the inherent uncertainty of 

the economic modeling. 

In the proposal, we asked for 

comment on whether and how to 

conduct an uncertainty analysis to help 

quantify the magnitude of this 

uncertainty and its relative impact on 

the resulting lifecycle emissions 

estimates. The results of the peer 

review, and the feedback we have 

received from the comment process, 

supported the value of conducting such 

an analysis. Therefore, working closely 

with other government agencies as well 

as incorporating feedback from experts 

who commented on the rule, we have 

quantified the uncertainty associated 

specifically with the international 

indirect land use change emissions 

associated with increased biofuel 

production. 

Although there is uncertainty in all 

portions of the lifecycle modeling, we 

focused our uncertainty analysis on the 

factors that are the most uncertain and 

have the biggest impact on the results. 

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). 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. 

Therefore, we focused our efforts on 

the international indirect land use 

change emissions and worked to 

manage the uncertainty around those 

impacts in three ways: (1) Getting the 

best information possible and updating 

our analysis to narrow the uncertainty, 

(2) performing sensitivity analysis 

around key factors to test the impact on 

the results, and (3) establishing 

reasonable ranges of uncertainty and 

using probability distributions within 

these ranges in threshold assessment. 

The following sections outline how we 

have incorporated these three 

approaches into our analysis. 

EPA recognizes that as the state of 

scientific knowledge continues to 

evolve in this area, the lifecycle GHG 

assessments for a variety of fuel 

pathways will continue to change. 

Therefore, while EPA is using its 

current lifecycle assessments to inform 

the regulatory determinations for fuel 

pathways in this final rule, as required 

by the statute, the Agency is also 

committing to further reassess these 

determinations and lifecycle estimates. 

As part of this ongoing effort, we will 

ask for the expert advice of the National 

Academy of Sciences, as well as other 

experts, and incorporate their advice 

and any updated information we receive 

into a new assessment of the lifecycle 

GHG emissions performance of the 

biofuels being evaluated in this final 

rule. EPA will request that the National 

Academy of Sciences over the next two 

years evaluate the approach taken in 

this rule, the underlying science of 

lifecycle assessment, and in particular 

indirect land use change, and make 

recommendations for subsequent 

rulemakings on this subject. This new 

assessment could result in new 

determinations of threshold compliance 

compared to those included in this rule 

that would apply to future production 

(from plants that are constructed after 

each subsequent rule). 

B. Methodology 

The regulatory purpose of this 

analysis is to determine which biofuels 

(both domestic and imported) qualify 

for the four different GHG reduction 

thresholds and renewable fuel 

categories established in EISA (see 

Section I.A). This threshold assessment 

compares the lifecycle emissions of a 

particular biofuel against the lifecycle 

emissions of the petroleum-based fuel it 

is replacing (e.g., ethanol replacing 

gasoline or biodiesel replacing diesel). 

This section discusses the Agency’s 

approach both for assessing the lifecycle 

GHG emissions from biofuels as well as 

for the petroleum-based fuels replaced 

by the biofuels. 

As described in detail below, EPA has 

received a number of comments on the 

different pieces of this analysis and has 

thoroughly considered those comments 

as well as feedback from our peer 

review process. In each section below 

we will discuss comments received and 

how they impacted our analysis. 

1. Scope of Analysis 

As stated in the proposal, the 

definition of lifecycle GHG emissions 

established by Congress in EISA is 

critical to establishing the scope of our 

analysis. 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.166

This definition forms the basis of 

defining the goal and scope of our 

lifecycle GHG analysis and in 

determining to what extent changes 

should be made to the analytical 

approach outlined in our proposed 

rulemaking. 

a. Inclusion of Indirect Land Use 

Change 

EPA notes that it received significant 

comment on including international 

indirect emissions in its lifecycle 

calculations. Most of the comments 

suggested that the science of 

international indirect land use change 

was too new, or that the uncertainty 

involved was too great, to be included 

in a regulatory analysis. EPA continues 

to believe 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 significant indirect impacts that 

occur not just within the United States, 

but also those that occur in other 

countries. 

Some commenters strongly supported 

EPA’s proposal to include significant 

GHG emissions that occur overseas and 

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are related to the lifecycle of renewable 

fuels or baseline fuels used in the 

United States. These commenters agreed 

that the text of the statute supports 

EPA’s proposed approach, and that the 

alternative of ignoring such emissions 

would result in grossly inaccurate 

assessments, and would be inconsistent 

with the international nature of GHG 

pollution and the fact that overseas 

emissions have domestic impacts. 

Other commenters argued that the 

presumption against extraterritorial 

application of domestic laws carries 

with it the presumption that Congress is 

concerned with domestic effects and 

domestic impacts only. They assert 

further that Congress intended to benefit 

domestic agriculture through EISA 

enactment, and that the statute’s 

ambiguous terms should not be 

interpreted in a manner that could harm 

domestic agriculture in general or, for 

one commenter, the biodiesel industry 

in particular. Although considering 

international emissions in its analyses 

could result in different implications 

under the statute for various fuels and 

fuel pathways as compared to ignoring 

these emissions, EPA believes that this 

is precisely the outcome that Congress 

intended. Implementation of EISA will 

undoubtedly benefit the domestic 

agricultural sector as a whole, with 

some components benefiting more than 

others depending in part on the lifecycle 

GHG emissions associated with the 

products to be made from individual 

feedstocks. If Congress had sought to 

promote all biofuel production without 

regard to GHG emissions related to the 

full lifecycle of those fuels, it would not 

have specified GHG reduction 

thresholds for each category of 

renewable fuel for which volume targets 

are specified in the Act. 

It is also important to note that 

including international indirect 

emissions in EPA’s lifecycle analysis 

does not exercise regulatory authority 

over activities that occur solely outside 

the U.S., nor does it raise questions of 

extra-territorial jurisdiction. EPA’s 

regulatory action involves an 

assessment 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 EISA for the use of 

designated volumes of renewable fuel, 

cellulosic biofuel, biomass-based diesel, 

and advanced biofuel. 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. 

A number of commenters pointed to 

the text and structure of the definition 

of ‘‘lifecycle greenhouse gas emissions’’ 

to argue that EPA either is not 

authorized to consider GHG emissions 

related to international land use change, 

or that it is not required to do so. One 

commenter suggested that the reference 

in the definition of ‘‘lifecycle 

greenhouse gas emissions’’ to ‘‘all stages’’ 

of the lifecycle ‘‘from’’ feedstock 

generation ‘‘through’’ use of the fuel by 

the ultimate consumer does not include 

indirect emissions that result from 

decisions to place more land in acreage 

overseas for such non-fuel purposes as 

cattle feed. Another commenter stated 

that EPA’s approach does not give any 

meaning to the terms ‘‘significant’’ and 

‘‘fuel lifecycle’’ in the definition, but 

instead focuses on the words such as 

‘‘full’’ to arrive at an expansive meaning. 

This commenter also noted the lack of 

any specific reference to international 

considerations in Section 211(o), as 

opposed to other provisions in the CAA, 

such as Section 115. 

EPA believes that a complete analysis 

of the aggregate GHG emissions related 

to the full lifecycle of renewable fuels 

includes the significant indirect 

emissions from international land use 

change that are predicted to result from 

increased domestic use of agricultural 

feedstocks to produce renewable fuel. 

The statute specifically directs EPA to 

include in its analyses significant 

indirect emissions such as significant 

emissions from land use changes. EPA 

has not ignored either the terms 

‘‘significant’’ or ‘‘life cycle.’’ It is clear 

from EPA’s assessments that the 

modeled indirect emissions from land 

use changes are ‘‘significant’’ in terms of 

their relationship to total GHG 

emissions for given fuel pathways. 

Therefore, they are appropriately 

considered in the total GHG emissions 

profile for the fuels in question. EPA has 

not ignored the term ‘‘life cycle.’’ The 

entire approach used by EPA is directed 

to fully analyzing emissions related to 

the complete lifecycle of renewable and 

baseline fuels. 

Although the definition of lifecycle 

greenhouse gas emissions in Section 

211(o) does not specifically mention 

international emissions, it would be 

inconsistent with the intent of this 

section of the amended Act to exclude 

them. A large variety of activities 

outside the U.S. play a major part in the 

full fuel lifecycle of both baseline 

(gasoline and diesel fuel used as 

transportation fuel in 2005) and 

renewable fuels. For example, several 

stages of the lifecycle process for 

gasoline and diesel can occur overseas, 

including extraction and delivery of 

imported crude oil, and for imported 

gasoline and diesel products, emissions 

associated with refining and 

distribution of the finished product to 

the U.S. For imported renewable fuel, 

all of the emissions associated with 

feedstock production and distribution, 

fuel processing, and delivery of the 

finished renewable fuel to the U.S. 

occur overseas. The definition of 

lifecycle GHG 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 result in a 

lifecycle analysis that bears no apparent 

relationship to the purpose of this 

provision. The purpose of the 

thresholds in EISA is to require the use 

of renewable fuels that achieve 

reductions in GHG emissions compared 

to the baseline. Ignoring international 

emissions, a large part of the GHG 

emission associated with the different 

fuels, would result in a GHG analysis 

that bears no relationship to the real 

world emissions impact of 

transportation fuels. The baseline would 

be significantly understated, given the 

large amount of imported crude and 

imported finished gasoline and diesel 

used in 2005. Likewise, the emissions 

estimates for imported renewable fuel 

would be grossly reduced in comparison 

to the aggregate emissions estimates for 

fuels made domestically with 

domestically-grown feedstocks, simply 

because the impacts of domestically 

produced fuels occurred within the U.S. 

EPA does not believe that Congress 

intended such a result. 

Excluding international impacts 

means 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 where the emissions 

occur. If the purpose of thresholds is to 

achieve some reduction in GHG 

emissions in order to help address 

climate change, then ignoring emissions 

outside our borders interferes with the 

ability to achieve this objective. Such an 

approach would essentially undermine 

the purpose of the provision, and would 

be an arbitrary interpretation of the 

broadly phrased text used by Congress. 

One commenter stated that matters 

that could appropriately be considered 

part of a food lifecycle (new land 

clearing for overseas grain production as 

a result of decreased U.S. grain exports) 

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should not be considered part of a 

renewable fuel lifecycle. However, the 

suggested approach would mean that 

EPA would fail to account for the 

significant indirect emissions that relate 

to renewable fuel production. EPA 

believes this would be counter to 

Congressional intent. Although a life 

cycle analysis of foreign food 

production may also take into account 

a given land use change, that does not 

mean that the same land use change 

should not be considered in evaluating 

its ultimate cause, which may be 

renewable fuel production in the United 

States. 

Some comments asserted that 

significant GHG gas emissions from 

international land use change should 

not be considered if the only available 

models for doing so are not generally 

accepted or valid considering 

economics or science, or where the 

approach is new and untested, or where 

the data are faulty and EPA models 

unrealistic scenarios. As described in 

this rulemaking, EPA has used the best 

available models and substantially 

modified key inputs to those models to 

reflect comments by peer reviewers, the 

public, and emerging science. EPA has 

also modeled additional scenarios from 

those described in the NPRM. EPA 

recognizes that uncertainty exists with 

respect to the results, and has attempted 

to quantify the range of uncertainty. 

While EPA agrees that application of the 

models it has used in the context of 

assessing GHG emissions represents 

changes from previous biofuel lifecycle 

modeling, EPA disagrees that it has used 

faulty data, modeled unrealistic 

scenarios, or that its approach is 

otherwise scientifically indefensible. 

Although the results of modeling GHG 

emissions associated with international 

land use change are uncertain, EPA has 

attempted to quantify that uncertainty 

and is now in a better position to 

consider the uncertainty inherent in its 

approach. 

One commenter asserted that by 

considering international land use 

changes, EPA is seeking to penalize 

domestic renewable fuel producers for 

impacts over which they have no 

control. In response, EPA disagrees that 

it is seeking to penalize anyone at all. 

EPA is simply attempting to account for 

all GHG emissions related to the full 

fuel lifecycle. Domestic renewable fuel 

producers may have no direct control 

over land use changes that occur 

overseas as a result of renewable fuel 

production and use here, but their 

choice of feedstock can and does 

influence oversees activities, and EPA 

believes it is appropriate to consider the 

GHG emissions from those activities in 

its analyses. 

Some commenters noted that a 

finding of causation is built into the 

definitions of ‘‘indirect effects’’ in the 

Endangered Species Act and the 

National Environmental Policy Act, and 

that EPA should interpret the reference 

to ‘‘indirect emissions’ in EISA as 

requiring similar findings of causation. 

Specifically, they argue that for EPA to 

count GHG emissions from international 

land use change in its assessments, EPA 

must find that renewable fuel 

production ‘‘caused’’ the land use 

change. In response, without addressing 

the commenter’s claims regarding the 

requirements of NEPA or the ESA, EPA 

notes that Congress has specified in 

Section 211(o) the required causal link 

between a fuel and indirect emissions. 

The indirect emissions must be ‘‘related 

to’’ the full fuel lifecycle. EPA believes 

that it has demonstrated this link 

through its modeling efforts. 

Specifically, the models predict that 

increased demand for feedstocks to 

produce renewable fuel that satisfies 

EISA mandates will likely result in 

international land use change. Such 

change is, then, ‘‘related to’’ the full fuel 

lifecycle of these fuels. EPA does not 

believe that the statute requires EPA to 

wait until these effects occur to 

establish the required linkage, but 

instead believes that it is authorized to 

use predictive models to demonstrate 

likely results. 

The term ‘‘related to’’ is generally 

interpreted broadly 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. EPA 

has used a suite of global models to 

project a variety of agricultural impacts 

of the RFS program, including changes 

in the types of crops and number of 

acres planted world-wide. These shifts 

in the agricultural market are a direct 

consequence of the increased demand 

for biofuels in the U.S. This increased 

demand diverts biofuel feedstocks from 

other competing uses, and also increases 

the price of the feedstock, thus spurring 

additional international production. Our 

analysis uses country-specific 

information to determine the amount, 

location, and type of land use change 

that would occur to meet these changes 

in production patterns. The linkages of 

these changes to increased U.S. biofuel 

demand in our analysis are generally 

close, and are not extended or overly 

complex. 

Overall, EPA is confident that it is 

appropriate to consider indirect 

emissions, including those from both 

domestic and international land use 

changes, as ‘‘related to’’ the full fuel 

lifecycle, based on the results of our 

modeling. These results form a 

reasonable technical basis for the 

linkage between the full fuel lifecycle of 

transportation fuels and indirect 

emissions, as well as for the 

determination that these emissions are 

significant. EPA believes that while 

uncertainty in the resulting aggregate 

GHG estimates should be taken into 

consideration, it would be inappropriate 

to exclude indirect emissions estimates 

from this analysis. The use of reasonable 

estimates of these kinds of indirect 

emissions allows EPA to conduct 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. 

EPA understands that including 

international indirect land use change is 

a key decision and that there is 

significant uncertainty associated with 

it. That is why we have taken an 

approach that quantifies that 

uncertainty and presents the weight of 

currently available evidence in making 

our threshold determinations. 

b. Models Used 

As described in the proposal, to 

estimate lifecycle indirect impacts of 

biofuel production requires the use of 

economic modeling to determine the 

market impacts of using agricultural 

commodity feedstocks for biofuels. The 

use of economic models and the 

uncertainty of those models to 

accurately predict future agricultural 

sector scenarios was one of the main 

comments we received on our analysis. 

While the comments and specifically 

the peer review supported our need to 

use economic models to incorporate and 

measure indirect impacts of biofuel 

production, they also highlighted the 

uncertainty with that modeling 

approach, especially in projecting out to 

the future. 

However, it is important to note that 

while there are many factors that impact 

the uncertainty in predicting total land 

used for crop production, making 

accurate predictions of many of these 

factors are not relevant to our analysis. 

For example different assumptions 

about economic growth rates, weather, 

and exchange rates will all impact 

future agricultural projections including 

amount of land use for crops. However, 

we are interested only in the difference 

between two biofuel scenarios holding 

all other changes constant. So the 

absolute values and projections for 

crops and other variables in the model 

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projections are not as important as the 

difference the model is projecting due to 

an increase in biofuels production. This 

limits the uncertainty of using the 

economic models for our analysis. 

Furthermore, one of the key 

uncertainties associated with our 

agricultural sector economic modeling 

that has the biggest impact on land use 

change results is the assumptions 

around crop yields. As discussed in 

Section V.A.2, we are conducting 

sensitivity analysis around different 

yield assumptions in our analysis. 

Therefore, because of the fact that we 

are only using the economic models to 

determine the difference between two 

projected scenarios and the fact that we 

are conducting sensitivity analysis 

around the yield assumptions we feel it 

is appropriate and acceptable to use 

economic models in our analysis of 

determining GHG thresholds in our final 

rule analysis. 

As was the case in the proposed 

analysis, 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, EPA uses the 

Forestry and Agricultural Sector 

Optimization Model (FASOM), 

developed by Texas A&M University 

and others. To estimate the impacts of 

biofuels feedstock production on 

international agricultural and livestock 

production, we used the integrated Food 

and Agricultural Policy and Research 

Institute international models, as 

maintained by the Center for 

Agricultural and Rural Development 

(FAPRI–CARD) at Iowa State University. 

One of the main comments we 

received on our choice of models was 

the issue of transparency. Several 

comments were concerned that the 

results of EPA’s modeling efforts can not 

be duplicated outside the experts who 

developed the models and conducted 

the analysis used by EPA in the 

proposal. Upon the release of the 

proposal, EPA requested comment on 

the use of these various models. EPA 

conducted a number of measures to 

gather comments, including the public 

comment period upon release of the 

NPRM analysis, holding a public 

workshop on the lifecycle methodology, 

and conducting a peer review of the 

lifecycle methodology. Specifically, one 

of the major tasks of the peer review of 

EPA’s lifecycle GHG methodology was 

to review and comment on the use of 

the various models and their linkages. 

The response we received through the 

peer review is supportive of our use of 

the FASOM and FAPRI–CARD models, 

affirming that they are the strong and 

appropriate tools for the task of 

estimating land use changes stemming 

from agricultural economic impacts due 

to changes in biofuel policy. 

In addition, in an effort to garner as 

useful comments as possible and to be 

as transparent as possible about the 

modeling process, EPA supplied in the 

docket technical documents for the 

FASOM and FAPRI–CARD models, the 

output received by EPA from each 

model, and the models themselves such 

that the public and commenters could 

learn and examine how each model 

operates. 

Building upon the support for the use 

of the FASOM and FAPRI–CARD 

models, a number of important 

enhancements were made to both 

models in response to comments 

received through the public comment 

system and through the peer review, 

and in consultation with various experts 

on domestic and international 

agronomics. These enhancements 

include updated substitution rates of 

corn and soybean meal for distillers 

grains (DG) based on recent scientific 

research by Argonne National 

Laboratory, the addition of a corn oil 

from the dry mill ethanol extraction 

process as a source of biodiesel, the full 

incorporation of FASOM’s forestry 

model that dynamically interacts with 

the agriculture sector model in the U.S., 

as well as the addition of a Brazil 

regional model to the FAPRI–CARD 

modeling system. All of these 

enhancements are discussed in more 

detail below and in the RIA (Chapter 2 

and 5). In addition to the model 

enhancements we also conducted a 

sensitivity analysis on yields as part of 

our final rule analysis. These updates to 

our modeling and the sensitivity 

analysis was done in response to public 

comments specifically asking for this to 

add transparency to the modeling and 

modeling results. 

We also received comments on the 

combined use of FASOM and FAPRI– 

CARD. Several comments and peer 

reviewers questioned the benefit of 

using two agricultural sector models. 

Specifically reviewers pointed to some 

of the inconsistencies in the FASOM 

and FAPRI–CARD domestic results. For 

the final rule analysis we worked to 

reconcile the two model results. We 

apply the same set of scenarios and key 

input assumptions in both models. For 

example, both models were updated to 

apply consistent treatment of DGs in 

domestic livestock feed replacement 

and consistent assumptions regarding 

DG export. 

Some reviewers questioned the 

benefits of using FASOM and suggested 

we rely entirely on the FAPRI–CARD 

model for the analysis. However, we 

continue to believe there are benefits to 

the use of FASOM. Specifically, the fact 

that FASOM has domestic land use 

change interactions between crop, 

pasture, and forest integrated into the 

modeling is an advantage over using the 

domestic FAPRI–CARD model that only 

tracks cropland. 

c. Scenarios Modeled 

As was done for the proposal, 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 volume 

scenarios in our economic models. 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 sectors 

of the economy in response to a given 

volume change in the amount of biofuel 

produced. 

Volume Scenarios: The two future 

scenarios considered included 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 scenario 

assumed a higher volume of renewable 

fuels as mandated by EISA for 2022. 

We project our analysis and economic 

modeling through the life of the 

program. We then consider the impacts 

of an increase of biofuels on the 

agricultural sector in 2022 as the basis 

for our threshold analysis. This was an 

area that we received numerous 

comments on highlighting that this 

approach adds uncertainty to our results 

because we are projecting uncertain 

technology and other changes out into 

the future. One of the recommendations 

was to base the lifecycle GHG 

assessments on a near term time frame 

and update the analysis every few years 

to capture actual technology changes. 

We continue to focus our final rule 

analyses on 2022 results for two main 

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 

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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. This also 

allows for the complete implementation 

of technology changes and updates that 

were made to improve or modeling 

efforts. For example, the inclusion of 

price induced yield increases and the 

efficiency gains of DGs replacement are 

phased in over time. Furthermore, these 

changes are in part driven by the 

changes in earlier years of increased 

biofuel use. 

Crop Yield Scenarios: EPA received 

numerous comments to the effect that 

we should consider a case in our 

economic models with higher yields 

that what were projected for the 

proposed rule analysis. There are many 

factors that go into the economic 

modeling but the yield assumptions for 

different crops has one of the biggest 

impacts on land use and land use 

change. Therefore, for this analysis we 

ran a base yield case and a high yield 

case. This will provide two distinct 

model results for key parameters like 

total amount of land converted by crop 

by country. 

EPA’s base yield projections are 

derived from extrapolating through 2022 

long-term historical U.S. corn yields 

from 1985 to 2009. This estimate, 183 

bushels/acre for corn and 48 bushels/ 

acre for soybeans, is consistent with 

USDA’s method of projecting future 

crop yields. During the public comment 

process we learned that numerous 

technical advancements— including 

better farm practices, seed hybridization 

and genetic modification—have led to 

more rapid gains in yields since 1995. 

In addition, commenters, including 

many leading seed companies, provided 

data supporting more rapid 

improvements in future yields. For 

example, commenters pointed to recent 

advancements in seed development 

(including genetic modification) and the 

general accumulation of knowledge of 

how to develop and bring to market 

seed varieties—factors that would allow 

for a greater rate of development of seed 

varieties requiring fewer inputs such as 

fertilizer and pest management 

applications. This new information 

would suggest that the base yield may 

be a conservative estimate of future 

yields in the U.S. Therefore, in 

coordination with USDA experts, EPA 

has developed for this final rule a high 

yield case scenario of 230 bushels/acre 

for corn and 60 bushels/acre for 

soybeans. These figures represent the 

99% upper bound confidence limit of 

variability in historical U.S. yields. This 

high yield case represents a feasible 

high yield scenario for the purpose of a 

sensitivity test of the impact on the 

results of higher yields. 

Feedback we received indicated that 

corn and soybean yields respond in 

tandem and that a high yield corn case 

would also imply a higher yield for 

soybeans as well. The high yield case is 

therefore based on higher yield corn and 

soybeans in the U.S. as well as in the 

major corn and soybean producing 

countries around the world. For 

international yields, it is reasonable to 

assume the same percent increases from 

the baseline yield assumptions could 

occur as we are estimating for the U.S. 

Thus in the case of corn, 230 bushels 

per acre is approximately 25% higher 

than the U.S. baseline yield of 183 

bushels per acre in 2022. This same 

25% increase in yield can be expected 

for the top corn producers in the rest of 

the world by 2022, as justified 

improvements in seed varieties and, 

perhaps even more so than in the case 

of the U.S., improvements in farming 

practices which can take more full 

advantage of the seed varieties’ 

potential. For example, seeds can be 

more readily developed to perform well 

in the particular regions of these 

countries and can be coupled with 

much improved farming practices as 

farmers move away from historical 

practices such as saving seeds from their 

crop for use the next year and better 

understand the economic advantages of 

modern farming practices. So the high 

yield scenarios would not have the same 

absolute yield values in other countries 

as the U.S. but would have the same 

percent increase. 

While we modeled a high yield 

scenario for this analysis we continue to 

rely primarily on the base yield 

estimates in our assessments of different 

biofuel lifecycle GHG emissions 

recognizing that the base yields could be 

conservative. The reasons outlined 

above could lead to higher rates of yield 

growth in the future, however, there are 

mitigating factors that could limit this 

yield growth or potentially cause 

reductions in yield growth rates. For 

example, the water requirements for 

both increased corn farming and ethanol 

production could lead to future water 

constraints that may in some regions 

limit yield growth potential. 

Furthermore, one of the long term 

impacts of potential global climate 

change could be a reduction in 

agricultural output of different impacted 

regions around the world, including the 

U.S. This could also serve to reduce 

yield growth. As with many aspects of 

this lifecycle modeling, as the science 

and data evolves on crop yields, the 

Agency will update its factors 

accordingly. 

2. Biofuel Modeling Framework & 

Methodology for Lifecycle Analysis 

Components 

As discussed above, to account for the 

direct and indirect emissions of biofuel 

production required the use of 

agricultural sector economic models. 

The results of these models were 

combined with other data sources to 

generate lifecycle GHG emissions for the 

different fuels. The basic modeling 

framework involved the following steps 

and modeling tools. 

To estimate the changes in the 

domestic agricultural sector we used 

FASOM, developed by Texas A&M 

University and others. FASOM is a 

partial equilibrium economic model of 

the U.S. forest and agricultural sectors 

that tracks over 2,000 production 

possibilities for field crops, livestock, 

and biofuels for private lands in the 

contiguous United States. Because 

FASOM captures the impacts of all crop 

production, not just biofuel feedstock, 

we are able to use it to determine 

secondary agricultural sector impacts, 

such as crop shifting and reduced 

demand due to higher prices. 

The output of the FASOM analysis 

includes changes in total domestic 

agricultural sector fertilizer and energy 

use. These are calculated based on the 

inputs required for all the different 

crops modeled and changes in the 

amounts of the different crops produced 

due to increased biofuel production. 

FASOM output also includes changes in 

the number and type of livestock 

produced. These changes are due to the 

changes in animal feed prices and makeup due to the increase in biofuel 

production. The FASOM output 

changes in fertilizer, energy use, and 

livestock are combined with GHG 

emission factors from those sources to 

generate biofuel lifecycle impacts. The 

GHG emission factors for fuel and 

fertilizer production come from the 

Greenhouse gases, Regulated Emissions, 

and Energy use in Transportation 

(GREET) spreadsheet analysis tool 

developed by Argonne National 

Laboratories, and livestock GHG 

emission factors are from IPCC 

guidance. 

To estimate the domestic impacts of 

N2O emissions from fertilizer 

application, we used the DAYCENT 

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model developed by Colorado State 

University. 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, and NOX). 

DAYCENT model results for N2O 

emissions from different crop and land 

use changes were combined with 

FASOM output to generate overall 

domestic N2O emissions. 

FASOM output also provides changes 

in total land use required for agriculture 

and land use shifting between crops, 

and interactions with pasture, and 

forestry. This output is combined with 

emission factors from land use change 

to generate domestic land use change 

GHG emissions from increased biofuel 

production. 

To estimate the impacts of biofuels 

feedstock production on international 

agricultural and livestock production, 

we used the integrated FAPRI–CARD 

international models, developed by 

Iowa State University. These worldwide 

agricultural sector economic models 

capture the biological, technical, and 

economic relationships among key 

variables within a particular commodity 

and across commodities. 

The output of the FAPRI–CARD 

model included changes in crop acres 

and livestock production by type by 

country globally. Unlike FASOM, the 

FAPRI–CARD output did not include 

changes in fertilizer or energy use or 

have land type interactions built in. 

These were developed outside the 

FAPRI–CARD model and combined 

with the FAPRI–CARD output to 

generate GHG emission impacts. 

Crop input data by crop and country 

was developed and combined with the 

FAPRI–CARD output crop acreage 

change data to generate overall changes 

in fertilizer and energy use. These 

fertilizer and energy changes along with 

the FAPRI–CARD output livestock 

changes were then converted to GHG 

emissions based on the same basic 

approach used for domestic sources, 

which involves combining with 

emission factors from GREET and IPCC. 

International land use change 

emissions were determined based on 

combining FAPRI–CARD output of crop 

acreage change with satellite data to 

determine types of land impacted by the 

projected crop changes and then 

applying emission factors of different 

land use conversions to generate GHG 

impacts. 

Additional modeling and data sources 

used to determine the GHG emissions of 

other stages in the biofuel lifecycle 

include studies and data on the distance 

and modes of transport needed to ship 

feedstock from the field to the biofuel 

processing facility and the finished 

biofuel from the facility to end use. 

These distances and modes are used to 

develop amount and type of energy used 

for transport which is combined with 

GREET factors to generate GHG 

emissions. We also calculate energy use 

needed in the biofuel processing facility 

from industry sources, reports, and 

process modeling. This energy use is 

combined with emissions factors from 

GREET to develop GHG impacts of the 

biofuel production process 

The following sections outline how 

the modeling tools and methodology 

discussed above were used in 

conducting the analysis for the different 

lifecycle stages of biofuel production, 

including changes made since the 

proposal. Lifecycle stages discussed 

include feedstock production, land use 

change, feedstock and fuel transport, 

biofuel production, and vehicle end use. 

The modeling of the petroleum fuels 

baseline is discussed in Section V.B.3. 

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). 

i. Domestic Agricultural Sector Impacts 

Agricultural Sector Inputs: The 

proposal analysis calculated GHG 

emissions from domestic agriculture 

fertilizer and energy use and production 

change by applying rates of energy and 

fertilizer use by crop by region to the 

FASOM acreage data and then 

multiplying by 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. 

In general commenters supported this 

approach as it captures all indirect 

impacts of agricultural sector emissions 

and not just those associated with the 

specific biofuel crop in question. 

However, we did receive comments as 

part of our Model Linkages Peer Review 

that the input data for some crops may 

be overestimating GHG emissions. 

Specifically, the commenter highlighted 

that N2O emissions from domestic hay 

production seemed to be over estimated. 

As part of the final rule analysis EPA 

confirmed that input data was being 

used correctly, however, the hay N2O 

emissions in the proposal may have 

been overestimated based on the 

approach used in the proposal to 

generate N2O emissions from nitrogen 

fixing crops. This has been updated for 

the final rule analysis as discussed in 

the next section which resulted in lower 

emissions from nitrogen fixing crops. 

Other comments indicated that we 

should be using the most up to date data 

for our calculations of GHG emissions. 

Since the proposal there has been a new 

release of the GREET model (Version 

1.8C). EPA reviewed the new version 

and concluded that this was an 

improvement over the previous GREET 

release that was used in the proposal 

analysis (Version 1.8B). Therefore, EPA 

updated the GHG emission factors for 

fertilizer production used in our 

analysis to the values from the new 

GREET version. This had the result of 

slightly increasing the GHG emissions 

associated with fertilizer production 

and thus slightly increasing the GHG 

emission impacts of domestic 

agriculture. 

As was the case in the proposal, we 

held the rates of domestic fertilizer 

application constant over time. This is 

true for both of our yield scenarios 

considered as well as for price induced 

yield increases. This constant rate of 

application is justified based on USDA 

data indicating that crops are becoming 

more efficient in their uptake of 

fertilizer such that higher yields can be 

achieved based on the same per acre 

fertilizer application rates. 

N2O Emissions: The proposal analysis 

calculated N2O emissions from domestic 

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. The proposal analysis N2O 

factors were based on existing 

DAYCENT modeling that was 

developed using the 1996 IPCC 

guidance for calculating N2O emissions 

from fertilizer applications and nitrogen 

fixing crops. We identified in the 

proposal that this was an area we would 

be updating for the final rule based on 

new analysis from Colorado State 

University using the DAYCENT model. 

This update was not available at time of 

proposal. 

We received a number of comments 

on our proposal results indicating that 

the N2O emissions were overestimated 

from soybean and other legume 

production (e.g., nitrogen fixing hay) in 

our analysis. The main issue is that 

because the N2O emission factors used 

in the proposal were based on the 1996 

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IPCC guidance for N2O accounting they 

were overestimating N2O emissions 

from nitrogen fixing crops. As an update 

in 2006, IPCC guidance was changed 

such that biological nitrogen fixation 

was removed as a direct source of N2O 

because of the lack of evidence of 

significant emissions arising from the 

fixation process itself. IPCC concluded 

that the N2O emissions induced by the 

growth of legume crops/forages may be 

estimated solely as a function of the 

above-ground and below-ground 

nitrogen inputs from crop/forage 

residue. This change effectively reduces 

the N2O emissions from nitrogen fixing 

crops like soybeans and nitrogen fixing 

hay from the 1996 to 2006 IPCC 

guidance. 

Therefore, as part of the update to 

new N2O emission factors from 

DAYCENT used for our final rule 

analysis we have updated to the 2006 

IPCC guidance which reduces the N2O 

emissions from soybean production. 

This has the effect of reducing lifecycle 

GHG emissions for soybean biodiesel 

production. When we model corn 

expansion as would result from 

increased production of corn-based 

ethanol, one of the impacts is that the 

increase in corn acres displaces some 

acres otherwise planted to soy beans. 

Since the GHG emissions impact of this 

change in land use considers the N2O 

emissions benefit from the displaced 

soy, the result of this lower soy bean 

N2O assessment means that the benefits 

for soy displacement are less, 

directionally increasing the net GHG 

emissions for corn expansion. 

We also received comments on our 

approach that we should use IPCC 

factors directly as opposed to relying on 

DAYCENT modeling. The difference is 

that IPCC provides default factors by 

crop by country, while DAYCENT 

models N2O emissions by crop but also 

by region within the US, accounting for 

different soil types and weather factors. 

For the final rule we still rely on the 

DAYCENT modeling results as we 

believe them to be more accurate. For 

example, the National Greenhouse Gas 

Inventory as reported annually by the 

US to the Framework Convention on 

Climate Change uses the DAYCENT 

model to determine N2O emissions from 

domestic fertilizer use as opposed to 

using default IPCC factors as the 

DAYCENT modeling is recognized to be 

a more accurate approach. 

Livestock Emissions: GHG emissions 

from livestock have two main sources: 

enteric fermentation and manure 

management. For the proposal, enteric 

fermentation methane emissions were 

determined by applying IPCC default 

factors for different livestock types to 

herd values as calculated by FASOM to 

get GHG emissions. Comments we 

received on this approach were that the 

default IPCC factors do not account for 

the beneficial use of distiller grains 

(DGs) as animal feed. Use of DGs has 

been shown to decrease methane 

produced from enteric fermentation if 

replacing corn as animal feed. This is 

due to the fact that the DGs are a more 

efficient feed source. Consistent with 

our assumptions regarding the 

efficiency of DGs as an animal feed in 

our agricultural sector modeling, we 

have also included the enteric 

fermentation methane reductions of DGs 

use in our final rule analysis. The 

reduction amount was based on default 

factors in GREET that calculated this 

reduction based on the same Argonne 

report used to determine DGs feed 

replacement efficiency discussed in 

Section V.B.2.b.i. This resulted in a 

reduction in the lifecycle GHG 

emissions for corn ethanol compared to 

the proposal assumptions. More detail 

on the enteric fermentation methane 

reductions of DGs use can be found in 

Chapter 2 of the RIA. 

The proposal analysis also included 

the methane and N2O emissions of 

livestock manure management based on 

IPCC default factors for emissions from 

the different types of livestock and 

management methods combined with 

FASOM results for livestock changes. 

We received comments that this was a 

good approach as it quantifies the 

indirect impacts of emissions associated 

with biofuel production. The same 

approach was used for the final rule 

analysis. 

Methane from Rice: For the proposal, 

methane emissions from rice production 

were calculated by taking the FASOM 

output predicted changes in rice acres, 

resulting from the increase in biofuel 

production, and multiplying by default 

methane emission factors from IPCC to 

generate GHG impacts. We received 

comments that this was a good approach 

as it quantifies the indirect impacts of 

emissions associated with biofuel 

production. The same approach was 

used for the final rule analysis. 

ii. International Agricultural Sector 

Impacts 

Agricultural Sector Inputs: For the 

proposal we determined international 

fertilizer and energy use emissions 

based on applying input data collected 

by the Food and Agriculture 

Organization (FAO) of the United 

Nations and the International Energy 

Agency (IEA) to the FAPRI–CARD crop 

output data and then applied GREET 

defaults for converting those inputs to 

GHG emissions. 

As part of our public comment and 

peer review process we had this 

component of our analysis specifically 

peer reviewed. The main comment we 

received was to update our input data 

with newer data sources. Therefore, for 

the final rule analysis we updated 

fertilizer and pesticide consumption 

projections from the incorporation of 

updates made by the FAO to its Fertistat 

and FAOStat datasets, as well as the 

incorporation of more up-to-date 

fertilizer consumption statistics 

provided by a recent International 

Fertilizer Institute (IFA) report. This 

update had varying impacts on the 

amount of fertilizer used on different 

crops in different countries but in 

general increased the amount of 

fertilizer assumed and thus 

international agriculture lifecycle GHG 

emissions from fertilizer use for all 

biofuels. 

Another comment from the peer 

review was that we should include lime 

use for some of the key crops modeled 

in our analysis. Lime use was not 

included in the proposal because of lack 

of international data on lime use by 

crop. Excluding lime used is an 

underestimate of international 

agriculture GHG emissions. For our final 

rule analysis we included lime use for 

sugarcane production in Brazil based on 

information received from Brazilian 

agricultural experts provided as part of 

the comment process. This led to an 

increase in GHG emissions from 

sugarcane farming. We did not include 

lime use for other crops in the final rule 

analysis because of lack of other data 

sources for other crops. 

Other comments we received on our 

approach were that we were potentially 

underestimating GHG emissions from 

international agriculture energy use. 

Our proposal based international 

agriculture energy use on factors from 

the International Energy Agency (IEA) 

that included all energy use for 

agriculture that we divided by all 

agricultural sector land by country to get 

a GHG emission per acre for each 

country considered. The comment 

raised the issue that by using all 

agricultural land this includes pasture 

land that would not have the same 

energy input as crop production. 

Effectively, higher energy use from crop 

production was getting averaged with 

lower energy use for pasture and then 

this lower number was applied only to 

crop production. We specifically asked 

as part of our peer review for guidance 

and comment on our international 

agriculture energy use calculation. We 

did not receive significant comments or 

data to suggest that we change our 

approach and reviewers generally 

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167Salil, A., M. Wu, and M. Wang. 2008. ‘‘Update 

of Distillers Grains Replacement Ratios for Corn 

Ethanol Life-Cycle Analysis.’’ Available at http:// 

www.transportation.anl.gov/pdfs/AF/527.pdf. 

agreed we were using the best data 

available. Furthermore, the energy use 

values represent all agriculture 

including forestry and fishing which 

could in some countries be 

overestimating energy use for crop 

production. So for our final rule 

analysis we used the same approach as 

for the proposal to calculate 

international agriculture energy use 

GHG emissions. 

We also received comments on the 

applicability of applying GREET 

defaults for fuel and fertilizer 

production to international fuel and 

fertilizer use to generate GHG emissions. 

The comments noted that GREET factors 

are developed for domestic US 

conditions and would not necessarily 

apply internationally. Specifically on 

the issue of nitrogen fertilizer 

production, the comments indicated 

that nitrogen fertilizer production 

internationally could rely on coal as a 

fuel source as opposed to natural gas 

used in the US, which would cause 

international GHG emissions associated 

with fertilizer production and hence 

biofuel production to be underestimated 

in our analysis. This was also an area 

we asked peer reviewers for comment 

and guidance. The peer review response 

generally supported our approach and 

did not offer suggestions for other data 

sources. So for our final rule analysis we 

used the same approach as for the 

proposal and applied GREET defaults to 

calculate international fertilizer 

production GHG emissions. 

As was the case in the proposal and 

for domestic agriculture, we held the 

rates of international fertilizer 

application constant over time. This is 

true for both of our yield scenarios 

considered as well as for price induced 

yield increases. This was an area that 

was specifically addressed in our peer 

review of International Agricultural 

Greenhouse Gas Emissions and Factors. 

The reviewers supported the approach 

we have taken, for example indicating 

that generally crop production as a unit 

of fertilizer application has increased 

over time, therefore, crop yields have 

increased with the same or lower 

fertilizer applications. 

N2O Emissions: For the proposal we 

included N2O emissions from fertilizer 

application by applying IPCC default 

factors for different crops in different 

countries. We use IPCC default factors 

because we do not have the same level 

of regional factors like we do in the US 

from the DAYCENT model. The IPCC 

guidance has emission factors for four 

sources of N2O emissions from crops, 

Direct N2O Emissions from Synthetic 

Fertilizer Application, Indirect N2O 

Emissions from Synthetic Fertilizer 

Application, Direct Emissions from 

Crop Residues, and Indirect Emissions 

from Crop Residues. The proposal did 

not include N2O emissions from the 

Direct and Indirect Emissions from Crop 

Residues for cotton, palm oil, rapeseed, 

sugar beet, sugarcane, or sunflower. 

These were not included for these crops 

because default crop-specific IPCC 

factors used in the calculation were not 

available. 

Comments from our peer review 

process suggested that we include proxy 

emissions from these crops based on 

similar crop types that do have default 

factors. Therefore, for our final rule 

analysis we have included crop residue 

N2O emissions from sugarcane 

production based on perennial grass as 

a proxy. Perennial grass is chosen as a 

proxy based on input from N2O 

modeling experts. This change results in 

an increase in N2O emissions from 

sugarcane and therefore sugarcane 

ethanol production compared to the 

proposal. 

Livestock Emissions: Similar to 

domestic livestock impacts, enteric 

fermentation and manure management 

GHG emissions were included in our 

proposal analysis. The proposal 

calculated international livestock GHG 

impacts based on activity data provided 

by the FAPRI–CARD model (e.g., 

number and type of livestock by 

country) multiplied by IPCC default 

factors for GHG emissions. 

Based on the peer review of the 

methodology used for the proposal it 

was determined that the calculations for 

manure management did not include 

emissions from soil application. These 

emissions were included for our final 

rule analysis but do not cause a 

significant change in the livestock GHG 

emission results. 

Rice Emissions: To estimate rice 

emission impacts internationally, the 

proposal used the FAPRI–CARD model 

to predict changes in international rice 

production as a result of the increase in 

biofuels demand in the U.S. We then 

applied IPCC default factors by country 

to these predicted changes in rice acres 

to generate GHG emissions. We received 

comments that this was a good approach 

as it quantifies the indirect impacts of 

emissions associated with biofuel 

production. The same approach was 

used for the final rule analysis. 

b. Land Use Change 

The following sections discuss our 

final rulemaking assessment of 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. 

There are four main methodology 

questions addressed both domestically 

and internationally: 

• Amount of Land Converted and 

Where. 

• Type of Land Converted. 

• GHG Emissions Associated with 

Conversion. 

• Timeframe of Emission Analysis. 

Each of those methodology 

components are discussed as are the 

comments we received as part of the 

comment and peer review process. We 

also outline in addition to our main 

FASOM and FAPRI–CARD approach a 

general equilibrium modeling 

approaches and its results. 

i. Amount of Land Area Converted and 

Where 

Based on a number of modeling 

changes made to the FASOM and 

FAPRI–CARD models since the NPRM, 

the amount of land use change resulting 

from an increase in biofuel demand in 

the U.S. is significantly lower in this 

FRM analysis for most renewable fuels. 

Many of the changes made were a direct 

result of comments received through the 

notice-and-comment period, comments 

received from the peer-reviewers, or as 

a result of incorporating new science 

that has become available since the 

analysis was conducted in the proposal. 

Some of the key changes that had the 

largest impact on the land use change 

estimates are included in this section. 

For additional information, see Chapter 

2 of the RIA. 

As discussed in the NPRM, one of the 

key factors in determining the amount 

of new land needed to meet an increase 

in biofuel demand is the treatment of 

co-products of ethanol and biodiesel 

production. We received many 

comments on this topic, particularly on 

the amount of corn and soybean meal a 

pound of DGS, the byproduct of dry mill 

grain ethanol production, can replace in 

animal feed. For the final rule, we 

predict that distiller grains will be 

absorbed by livestock more efficiently 

over time. We updated the displacement 

rate assumptions in the FASOM and 

FAPRI–CARD models based on 

comments we received and on the 

recent research conducted by Argonne 

National Laboratory and others.167

According to this research, one pound 

of DGS replaces more than a pound of 

corn and/or soybean meal in beef and 

dairy rations, in part because cattle fed 

DGS show faster weight gain and 

increased milk production compared to 

those fed a traditional diet. While this 

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168Technical Report: An Analysis of EPA 

Renewable Fuel Scenarios with the FAPRI–CARD 

International Models, CARD Staff, January, 2010. 

169Thomson, A.M., R.C. Izarrualde, T.O. West, 

D.J. Parrish, D.D. Tyler, and J.R. Williams. 2009. 

Simulating Potential Switchgrass Production in the 

United States. PNNL–19072. College Park, MD: 

Pacific Northwest National Laboratory. 

study represents a significant increase 

over current DGS replacement rates, we 

believe it is reasonable to assume that 

improvements will be made in the use 

and efficiency of DGS over time as the 

DGS market matures, the quality and 

consistency of DGS improves, and as 

livestock producers learn to optimize 

DGS feed rations. As a result of this 

modification, less land is needed to 

replace the amount of corn diverted to 

ethanol production. Additional details 

on the DGS assumptions are included in 

Chapters 2 and 5 of the RIA. 

A second factor that can have a 

significant impact on the amount of 

land that may be converted as a result 

of increasing biofuel demand are 

changes in crop yields over time. As 

discussed in the NPRM, our proposal 

based domestic yields on USDA 

projections for both the reference case 

and the control case. As discussed in 

Section V.B.1.c, for this FRM we have 

also included scenarios that use higher 

yield projections in both the reference 

case and the control case. However, in 

the NPRM we also requested comment 

on whether the higher prices caused by 

an increased in demand for biofuels 

would increase future yield projections 

in the policy case beyond the yield 

trends in the reference case (sometimes 

referred to as ‘‘price induced yields’’), or 

whether these price induced yields 

would be offset by the reduction in 

yields associated with expanding 

production onto new marginal acres 

(sometimes referred to as 

extensification). Based on the comments 

we received, along with additional 

historical trend analysis conducted by 

FAPRI–CARD, the international 

agricultural modeling framework now 

incorporates a price induced yield 

component.168 The new yield 

adjustments are partially offset by the 

extensification factor, however, the 

combined impact is that fewer new 

acres are needed for agricultural 

production to meet world agricultural 

demands. 

One additional change we made to the 

yield assumptions was to update the 

FASOM model with new analysis by 

Pacific Northwest National Laboratories 

(PNNL) on switchgrass yields.169 We 

included this new data for two reasons. 

First, we received several comments 

that our assumptions on switchgrass 

yields were too low, based on more 

recent field work. In addition, for out 

NPRM analysis, we did not have data 

for switchgrass yields in certain regions 

of the US. Therefore, the PNNL data 

helped to fill a pre-existing data gap. As 

a result of these updates, less land is 

needed per gallon of switchgrass 

ethanol produced. Additional details on 

switchgrass yields and other agricultural 

sector modeling assumptions are 

included in RIA Chapter 5. 

One of the major changes made to the 

FAPRI–CARD model between the NPRM 

and FRM includes the more detailed 

representation of Brazil through a new 

integrated module. The Brazil module 

was developed by Iowa State with input 

from Brazilian agricultural sector 

experts and we believe it is an 

improvement over the approach used in 

the proposal. In the NPRM, we 

requested additional data for countries 

outside the U.S. We received comments 

encouraging us to use regional and 

country specific data where it was 

available. We also received comments 

encouraging us to take into account the 

available supply of abandoned 

pastureland in Brazil as a potential 

source of new crop land. The new Brazil 

module addresses these comments. 

Since the Brazil module contains data 

specific to six regions, this additional 

level of details allows FAPRI–CARD to 

more accurately capture real-world 

responses to higher agricultural prices. 

For example, double cropping (the 

practice of planting a winter crop of 

corn or wheat on existing crop acres) is 

a common practice in Brazil. Increased 

double cropping is feasible in response 

to higher agricultural prices, which 

increases total production without 

increasing land use conversion. The 

new Brazil module also explicitly 

accounts for changes in pasture acres, 

therefore accounting for the competition 

between crop and pasture acres. 

Furthermore, the Brazil module 

explicitly models livestock 

intensification, the practice of 

increasing the number of heads of cattle 

per acre of land in response to higher 

commodity prices or increased demand 

for land. 

In addition to modifying how pasture 

acres are treated in Brazil, we also 

improved the methodology for 

calculating pasture acreage changes in 

other countries. We received several 

comments through the public comment 

period and peer reviewers supporting a 

better analysis of the interaction 

between crops, pasture, and livestock. 

In the NPRM, although we accounted 

for GHG emissions from livestock 

production (e.g., manure management), 

we did not explicitly account for GHG 

emissions from changes in pasture 

demand. In response to comments 

received, our new methodology 

accounts for changes in pasture area 

resulting from livestock fluctuations and 

therefore captures the link between 

livestock and land used for grazing. 

Based on regional pasture stocking rates 

(livestock per acre), we now calculate 

the amount of land used for livestock 

grazing. The regional stocking rates 

were determined with data on livestock 

populations from the UN Food and 

Agricultural Organization (FAO) and 

data on pasture area measured with 

agricultural inventory and satellitederived land cover data. As a result of 

this change, in countries where 

livestock numbers decrease, less land is 

needed for pasture. Therefore, unneeded 

pasture acres are available for crop land 

or allowed to revert to their natural 

state. In countries where livestock 

numbers increase, more land is needed 

for pasture, which can be added on 

abandoned cropland or unused 

grassland, or it can result in 

deforestation. We believe this new 

methodology provides a more realistic 

assessment of land use changes, 

especially in regions where livestock 

populations are changing significantly. 

For additional information on the 

pasture replacement methodology, see 

RIA Chapter 2. 

Although the total amount of land use 

conversion is lower in the FRM analysis 

compared to the NPRM analysis, the 

regional distribution of this land use 

change has shifted. Due to the many 

changes made in response to comments 

associated with agriculture and 

livestock markets, Brazil is now much 

more responsive to changes in world 

biofuel and agricultural product 

demand. As a result, a larger portion of 

the projected land use change occurs in 

Brazil compared to the NPRM analysis. 

Additional details on the geographical 

location of land use change are included 

in Chapter 2 of the RIA. 

ii. Type of Land Converted 

Based on a number of improvements 

in our analysis, the types of land 

affected by biofuel-induced tend to be 

less carbon intensive compared to the 

NPRM. Therefore, the net effect of our 

revisions to this part of our analysis 

significantly reduced land use change 

GHG emissions. The updated FAPRI– 

CARD Brazil model, discussed in the 

previous section, showed more pasture 

expansion in the Amazon which 

increased land use change emissions. 

However, the most important revisions 

to this part of our international analysis, 

in terms of their net effect on GHG 

emissions, were improvements that we 

made in our modeling of the 

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interactions between livestock, pasture, 

crops and unused, or underutilized, 

grasslands globally. In the NPRM we 

made the broad assumption that 

international crop expansion would 

necessarily displace pasture, which 

would require an equivalent amount of 

pasture to expand into forests and 

shrublands. In the FRM analysis as 

discussed in the previous section, we 

have linked international changes in 

livestock production with changes in 

pasture area to allow for pasture 

abandonment in regions where livestock 

production decreases as a result of 

biofuel production. We also 

incorporated the ability of pasture to 

expand onto unused, or underutilized, 

grasslands and savannas which on a 

global basis reduced the amount of 

forest conversion compared to the 

proposal. These revisions, as well as a 

quantitative uncertainty assessment, are 

discussed in this section. 

In the same way that the amount and 

location of land use change is 

important, the type of land converted is 

also a critical determinant of the 

magnitude of the GHG emissions 

impacts associated with biofuel 

production. For example, the 

conversion of rainforest to agriculture 

results in a much larger GHG release 

than conversion of grassland. In the 

proposed rule analysis we used two 

approaches, based on the best available 

information to us at the time, to evaluate 

the types of land that would be affected 

domestically and internationally. 

Domestically, we used the FASOM 

model, which simulates rental rates for 

different types of land (e.g., forest, 

pasture, crop) and chooses the land uses 

that would produce the highest net 

returns. Internationally, we used the 

FAPRI–CARD/Winrock analysis 

whereby historical land conversion 

trends, as evaluated with satellite 

imagery, are used to determine what 

types of land are affected by agricultural 

land use changes in each country or 

sub-region. 

In the proposed rule we also 

explained several other options to 

determine what types of land will be 

affected by biofuel-induced land use 

changes, such as the use of general 

equilibrium models. EPA specifically 

sought expert peer review input and 

public comment on our approach and 

all of the analytical options for this part 

of the lifecycle assessment. The expert 

peer reviewers agreed that EPA’s 

approach was scientifically justifiable, 

but they highlighted problematic areas 

and suggested important revisions to 

improve our analysis. The public 

comments received on this issue 

expressed a wide range of views 

regarding EPA’s approach. In general, 

the commenters that objected to our 

analytical approach raised similar 

concerns as the peer reviewers, such as 

the need for more data validation and 

uncertainty assessment. As discussed 

below, we made significant 

improvements to our analysis based on 

the recommendations and comments we 

received. Based on the peer reviewers 

agreement that our general approach is 

scientifically justifiable, and in light of 

the significant improvements made, we 

think that our approach represents the 

best available analysis of the types of 

land affected by biofuel-induced land 

use changes. We did consider a range of 

other analytical options, but based on 

all of the information considered and 

the requirements for this analysis, we 

did not find any alternative approaches 

that are superior at this time. As part of 

periodic updates to the lifecycle 

analysis, we will continue to consider 

ways to improve this part of our 

analysis, as well as the merits of 

alternate approaches. 

Domestic: In response to comments 

received, we made two major 

improvements to the FASOM model for 

the final rulemaking. As discussed in 

the NPRM and supported by comments, 

we were able to include the forestry 

sector into the FASOM analysis. Only 

the agricultural sector of FASOM was 

analyzed for the NPRM, due to the fact 

that the forestry sector component was 

undergoing model modifications. For 

this FRM analysis, we were able to use 

the fully integrated forestry and 

agricultural sector model, thereby 

capturing the interaction between 

agricultural land and forests in the U.S. 

In addition, the inclusion of the forestry 

model allows us to explicitly model the 

land use change impacts of the 

competing demand for cellulosic 

ethanol from agricultural sources with 

cellulosic ethanol from logging and mill 

residues. As a result of this 

modification, the FRM analysis includes 

some land use conversion from forests 

into agriculture in the U.S. as a result of 

the increased demand for renewable 

fuels. 

The second major modification we 

made in response to comments was the 

disaggregation of different types of land 

included in FASOM. In the proposed 

rulemaking, the FASOM model 

included three major categories of land: 

cropland, pasture, and acres enrolled in 

the Conservation Reserve Program 

(CRP). Although this categorization 

allowed for a detailed regional analysis 

of land used to grow crops, acres used 

for livestock production were not fully 

captured. We received comments 

requesting a more detailed breakdown 

of land types in order to capture the 

interaction between livestock, pasture, 

and cropland. Therefore, the FASOM 

model now includes rangeland, pasture 

and forest land that can be used for 

grazing. Since we also received 

comments that we should take into 

account the potential for idle land to be 

used for other purposes such as the 

production of cellulosic ethanol, 

FASOM now accounts for the amount of 

land within each category that is either 

idle or used for production. 

These two major modifications to the 

FASOM model now allow us to 

explicitly track land transfers between 

various land categories in the U.S. As a 

result, we can more accurately capture 

the GHG impacts of different types of 

land use changes domestically. More 

detail and results of the FASOM model 

can be found in Section V.B.1.b of the 

preamble. 

International: The proposed rule 

included a detailed description of the 

FAPRI–CARD/Winrock approach used 

to determine the type of land affected 

internationally. This approach uses 

satellite data depicting recent land 

conversion trends in conjunction with 

economic projections from the FAPRI– 

CARD model (an economic model of 

global agricultural markets) to 

determine the type of land converted 

internationally. In the proposed rule we 

described areas of uncertainty in this 

approach, illustrated the uncertainty 

with sensitivity analyses, and discussed 

other potential approaches for this 

analysis. To encourage expert and 

stakeholder feedback, EPA specifically 

invited comment on this issue, held 

public hearings and workshops, and 

sponsored an independent peer-review, 

all of which specifically highlighted this 

part of our analysis for feedback. While 

there were a wide range of views 

expressed in these forums, the feedback 

received by the Agency generally 

supported the FAPRI–CARD/Winrock 

approach as appropriate for this 

analysis. For example, all five experts 

that peer reviewed EPA’s use of satellite 

imagery agreed that it is scientifically 

justifiable to use historic remote sensing 

data in conjunction with agricultural 

sector models to evaluate and project 

land use change emissions associated 

with biofuel production. Additionally, 

the peer reviewers and public 

commenters highlighted problematic 

areas and suggested revisions to 

improve our analysis. Below, we 

describe the key revisions that were 

implemented which have significantly 

improved our analysis based on the 

feedback received. 

FAPRI–CARD/Satellite Data 

Approach: As described above in 

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Section V.B.1.b, the FAPRI–CARD 

model was used to determine the 

amount of land use change in each 

country/region in response to increased 

biofuel production. Because the FAPRI– 

CARD model does not provide 

information about what type of land is 

converted to crop production or pasture, 

we worked with Winrock International 

to evaluate the types of land that would 

be affected internationally. Winrock is a 

global nonprofit organization with years 

of experience in the development and 

application of the IPCC agricultural 

forestry and other land use (AFOLU) 

guidance. For the proposed rule, we 

used satellite data from 2001–2004 to 

provide a breakdown of the types of 

land converted to crop production. A 

key strength of this approach is that 

satellite information is based on 

empirical observations which can be 

verified and statistically tested for 

accuracy. Furthermore, it is reasonable 

to assume that recent land use change 

decisions have been driven largely by 

economics, and, as such, recent patterns 

will continue in the future, absent major 

economic or land use regime shifts 

caused, for example, by changes in 

government policies. 

As discussed above, all five of the 

expert peer reviewers that reviewed our 

use of satellite imagery for this analysis 

agreed that our general approach was 

scientifically justifiable. However, all of 

the peer reviewers qualified that 

statement by describing relevant 

uncertainties and highlighting revisions 

that would improve our analysis. Some 

of the public commenters supported 

EPA’s use of satellite imagery, while 

other expressed concern. In general, 

both sets of public commenters—those 

in favor and opposed—outlined the 

same criticisms and suggestions as the 

expert peer reviewers. Among the many 

valuable suggestions for satellite data 

analysis provided in the expert peer 

reviews and public comments, several 

major recommendations emerged: EPA 

should use the most recent satellite data 

set that covers a period of at least 5 

years; EPA should use higher resolution 

satellite imagery; EPA’s analysis should 

consider a wider range of land 

categories; EPA should improve it’s 

analysis of the interaction between 

cropland, pasture and unused or 

underutilized land; and EPA’s analysis 

should include thorough data validation 

and a full assessment of uncertainty. 

Below, we describe these and other 

recommendations and how we 

addressed each of them to improve our 

analysis. Based on the peer reviewers 

agreement that our general approach is 

scientifically justifiable, and in light of 

the significant improvements made, we 

think that our approach represents the 

best available analysis of the types of 

land affected internationally. 

One of the fundamental 

improvements in this analysis since the 

proposed rule is that it now provides 

global coverage. The analysis for the 

proposed rule included satellite imagery 

for 6 land categories in 314 regions 

across 35 of the most important 

countries, with a weighted average 

applied to the rest of the world. We 

have since completed a global satellite 

data analysis including 9 land categories 

in over 750 distinct regions across 160 

countries. This was an analytical 

improvement that we committed to do 

in the proposed rule. As described 

below, the other major analytical 

enhancements were conducted in 

response to the many technical 

recommendations that we received as 

part of the peer review and public 

comment process. 

All of the expert peer reviewers 

agreed that the version 4 MODIS data 

set used in the proposed rule, which 

covers 2001–2004 with one squarekilometer (1km) spatial resolution, was 

appropriate for our analysis given the 

goals of the study at the time. However, 

almost all of the reviewers strongly 

recommended using a data set covering 

a longer time period. The reviewers 

argued that the 3-year time period from 

2001–2004 was too short to capture the 

often gradual, or sequential, cropland 

expansion that has been observed in the 

tropics. The short time period may also 

show unusual or temporary trends in 

land use caused by short-term policy 

changes or market influences. The 

reviewers suggested that remote sensing 

observations covering 5–10 years would 

be adequate to address these problems. 

The reviewers also recommended that 

remote sensing observations should be 

as recent as possible in order to capture 

current land use change drivers and 

patterns (e.g., political systems, 

infrastructure, and protected areas). To 

use the best available data and respond 

to the peer reviewers’ recommendations, 

the analysis was updated to include the 

most recent MODIS data set, version 5, 

which covers the time period 2001– 

2007. MODIS land cover products are 

not available for years prior to 2001, so 

it is not currently possible to analyze a 

time period longer than six years (i.e., 

2001–2007) with a single, or consistent, 

data set. Thus, consistent with the peer 

review recommendations, we are now 

using the most recent global data set 

which covers at least 5 years. There are 

other advantages to using the version 5 

MODIS data, such as improved spatial 

resolution, and robust data validation, 

which are discussed below. 

There was strong agreement among 

the peer reviewers that higher resolution 

satellite imagery would be an important 

improvement over the 1-km resolution 

data used in the proposed rule analysis. 

Higher spatial resolution is especially 

useful in categorizing highly fragmented 

landscapes. One of the reviewers 

hypothesized that land use change 

driven by biofuel production would 

likely involve large parcels of land, and 

thus 1-km resolution may be sufficient. 

However, all of the reviewers agreed 

that higher resolution data would be 

preferable. A number of the peer 

reviewers specifically said that the 

version 5 MODIS data set, with 500 

meter resolution, would be adequate. 

With four-times higher spatial 

resolution than version 4, the peer 

reviewers anticipated that the 500m 

imagery would classify less area of 

‘‘mixed class’’ land, thus providing a 

more detailed representation of the land 

in that category. Consistent with the 

peer reviewer’s recommendations and 

with our goal to use the best available 

information, our analysis was updated 

with the higher resolution version 5 

MODIS data. 

Related to the issue of spatial 

resolution, the peer review experts were 

asked whether they would recommend 

augmenting our global analysis with 

even higher resolution data for specific 

regions where there is a high degree of 

agricultural land use change. All of the 

peer reviews agreed that this type of 

analysis would be worthwhile. In 

response to this recommendation, we 

analyzed select geographic regions (e.g., 

Brazil, India) with the higher resolution 

30m Landsat data set covering 2000– 

2005. The Landsat data set does not 

currently provide global coverage, thus 

it was not an option for use in the full 

analysis; instead, it was used as a way 

to check/validate the appropriateness of 

the version 5 MODIS imagery. In 

general, the higher resolution data 

showed similar land use change 

patterns as the MODIS data. The results 

of this analysis are discussed further in 

Chapter 2 of the RIA. 

Another issue that we invited 

comments on was the re-classification of 

the MODIS data from 17 land cover 

categories into 6 aggregated categories 

(e.g., open and closed shrubland were 

both re-classified as shrubland). The 

category aggregation was intended to 

remove unnecessary complexity from 

the analysis. All five expert reviewers 

agreed that the methodology used to reclassify land cover categories using 

International Geosphere-Biosphere 

Programme (IGBP) land definitions was 

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170Peer Review Report, Emissions from Land Use 

Change due to Increased Biofuel Production: 

Satellite Imagery and Emissions Factor Analysis, 

July 31, 2009, p. 2. 

sound; however, the reviewers 

recommended inclusion of more than 6 

aggregated land categories. The 

reviewers specifically recommended the 

addition cropland/natural vegetation 

mosaic, permanent wetlands, and barren 

or sparsely vegetated land, all of which 

are now included in our analysis. 

Consistent with these recommendations, 

there are 9 aggregate land categories in 

our revised analysis: barren, cropland, 

excluded (e.g., urban, ice, water bodies), 

forest, grassland, mixed (i.e., cropland/ 

natural vegetation mosaic), savanna, 

shrubland and wetland. These land 

cover categories capture all significant 

types of land affected by agricultural 

land use changes. As described below in 

Section V.B.2.b.iii, we also estimated 

carbon sequestrations for all of these 

land categories. The impact of adding 

these land categories to our analysis is 

discussed further in RIA Chapter 2. 

Another important addition to our 

analysis was consideration of the types 

of land affected by changes in pasture 

area, and the interaction of pasture land 

with cropland. In the proposed rule, we 

made a broad assumption that the total 

land area used for pasture would stay 

the same in each country or region. 

Thus, in the proposed rule, we assumed 

that any crop expansion onto pasture 

would necessarily require an equal 

amount of pasture to be replaced on 

forest or shrubland. We received a large 

number of comments questioning these 

assumptions, and the expert peer 

reviewers encouraged us to develop a 

better representation of the interactions 

between cropland and pasture land. As 

described above in Section V.B.2.6.i, the 

results from the FAPRI–CARD model 

are now used to determine pasture area 

changes in each country or region. In 

regions where we project that pasture 

and crop area both increase, the land 

types affected by pasture expansion are 

determined using the same analysis 

used for crop expansion. This new 

approach accounts for the ability of 

pasture to expand on to previously 

unused, or underutilized, grasslands 

and savanna. In regions where we 

project that crop and pasture area will 

change in opposite directions (e.g., crop 

area increases and pasture decreases) we 

assume that crops will expand onto 

abandoned pasture, and vice versa. Our 

analysis also now accounts for carbon 

sequestration resulting from crop or 

pasture abandonment. We used our 

satellite analysis, which shows the 

dominant ecosystems and land cover 

types in each region, to determine 

which types of ecosystems would grow 

back on abandoned agricultural lands in 

each region. More information about our 

analysis of pasture and abandoned 

agricultural land are provided in RIA 

Chapter 2. 

A sub-set of the expert peer reviewers 

recommended combining the historic 

satellite imagery with other information 

on land use change drivers (e.g., 

transportation infrastructure, poverty 

rates, opportunity costs) as an 

additional means to estimate the types 

of land affected. Consideration of these 

types of information could potentially 

address two conceptual issues with the 

use of satellite imagery in this analysis: 

First, biofuel-induced land use change 

could affect different types of land than 

the generic agricultural expansion 

captured by the historic data; and 

second, future land use change patterns 

may differ from historic patterns. Our 

concerns with the first issue are allayed 

to some degree by one of the peer 

reviewers who observed, ‘‘While it is 

theoretically possible that the changes 

in land use resulting from biofuel 

production occur in ecosystems or 

regions that would not be the ones 

affected by other drivers, this doesn’t 

appear very likely.’’ 170 Furthermore, the 

economic drivers of land use change are 

to a large degree captured by the 

economic models that are used in our 

analysis. For example, the FAPRI–CARD 

model considers economic drivers in its 

projections of where and how much 

crop production will change as a result 

of specifically biofuel-induced changes. 

The second issue is also addressed to 

some degree by the FAPRI–CARD model 

which includes baseline forecasts of 

future international agricultural, 

economic and demographic conditions. 

Furthermore, as discussed above, we 

used the most recently available satellite 

data sets in order to capture the most 

current land use change drivers. Thus, 

while we think that these issues are 

currently addressed to a scientifically 

justifiable degree for the purposes of 

this analysis, we recognize that these are 

areas for future investigation, and we 

have tried to capture the uncertainty 

from these factors in uncertainty and 

sensitivity analyses as described below. 

While EPA has made significant 

improvements to the methodology in 

response to peer review comments, the 

use of satellite data for forecasting land 

use changes is a key area of uncertainty 

in the analysis. To facilitate substantive 

comments on the impact of uncertainty 

in international land use changes, and 

how to address the uncertainty, the 

proposed rule highlighted areas of 

uncertainty and included multiple 

sensitivity analyses. For example, we 

presented a range of lifecycle results 

assuming at the high-end that all land 

conversion caused deforestation and at 

the low-end that biofuels would cause 

no deforestation. Further, EPA sought 

input on this issue in public hearings 

and workshops, and expert feedback 

through the independent peer review. 

The feedback we received, both from 

experts and the public, overwhelmingly 

supported a more systematic analysis of 

the uncertainty in using satellite data to 

project biofuel-induced land use change 

patterns. Additionally, commenters 

recommended more data validation, 

especially regarding the satellite 

imagery. To respond to these comments, 

we incorporated satellite imagery 

validation and conducted a Monte Carlo 

analysis of the MODIS satellite data 

using assessments provided by NASA to 

quantitatively evaluate the uncertainty 

in our application of satellite imagery. 

One benefit of using the MODIS data 

set is that it is routinely and extensively 

validated by NASA’s MODIS land 

validation team. NASA uses several 

validation techniques for quality 

assurance and to develop uncertainty 

information for its products. NASA’s 

primary validation technique includes 

comparing the satellite classifications to 

data collected through field and aircraft 

surveys, and other satellite data sensors. 

The accuracy of the version 5 MODIS 

land cover product was assessed over a 

significant set of international locations, 

including roughly 1,900 sample site 

clusters covering close to 150 million 

square kilometers. The results of these 

validation efforts are summarized in a 

‘‘confusion matrix’’ which compares the 

satellite’s land classifications with the 

actual land types observed on the 

ground. We used this information to 

assess the accuracy and systematic 

biases in the published MODIS data. In 

general, the validation process found 

that MODIS version 5 was quite 

accurate at distinguishing forest from 

cropland or grassland. However, the 

satellite was more likely; for example, to 

confuse savanna and shrubland because 

these land types can look quite similar 

from space. 

Using the data validation information 

from NASA about which types of land 

MODIS tends to confuse which each 

other, our Monte Carlo analysis was able 

to account for systematic 

misclassifications in the MODIS data 

set. Therefore, part of the Monte Carlo 

analysis can be viewed as a way to 

correct and reduce the inaccuracies in 

the MODIS data. After this correction is 

performed, the uncertainty in the 

satellite data is no longer solely a 

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function of the accuracy of the satellite. 

Instead, the sizes of the standard errors 

for each classification are also a 

function of the sample sizes in the data 

validation exercise. For example, if 

NASA validated every pixel on Earth, 

the corrected data set would be 100% 

accurate, even if the original satellite 

data were only 50% accurate. Similarly, 

although NASA reports that the overall 

accuracy of the MODIS version 5 land 

cover data set is approximately 75%, the 

standard errors after the Monte Carlo 

procedure are less than 5% for each 

aggregate land category. These standard 

errors were used to quantify the 

uncertainty added by the satellite data 

used in our analysis. This procedure 

and the results are described in more 

detail in Chapter 2 of the RIA. 

It should be noted that our assessment 

of satellite data uncertainty did not try 

to fully quantify the uncertainty of using 

historical data to make future 

projections about the types of land that 

would be affected internationally. As 

noted above, we think it is reasonable to 

assume that in general, recent land use 

change patterns will continue in the 

future absent major economic or land 

use regime shifts caused, for example, 

by changes in government policies. 

Thus, our uncertainty assessment 

provides a reasonable estimate of the 

variability in land use change patterns 

absent any fundamental shifts in the 

factors that affect land use patterns. 

However, our uncertainty assessment 

does not attempt to fully quantify the 

probability of major shifts in land use 

regimes, such as the implementation of 

effective international policies to curb 

deforestation. 

Some of the peer reviewers 

recommended a satellite imagery 

analysis approach known as change 

detection, instead of the ‘‘differencing’’ 

approach used in the Winrock analysis. 

However, there was disagreement 

among the peer reviewers on this point, 

with one peer reviewer saying that 

thematic differencing between land 

cover maps generated for two specific 

dates, as conducted in this study, 

provides the best approach for detecting 

and analyzing land use pattern changes 

globally. In general terms, the 

differencing method employed by 

Winrock compared global land cover 

maps from 2001 and 2007 to evaluate 

the pattern of land use change during 

this period. Thus, the differencing 

method shows all of the land that 

changed categories, as well as all of the 

land that stayed the same over this 

period. For change detection, instead of 

using comprehensive land cover maps, 

the data set only shows land categories 

that changed. One advantage of change 

detection is that it is better suited to 

capture the sequential nature of land 

use changes, e.g., a forest could be 

converted to savanna, then grassland 

and then cropland. The differencing 

method that we employed lends itself 

more readily to comprehensive global 

analysis, data validation, and 

uncertainty assessment. Given the 

timeframe and priorities for our 

analysis, we think that the differencing 

method provides the best approach 

available at this time. However, we will 

continue to consider alternative 

analytical techniques, such as change 

detection, for use as part of periodic 

updates to this analysis. 

Some of the peer reviewers 

recommended additional alternative 

technical approaches for satellite data 

and land use change analysis. For 

example, some of the reviewers 

recommended the use of satellite 

imagery to identify specific crop-types 

and rotations, and one reviewer 

suggested that EPA develop a new 

interactive spatial model. The Summary 

and Analysis of Comments document 

includes discussion of these and other 

technical comments and 

recommendations that are not covered 

here. 

iii. GHG Emissions Associated With 

Conversion 

(1) Domestic Emissions 

GHG emissions impacts due to 

domestic land use change are based on 

GHG emissions the FASOM model 

generates in association with land type 

conversions projected in the model. In 

the proposed rule analysis, estimates of 

land use change emissions were limited 

to conversion between different types of 

agricultural land (e.g., cropland, fallow 

cropland, pasture). The analysis did not 

allow for the addition of new domestic 

agricultural land. 

In response to feedback EPA received 

during the public comment period and 

based on commitments EPA made in the 

NPRM, several changes and additions 

have augmented the analysis of 

domestic land use change GHG 

emissions since the proposed rule 

analysis. The addition of the forest land 

types and the interaction between 

cropland, pastureland, forestland, and 

developed land to the FASOM model 

provides a more complete emissions 

profile due to domestic land use change 

(see Section V.B.4.b.ii). We have 

updated soil carbon accounting based 

on new available data. Lastly, the 

methodology now captures GHG 

emission streams over time associated 

with discrete land use changes. 

For agricultural soils, FASOM models 

GHG emissions associated with changes 

in crop production acreage and with 

changes in crop type produced. FASOM 

generates soil carbon factors for 

cropland and pasture according to IPCC 

Agriculture, Forestry, and Other Land 

Use (AFOLU) Guidelines. In the 

proposed rule, we committed to 

updating FASOM soil carbon 

accounting for agriculture. Per our 

commitment, we have updated FASOM 

soil carbon accounting for cropland and 

pasture using the latest DAYCENT 

modeling from Colorado State 

University. 

In the proposed rule, EPA committed 

to incorporate the forestry sector and the 

GHG emission impacts due to the land 

use interactions between the domestic 

agricultural and forestry sectors into the 

FASOM analysis. We received comment 

supporting the incorporation of the 

forestry sector. By including the forestry 

sector in the FASOM domestic model 

(see Section V.B.4.b.ii), we have 

incorporated GHG emission impacts 

associated with change in forest aboveground and below-ground biomass, 

forest soil carbon stocks, forest 

management practices (e.g. timber 

harvest cycles), and forest products and 

product emission streams over time. 

Forest carbon accounting in FASOM is 

based on the FORCARB developed by 

the U.S. Forest Service and on data 

derived largely from the U.S. Forest 

Service RPA modeling system. 

With the changes to FASOM 

discussed above, we also updated the 

final calculation method of domestic 

land use change GHG emissions to 

account for FASOM’s cumulative 

assessment of GHG emissions and the 

continuous (rather than discrete) nature 

of soil carbon and forest product 

emissions. For each category of 

agricultural and forestry land use 

emissions, we calculated the mean 

cumulative emissions from the initial 

year of FASOM modeling (2000) to 

2022. Changes in agricultural and forest 

soil carbon and forest products have a 

stream of GHG emissions associated 

with them in addition to the initial 

pulse associate with a discrete instance 

or year of land use change. For each of 

these categories FASOM calculates the 

emissions over time associated with the 

mean land use change over a year. We 

included in total domestic land use 

change emissions the annualized 

emission streams associated with all 

agricultural soil, forest soil, and forest 

product changes included in the mean 

cumulative emissions (2000–2022) for 

30 years after 2022. 

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171 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. 

(2) International Emissions 

Based on input from the expert peer 

review and public comments, we 

incorporated new data sources and 

made other methodological 

improvements in our estimates of GHG 

emissions from international land 

conversions. Some of these 

modifications increased land use change 

GHG emissions compared to the NPRM, 

such as the consideration of carbon 

releases from drained peat soils. Other 

modifications, such as more 

conservative foregone sequestration 

estimates, tended to decrease land use 

change GHG emissions. For example, 

our estimates of emissions per acre of 

deforestation in Brazil tended to 

increase because of improved data on 

forest biomass carbon stocks in that 

region. However, for example, our 

deforestation estimates in China 

decreased, in part because of new data 

on foregone forest sequestration. The net 

effect of the revisions varied depending 

on the location and types of land use 

changes in each biofuel scenario. The 

major changes to this part of our 

analysis, including a quantitative 

uncertainty assessment, are discussed in 

this section. 

To determine the GHG emissions 

impacts of international land use 

changes, we followed the 2006 IPCC 

Agriculture, Forestry, and Other Land 

Use (AFOLU) Guidelines.171 We worked 

with Winrock, which has years of 

experience developing and 

implementing the IPCC guidelines, to 

estimate land conversion emissions 

factors, including changes in biomass 

carbon stocks, soil carbon stocks, nonCO2 emissions from clearing with fire 

and foregone forest sequestration (i.e., 

lost future growth in vegetation and soil 

carbon). In addition to seeking comment 

on our analysis in the proposed rule, 

EPA organized public hearings and 

workshops, and an expert peer review 

specifically eliciting feedback on this 

part of the lifecycle analysis. All of the 

expert peer reviewers generally felt that 

our analysis followed IPCC guidelines 

and was scientifically justifiable; 

however, they did make several 

suggestions of new data sources and 

recommended areas that could benefit 

from additional clarification. Based on 

the detailed comments we received, we 

worked with Winrock to make a number 

of important revisions, which have 

significantly improved this part of our 

analysis. 

The proposed rule analysis included 

land conversion emissions factors for 5 

land categories in 314 regions across 35 

of the most important countries, with a 

weighted average applied to the rest of 

the world. We augmented this analysis 

to provide global coverage, including 

emissions factors for 10 land categories 

in over 750 regions across 160 countries. 

Other significant improvements 

included incorporation of new data 

sources, emissions factors for peat soil 

drainage, sequestration factors for 

abandoned agricultural land, and a full 

uncertainty assessment considering 

every data input. 

Another significant improvement in 

our analysis was incorporation of higher 

resolution soil carbon data. One of the 

expert peer reviewers commented that 

the weakest part of EPA’s international 

emissions factor analysis for the 

proposed rule was the global soil carbon 

map that was used because of its coarse 

resolution. To address this comment, we 

incorporated the new Harmonized 

World Soil Database, released in March 

2009. This dataset provides one square 

kilometer spatial resolution, which is a 

major improvement compared to the 

proposed rule analysis. This dataset also 

includes an updated soil map of China 

that the peer reviewers recommended. 

Using this updated soil carbon data, the 

change in soil carbon following 

conversion of natural land to annual 

crop production was estimated 

following the 2006 IPCC guidelines. 

When land is plowed in preparation for 

crop production the soil loses carbon 

over time until a new equilibrium is 

established. To calculate soil carbon 

emissions the IPCC approach considers 

both tillage practices and agricultural 

inputs. Some of the peer reviewers 

expressed concern with our annual soil 

carbon change estimates, which 

assumed a constant rate of change over 

20 years. However, for analytical 

timeframes greater than 20 years, such 

as used in our lifecycle analysis, the 

peer reviewers agreed that the our 

approach was scientifically justifiable. 

More information about soil carbon 

stock estimates is available in Chapter 2 

of the RIA. 

The expert peer reviewers generally 

agreed that EPA’s estimate of forest 

carbon stocks followed IPCC guidelines 

and used the best available data. They 

did, however, recommend that the 

analysis could be updated with 

improved forest biomass maps as they 

become available. Consistent with these 

suggestions, we incorporated improved 

forest biomass maps for regions where 

they were available. More information 

about the specific data sources used is 

available in RIA Chapter 2. 

In addition to estimating forest carbon 

stocks for each region, EPA’s analysis 

also includes estimates of annual forest 

carbon uptake. When a forest is cleared 

the future carbon uptake from the forest 

is lost; this is known as foregone forest 

sequestration. In the proposed rule, to 

estimate annual forgone forest 

sequestration, we used IPCC default 

data for the growth rates of forests 

greater than 20 years old. The expert 

peer reviewers noted that these 

estimates could be refined with more 

detailed information from the scientific 

literature. Many of the public 

commenters were also concerned that 

EPA’s approach overestimated foregone 

sequestration because it did not 

adequately account for natural 

disturbances, such as fires and disease. 

To address these comments, our 

analysis has been updated with peer 

reviewed studies of long-term growth 

rates for both tropical and temperate 

forests. These estimates are based on 

long-term records (i.e., monitoring 

stations in old-growth forests for the 

tropics and multi-decadal inventory 

comparisons for the temperate regions) 

and reflect all losses/gains over time. 

These studies show that the old-growth 

forests in the tropics that many once 

assumed to be in ‘‘steady state’’ (i.e., 

carbon gains equal losses) are in fact 

still gaining carbon. In summary, our 

analysis now includes more 

conservative foregone forest 

sequestration estimates that account for 

natural gains and losses over time. More 

information about these estimates is 

provided in RIA Chapter 2. 

Another consideration when 

estimating GHG emissions resulting 

from deforestation is that some of the 

wood from the cleared forest can be 

harvested and used in wooden products, 

such as a table, that retain biogenic 

carbon for a long period of time. Some 

commenters argued that consideration 

of the use of harvested wood in 

products would decrease land use 

change emissions and reduce the 

impacts of biofuel production. As part 

of analysis for the proposed rule, we 

investigated the share of cleared forest 

biomass that is typically used in 

harvested wood products (HWP). 

However, we did not account for this 

factor in the proposed rule after it was 

determined that HWP would have a 

very small impact on the magnitude of 

land use change emissions. A number of 

commenters expressed concern that we 

did not account for HWP, and they 

argued that HWP would be more 

significant than we had determined. 

However, in response to specific 

questions on this topic, all of the expert 

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172 2006 IPCC Guidelines for National Greenhouse 

Gas Inventories, Volume 1: General Guidance and 

Reporting, Chapter 3: Uncertainties, available at 

http://www.ipcc-nggip.iges.or.jp/public/2006gl/ 

vol1.html. 

peer reviewers agreed that EPA had 

properly accounted for HWP and other 

factors (e.g., land filling) that could 

prevent or delay emissions from land 

clearing. One of the peer reviewers 

noted that forests converted to 

croplands are generally driven by 

interests unrelated to timber, and thus 

the trees are simply burned and 

exceptions are probably of minor 

importance. To study this issue further, 

we looked at FAO timber volume 

estimates for 111 developing countries, 

and published literature on the share of 

harvested timber used in wood products 

and the oxidation period for wood 

products, such as wood-based panels 

and other industrial roundwood. 

Consistent with the peer reviewers’ 

statements, our analysis concluded that 

even in countries with high rates of 

harvested timber utilization, such as 

Indonesia, a very small share of 

harvested forest biomass would be 

sequestered in HWP for longer than 30 

years. The details of our HWP analysis 

are discussed further in RIA Chapter 2. 

This is an area for further work, but 

based on our analysis, and the feedback 

from expert commenters, we do not 

expect that consideration of HWP would 

have a significant impact on the 

magnitude of GHG emissions from 

international deforestation in our 

analysis. Furthermore, the range of 

outcomes from consideration of HWP is 

indirectly captured in our assessment of 

forest carbon stock uncertainty, which is 

described below. 

The land conversion emissions 

estimates used in our analysis consider 

the carbon stored in crop biomass. In 

the proposed rule, we used the IPCC 

default biomass sequestration factor of 5 

metric tons of carbon per hectare for 

annual crops, and applied this value to 

all crops globally. The final rule 

analysis now distinguishes between 

annual and perennial crops, with 

separate sequestration estimates for 

sugarcane and oil palm determined from 

the scientific literature. The peer 

reviewers suggested approaches to 

refine our biomass carbon estimates for 

different types of annual crops, e.g., for 

corn versus soybeans. However, we 

determined that adding crop-specific 

biomass sequestration estimates would 

have a very small impact on our results, 

because in general annual cropland 

carbon stocks range only from 3 to 7 

tons per hectare and the average would 

likely be very close to the IPCC default 

factor currently applied. This is an area 

for future work, but we are confident 

that it would have very small impact. 

Furthermore, the range of potential 

outcomes is captured in the uncertainty 

analysis described below. 

Other issues that were covered in the 

expert peer review and public 

comments included EPA’s carbon stock 

estimates for grasslands, savanna, 

shrublands and wetlands, and our 

assumptions about which regions use 

fire to clear land prior to agricultural 

expansion. There is less data available 

for these parameters relative to some of 

the other issues discussed above, e.g., 

forest carbon stocks. Therefore, we 

worked to use expert judgment to derive 

global estimates for these parameters. In 

general, the peer reviewers thought that 

EPA’s approach to these issues was 

reasonable and scientifically justifiable. 

Some of the peer reviewers 

recommended more resource-intensive 

techniques to refine some of our 

estimates. For example, regarding the 

issue of clearing with fire, one of the 

peer reviewers suggested that we could 

review fire events in the historical 

satellite data to estimate where fire is 

most commonly used. We carefully 

considered these suggestions, but did 

not make significant revisions to our 

analysis of these issues. Our review 

concluded that given the timeframe and 

goals of our analysis, the approach used 

in the proposed rule was most 

appropriate. We recognize that these are 

areas for future work, and we will 

consider new data as part of periodic 

updates. Furthermore, our uncertainty 

analysis, described below, considered 

the fact that these are areas where less 

data is available. 

Other improvements in our analysis 

included the addition of emissions from 

peat soil drainage in Indonesia and 

Malaysia, and sequestration factors for 

abandoned agricultural land. Consistent 

with the expert peer reviewers’ 

recommendations, we considered a 

number of recent studies to estimate 

average carbon emissions when peat 

soils are drained in Indonesia and 

Malaysia (the countries where peat soil 

is sometimes drained in preparation for 

new agricultural production). To 

estimate annual sequestration on 

abandoned agricultural land we used 

our foregone sequestration estimates 

and other data from IPCC. More 

information about these estimates is 

available in RIA Chapter 2. 

As discussed in Section V.A.2, the 

uncertainty of land use change 

emissions is an important consideration 

in EPA’s threshold determinations as 

part of this rulemaking. We conducted 

a full assessment of the uncertainty in 

international land use change emissions 

factors consistent with 2006 IPCC 

guidance.172 This analysis considers the 

uncertainty in the every parameter used 

in our emissions factor estimates. 

Standard deviations for each parameter 

were estimated based on the quality and 

quantity of the underlying data. For 

example, in our analysis the standard 

errors (as a percent of the mean) tend to 

be smallest for forest carbon stocks in 

Brazil, because a large amount of high 

quality/resolution data was considered 

to estimate that parameter. Standard 

errors are largest for parameters that 

were estimated by scaling other data, or 

applying IPCC defaults, e.g., savanna 

carbon stocks in Yemen. More detail 

about our estimate of parameter 

uncertainty is available in RIA Chapter 

2. 

Following IPCC guidance, the 

uncertainties in the individual 

parameters of an emission factor can be 

combined using either error propagation 

methods (IPCC Tier 1) or Monte Carlo 

simulation (IPCC Tier 2). We used the 

Tier 2 Monte Carlo simulation method 

for this analysis. Monte Carlo is a 

method for analyzing uncertainty 

propagation by randomly sampling from 

the probability distributions of model 

parameters, calculating the results of the 

model from each sample, and 

characterizing the probability of the 

outcomes. An important consideration 

for Monte Carlo analysis is the treatment 

of correlation, or dependencies, among 

parameter errors. Strong positive 

correlation among parameter errors will 

result in greater overall uncertainty. As 

a simplified example, if the errors in our 

forest carbon stock estimates are 

positively correlated, then if we are 

overestimating forest carbon in one 

region we are likely overestimating 

forest carbon in every region. We 

worked with Winrock to estimate the 

degree of correlation among variables— 

both the correlation of one variable 

across space as well as the correlation 

of one variable to any others used in the 

analysis. This was done by considering 

dependencies in the underlying data 

used to estimate each parameter. For 

example, our forest carbon stock 

estimates are correlated across Russia 

because they were derived from one 

biomass map covering Russia. However, 

forest carbon stocks in Russia are not 

correlated with China, because they 

were derived from separate biomass 

maps. This partial correlation approach 

tended to reduce the overall uncertainty 

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173The 95% confidence range indicates there is 

no more than a 5% chance the actual value is likely 

to be outside this range. 

associated with GHG emissions factor 

data. 

The information about the uncertainty 

in each parameter and the degree of 

correlation across parameters was 

utilized in Monte Carlo analysis to 

determine the overall uncertainty in our 

emissions factor estimates. We used the 

Monte Carlo simulation to combine the 

emissions factor and satellite data 

uncertainty for every biofuel scenario 

analyzed. Uncertainty ranges varied 

across scenarios depending on the types 

and locations of land use changes. For 

example, based on the sources of 

uncertainty analyzed, the 95% 

confidence range for land use change 

emissions (as a percent of the mean) was 

¥27% to +32% for base yield corn 

ethanol in 2022, and ¥56% to +76% for 

base yield soy biodiesel in 2022.173

More details about this uncertainty 

analysis are provided in RIA Chapter 2. 

iv. Timeframe of Emission Analysis 

Based on input from the expert peer 

review and public comments, EPA has 

chosen to analyze lifecycle GHG 

emissions using a 30 year time period, 

over which emissions are not 

discounted, i.e., a zero discount rate is 

applied to future emissions. The input 

we received and the reasons for our use 

of this approach are described in this 

section. 

As required by EISA, EPA must 

determine whether biofuels reduce GHG 

emissions by the required percentage 

relative to the 2005 petroleum baseline. 

In the proposal the Agency discussed a 

number of accounting methods for 

capturing the full stream of GHG 

emissions and benefits over time. When 

accounting for the time profile of 

lifecycle GHG emissions, two important 

assumptions to consider are: (1) The 

time period considered and (2) the 

discount rate (which could be zero) 

applied to future emissions streams. At 

the time of proposal, EPA requested 

public comment on the choice of time 

frames and discounting approaches for 

purposes of estimating lifecycle GHG 

emissions. Also, as part of the peer 

review process, EPA requested comment 

from expert peer reviewers on the 

choice of the appropriate time frames 

and discount rates for the RFS2 

analysis. Below is a summary of the 

comments we received on these issues 

and how we address them in our 

analytical approach. 

Time Period for Analysis: In the 

proposed rule, EPA highlighted two 

time periods, 30 years and 100 years, for 

consideration in our lifecycle analysis. 

The Agency discussed the relative 

advantages of these, and other, time 

periods. In addition, the Agency sought 

comment on whether it is appropriate to 

split the time period for GHG emissions 

assessment based upon how long the 

biofuel would be produced (i.e., the 

‘‘project’’ period) and the time period for 

which there would likely be GHG 

emissions changes (i.e., the ‘‘impact’’ 

period). To encourage expert and public 

comments on these issues, EPA held 

public hearings and workshops and 

sponsored an expert peer review 

specifically focused on this topic. The 

expert input and comments that we 

received included many valuable points 

which guided our decisions about 

which time frame should be the focus of 

our analysis. Below we summarize some 

of the key arguments made by the peer 

reviewers and commenters, and how 

these arguments factored into our choice 

of analytical approach. 

The expert peer reviewers discussed a 

number of justifiable time periods 

ranging from 13 to 100 years for 

assessing lifecycle GHG emissions. A 

subset of the reviewers said that EPA’s 

analysis should be restricted to 2010– 

2022 based on the years specified in 

EISA, because these reviewers argued 

that EPA should not assume that biofuel 

production will continue beyond 2022 

at the RFS2 levels. The reviewers said 

that longer time frames, such as 100 

years, were only appropriate if the 

Agency used positive discount rates to 

value future emissions. Almost all of the 

peer reviewers said that a time frame of 

20 to 30 years would be a reasonable 

timeframe for assessing lifecycle GHG 

emissions. They gave several reasons for 

why a short time period is appropriate: 

This time frame is the average life of a 

typical biofuel production facility; 

future emissions are less certain and 

more difficult to value, so the analysis 

should be confined insofar as possible 

to the foreseeable future; and a nearterm time horizon is consistent with the 

latest climate science that indicates that 

relatively deep reductions of heattrapping gasses are needed to avoid 

catastrophic changes due to a warming 

climate. The peer reviewers suggested 

that while there is no unassailable basis 

for choosing a precise timeframe the 

expected average lifetime of a biofuel 

production facility is the ‘‘most sensible 

anchor’’ for the choice of a timeframe. 

There was support in the public 

comments for both the 30 year and 100 

year time frames. A number of public 

commenters supported the use of a 30 

year time period, or less, and made 

arguments similar to those of the expert 

peer reviewers. They argued that shorter 

time periods give more weight to the 

known, more immediate, effects of 

biofuel production and that use of 

longer time periods gives more weight 

to activities that are much more 

uncertain, and that the 100 year 

timeframe is inappropriate because it is 

much longer than the life of individual 

biofuel plants. 

On the issue of whether to split the 

time period for GHG emissions analysis 

into the ‘‘project and ‘‘impact’’ periods, 

there was little support for the use of a 

split time frame for evaluating lifecycle 

GHG emissions by the peer reviewers or 

in the public comments. The peer 

reviewers thought that it would be 

difficult to find a scientific basis for 

determining the length of the two 

different time horizons. Also, splitting 

the time horizon would necessitate 

consideration of the land use changes 

following the end of the project time 

horizon such as land reversion. 

However, the majority of expert peer 

reviewers did not think it was 

appropriate to attribute potential land 

reversions, following the project time 

frame, to a biofuel’s lifecycle. 

Based upon the comments discussed 

above, EPA has decided to use a 30 year 

frame for assessing the lifecycle GHG 

emissions. There are several reasons 

why the 30 year time frame was chosen. 

The full life of a typical biofuel plant 

seems reasonable as a basis for the 

timeframe for assessing the GHG 

emissions impacts of a biofuel, because 

it provides a guideline for how long we 

can expect biofuels to be produced from 

a particular entity using a specific 

processing technology. Also, the 30 year 

time frame focuses on GHG emissions 

impacts that are more near term and, 

hence, more certain. We also 

determined that longer time periods 

were less appropriate because the peer 

reviewers recommended that they 

should only be used in conjunction with 

positive discount rates; but, for the 

reasons discussed below, we are using 

a zero discount rate in our analysis. In 

addition, the 30 year time frame is 

consistent with responses of the peer 

reviewers that EPA should not split the 

time periods for analysis, or include 

potential land reversions following the 

project time period in the biofuel 

lifecycle. 

Discounting: In the RFS2 Proposal, 

EPA highlighted two principal options 

for discounting the lifecycle GHG 

emission streams from biofuels over 

time. The first involved the use of a 2% 

discount rate using the 100 year time 

horizon for assessing lifecycle GHG 

emissions streams. The second option 

involved using a 30 year time horizon 

for examining lifecycle GHG emissions 

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impacts. In the 30 year case, each GHG 

emission is treated equally through 

time, which implicitly assumes a zero 

discount rate to GHG lifecycle emissions 

streams. The issue of whether to 

discount lifecycle GHG emissions was 

raised as a topic that EPA sought 

comment on in both the peer review 

process and in public comments. 

EPA received numerous comments on 

the issue of whether the Agency should 

be discounting lifecycle GHG emissions 

through time. While many of peer 

reviewers thought that current GHG 

emissions reductions should be more 

strongly weighted than future 

reductions, the peer reviewers were in 

general agreement that a discount rate 

should only be applied to a monetary 

unit, rather than a physical unit, such as 

GHG emissions. Public commenters 

suggested that discounting is an 

essential part of long term cost benefit 

analysis but it is not necessary in the 

context of the physical aggregation of 

lifecycle GHG emissions called for in 

the EISA. Further, public commenters 

expressed concerns that any discount 

rate chosen by the Agency would be 

based upon relatively arbitrary criteria. 

After considering the comments on 

discounting from the peer review and 

the public, EPA has decided not to 

discount (i.e., use a 0% discount rate) 

GHG emissions due to the many issues 

associated with applying an economic 

concept to a physical parameter. First, it 

is unclear whether EISA intended 

lifecycle GHG emissions to be converted 

into a metric whose underpinnings rest 

on principals of economic valuation. A 

more literal interpretation of EISA is 

that EPA should consider only physical 

GHG emissions. Second, even if the 

principle of tying GHG emissions to 

economic valuation approaches were to 

be accepted, there would still be the 

problem that there is a lack of consensus 

in the scientific community about the 

best way to translate GHG emissions 

into a proxy for economic damages. 

Also, there is a lack of consensus as to 

the appropriate discount rate to apply to 

GHG lifecycle emissions streams 

through time. Finally, since EPA has 

decided to base threshold assessments 

of lifecycle GHG emissions on a 30 year 

time frame, the issue of whether to 

discount GHG emissions is not as 

significant as if the EPA had chosen the 

100 year time frame to assess GHG 

emissions impacts. More discussion of 

discount rates and their impact on the 

lifecycle results can be found in Chapter 

2 of the RIA. 

v. GTAP and Other Models 

Although we have used the partial 

equilibrium (PE) models FASOM and 

FAPRI–CARD as the primary tools for 

evaluating whether individual biofuels 

meet the GHG thresholds, as part of the 

peer review process, we explicitly 

requested input on whether general 

equilibrium (GE) models should be 

used. None of the comments 

recommended using a GE model as the 

sole tool for estimating GHG emissions, 

given the limited details on the 

agricultural sector contained in most GE 

models. The peer reviewers generally 

supported the use of the FASOM and 

FAPRI–CARD models for our GHG 

analysis given the need for additional 

detail offered in the PE models, however 

several comments suggested 

incorporating GE models into the 

analysis. 

Given these recommendations, we 

opted to use the GTAP model to inform 

the range of potential GHG emissions 

associated with land use change 

resulting from an increase in renewable 

fuels. As discussed in the NPRM, there 

are several advantages to using GTAP. 

As a general equilibrium model, GTAP 

captures the interaction between 

different markets (e.g., agriculture and 

energy) in different regions. It is 

distinctive in estimating the complex 

international land use change through 

trade linkages. In addition, GTAP 

explicitly models land-use conversion 

decisions, as well as land management 

intensification. 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 types of land cover 

within each Agro-Ecological Zone. 

Like the peer reviewers, we felt that 

some of the drawbacks of the GTAP 

model prevent us from using GTAP as 

the sole model for estimating GHG 

emissions from biofuels. As discussed 

in the NPRM, GTAP does not utilize 

unmanaged cropland, nor is it able to 

capture the long-run baseline issues 

(e.g., the state of the economy in 2022). 

For our analysis, the GTAP model was 

most valuable for providing another 

estimate of the quantity and type of land 

conversion resulting from an increase in 

corn ethanol and biodiesel given the 

competition for land and other inputs 

from other sectors of the economy. 

These results were therefore considered 

as part of the weight of evidence when 

determining whether corn ethanol or 

biodiesel met the GHG thresholds. 

The quantity of total acres converted 

to crop land projected by FAPRI–CARD 

were within the range of values 

projected by GTAP when normalized on 

a per BTU basis, although there were 

differences in the regional distribution 

of these changes. The land use changes 

projected by GTAP were smaller than 

land use changes predicted by FAPRI– 

CARD, which is primarily due to several 

important differences in the modeling 

frameworks. First, the GTAP model 

incorporates a more optimistic view of 

intensification options by which higher 

prices induced by renewable fuels 

results in higher yields, not just for 

corn, but also for other displaced crops. 

Second, the demands for other uses of 

land are explicitly captured in GTAP. 

Therefore, when land is withdrawn 

from these uses, the prices of these 

products rise and provide a certain 

amount of ‘‘push-back’’ on the 

conversion of land to crops from pasture 

or forest. Third, none of the peerreviewed versions of GTAP currently 

contain unmanaged cropland, thereby 

omitting additional sources of land. 

Finally, the GTAP model also predicted 

larger increases in forest conversion 

than the FAPRI–CARD/Winrock 

analysis, in part because the GTAP 

model includes only three types of land 

(i.e., crops, pasture, forest). As 

discussed in the FAPRI–CARD/Winrock 

section, there are many other categories 

of land which may be converted to 

pasture and crop land. 

As with all economic models, GTAP 

results are sensitive to certain key 

parameter values. One advantage of this 

framework is that it offers a readily 

usable approach to Systematic 

Sensitivity Analysis (SSA) using 

efficient sampling techniques. We have 

exploited this tool in order to develop 

a set of 95% confidence intervals 

around the projected land use changes. 

Several key parameters were identified 

that have a significant impact on the 

land use change projections, including 

the yield elasticity (i.e., the change in 

yield that results from a change in that 

commodity’s price), the elasticity of 

transformation of land supply (i.e., the 

measure of how easily land can be 

converted between forest, pasture, and 

crop land), and the elasticity of 

transformation of crop land (i.e., the 

measure of how easily land can be 

converted between crops). Although the 

confidence intervals are relatively large, 

in most cases the ranges do not bracket 

zero. Therefore, we conclude that the 

impacts of the corn ethanol and soybean 

biodiesel mandates on land use change 

are statistically significant. These 

confidence intervals also bracket the 

FAPRI–CARD results. Additional 

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174 Davis, Ryan. November 2009. Technoeconomic analysis of microalgae-derived biofuel 

production. National Renewable Energy Laboratory 

(NREL) 

175Tao, Ling and Aden, Andy. November 2008. 

Techno-economic Modeling to Support the EPA 

Notice of Proposed Rulemaking (NOPR). National 

Renewable Energy Laboratory (NREL). 

176Aden, Andy. September 2009. Mixed Alcohols 

from Woody Biomass—2010, 2015, 2022. National 

Renewable Energy Laboratory (NREL). 

177 Davis, Ryan. August 2009. Techno-economic 

analysis of current technology for Fischer-Tropsch 

fuels. National Renewable Energy Laboratory 

(NREL). 

information on the GTAP results is 

discussed in RIA Chapter 2. 

c. Feedstock Transport 

To estimate the GHG impacts of 

transporting corn from the field to an 

ethanol production facility and 

transporting the co-product DDGS from 

the ethanol facility to the point of use, 

we used the method described in the 

proposed rule. We also did not change 

our estimates for the transport of 

cellulosic biofuel feedstock and 

biomass-based diesel feedstock. 

For sugarcane transport, we received 

the comment that the GREET defaults 

used to estimate the energy 

consumption and associated GHG 

emissions do not all reflect current 

industry practices. To address this 

concern, we reviewed the current 

literature on sugarcane transport and 

updated our assumptions on the 

distance sugarcane travels by truck from 

the field to ethanol production facilities 

as well as the payload and fuel economy 

of those trucks. We incorporated these 

revised inputs into an updated version 

of the GREET model (Version 1.8c) in 

order to estimate the GHG impacts of 

sugarcane transport. More details on 

these updates can be found in Chapter 

2 of the RIA. 

In the proposal, we discussed 

updating our analysis to incorporate the 

results of a recent study detailing 

biofuel production locations and modes 

of transport. This study, conducted by 

Oak Ridge National Laboratory, 

modeled the transportation of ethanol 

from production or import facilities to 

petroleum blending terminals. Since the 

study did not explicitly address the 

transport of biofuel feedstocks, we did 

not implement the results for this part 

of the analysis. However, we did 

incorporate the results into our 

assessment of the GHG impacts of fuel 

transportation. We will continue to 

examine whether our feedstock 

transport estimates could be 

significantly improved by implementing 

more detailed information on the 

location of biofuel production facilities. 

We also discussed updating the 

transportation modes and distances 

assumed for corn and DDGS to account 

for the secondary or indirect 

transportation impacts. For example, 

decreases in exports will reduce overall 

domestic agricultural commodity 

transport and emissions but will 

increase transportation of commodities 

internationally. We did not implement 

these secondary transportation impacts 

in this final rule. While we do not 

anticipate that such impacts would 

significantly change the lifecycle 

analysis, we plan to continue to look at 

this issue and consider incorporating 

them in the future. 

d. Biofuel Processing 

For the proposal the GHG emissions 

from renewable fuel production were 

calculated by multiplying the Btus of 

the different types of energy inputs at 

biofuel process plants by emissions 

factors for combustion of those fuel 

sources. The Btu of energy input was 

determined based on analysis of the 

industry and specific work done as part 

of the NPRM. The emission factors for 

the different fuel types are from GREET 

and were based on assumed carbon 

contents of the different process fuels. 

The emissions from producing 

electricity in the U.S. were also taken 

from GREET and represent average U.S. 

grid electricity production emissions. 

We received comments on our 

approach and updated the analysis of 

GHG emissions from biofuel process for 

the final rule specifically regarding 

process energy use and the treatment of 

co-products. 

Process Energy Use: For the final rule 

we updated each of our biofuel 

pathways to include the latest data 

available on process energy use. For the 

proposal, one of the key sources of 

information on energy use for corn 

ethanol production was a study from the 

University of Illinois at Chicago Energy 

Resource Center. Between proposal and 

final rule, the study was updated, 

therefore, we incorporated the results of 

the updated study in our corn ethanol 

pathways process energy use for the 

final rule. We also updated corn ethanol 

production energy use for different 

technologies in the final rule based on 

feedback from industry technology 

providers as part of the public comment 

period. The main difference between 

proposal and final corn ethanol energy 

use values was a slight increase in 

energy use for the corn ethanol 

fractionation process, based on feedback 

from industry technology providers. 

For the proposal we based biodiesel 

processing energy on a process model 

developed by USDA–ARS to simulate 

biodiesel production from the Fatty 

Acid Methyl Ester (FAME) 

transesterification process. We received 

a number of comments from 

stakeholders that the energy balance for 

biodiesel production was overestimating 

energy use and should be updated. 

During the comment period USDA 

updated their energy balance for 

biodiesel production to incorporate a 

different biodiesel dehydration process 

based on a system which has resulted in 

a decrease in energy requirements. This 

change was reflected in the energy use 

values for biodiesel assumed in our final 

rule analysis which resulted in reduced 

GHG impacts from the biodiesel 

production process. 

In addition, for the final rule we have 

included an analysis of algae oil 

production for biodiesel based on 

ASPEN process modeling from NREL.174

The analysis is for two major cultivation 

pathways (open pond and 

photobioreactors) for a facility that can 

be feasibly commercialized in the 

future, represented by a ‘‘2022’’ target 

production. We coupled the algae oil 

production process (which includes 

cultivation, harvesting, and extraction) 

with the biodiesel production energy 

use from virgin oils energy use model 

under the assumption that algae oil is 

similar enough to that of virgin oil. 

For the cellulosic biofuel pathways, 

we updated our final rule energy 

consumption assumptions on process 

modeling also completed by NREL. For 

the NPRM, NREL estimated energy use 

for the biochemical enzymatic process 

to ethanol route in the near future 

(2010) and future (2015 and 

2022).175 176 177 As there are multiple 

processing pathways for cellulosic 

biofuel, we have expanded the analysis 

for the FRM to also include 

thermochemical processes (MixedAlcohols route and Fischer-Tropsch to 

diesel route) for plants which assume 

woody biomass as its feedstock. 

Under the imported sugarcane ethanol 

cases we updated process energy use 

assumptions to reflect anticipated 

increases in electricity production for 

2022 based on recent literature and 

comments to the proposal. One major 

change was assuming the potential use 

of trash (tops and leaves of sugarcane) 

collection in future facilities to generate 

additional electricity. The NPRM had 

only assumed the use of bagasse for 

electricity generation. Based on 

comments received, we are also 

assuming marginal electricity 

production (i.e., natural gas) instead of 

average electricity mix in Brazil which 

is mainly hydroelectricity. This 

approach assumes surplus electricity 

will likely displace electricity which is 

normally dispatched last, in this case 

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178The method used to estimate the GHG impacts 

associated with biodiesel transportation has not 

been changed since the proposal. This method 

utilized an earlier version of the GREET model. 

typically natural gas based electricity. 

The result of this change is a greater 

credit for displacing marginal grid 

electricity and thus a lower GHG 

emissions profile for imported 

sugarcane ethanol than that assumed in 

the NPRM. We also received public 

comment that there are differences in 

the types of process fuel e.g. used in the 

dehydration process for ethanol. While 

using heavier fuels such as diesel or 

bunker fuel tends to increase the 

imported sugarcane ethanol emissions 

profile, the overall impact was small 

enough that lifecycle results did not 

change dramatically. 

Co-Products: In response to comments 

received, we included corn oil 

fractionation and extraction as a 

potential source of renewable fuels for 

this final rulemaking. Based on research 

of various corn ethanol plant 

technologies, corn oil as a co-product 

from dry mill corn ethanol plants can be 

used as an additional biodiesel 

feedstock source (see Section VII.A.2 for 

additional information). Dry mill corn 

ethanol plants have two different 

technological methods to withdraw corn 

oil during the ethanol production 

process. The fractionation process 

withdraws corn oil before the 

production of the DGS co-product. The 

resulting product is food-grade corn oil. 

The extraction process withdraws corn 

oil after the production of the DGS coproduct, resulting in corn oil that is 

only suitable for use as a biodiesel 

feedstock. 

Based on cost projections outlined in 

Section VII.A, it is estimated that by 

2022, 70% of dry mill ethanol plants 

will conduct extraction, 20% will 

conduct fractionation, and that 10% 

will choose to do neither. These 

parameters have been incorporated into 

the FASOM and FAPRI–CARD models 

for the final rulemaking analysis, 

allowing for corn oil from extraction as 

a major biodiesel feedstock. 

Glycerin is a co-product of biodiesel 

production. Our proposal analysis did 

not assume any credit for this glycerin 

product. The assumption for the 

proposal was that by 2022 the market 

for glycerin would be saturated due to 

the large increase in biodiesel 

production in both the US and abroad 

and the glycerin would therefore be a 

waste product. We received a number of 

comments that we should be factoring 

in a co-product credit for glycerin as 

there would be some valuable use for 

this product in the market. Based on 

these comments we have included for 

the final rule analysis that glycerin 

would displace residual oil as a fuel 

source on an energy equivalent basis. 

This is based on the assumption that the 

glycerin market would still be saturated 

in 2022 and that glycerin produced from 

biodiesel would not displace any 

additional petroleum glycerin 

production. However, the biodiesel 

glycerin would not be a waste and a low 

value use would be to use the glycerin 

as a fuel source. The fuel source 

assumed to be replaced by the glycerin 

is residual oil. This inclusion of a coproduct credit for glycerin reduces the 

overall GHG impact of biodiesel 

compared to the proposal analysis. 

e. Fuel Transportation 

For the proposed rule, we estimated 

the GHG impacts associated with the 

transportation and distribution of 

domestic and imported ethanol and 

biomass-based diesel using GREET 

defaults. We have upgraded to the most 

recent version of GREET (Version 1.8c) 

for our transportation analysis in the 

final rule.178 We made several other 

updates to the method we utilized in the 

proposed rule. These updates are 

described here and in more detail in 

Chapter 2 of the RIA. 

In the proposal, we noted our 

intention to incorporate the results of a 

recent study by Oak Ridge National 

Laboratory (ORNL) into our 

transportation analysis for the final rule. 

The ORNL study models the 

transportation of ethanol from refineries 

or import facilities to the petroleum 

blending terminals by domestic truck, 

marine, and rail distribution systems. 

We used ORNL’s transportation 

projections for 2022 under the EISA 

policy scenario to update our estimates 

of the GHG impacts associated with the 

transportation of corn, cellulosic, and 

sugarcane ethanol. Since the study did 

not address the distribution of ethanol 

from petroleum blending terminals to 

refueling stations, we continued to use 

GREET defaults to estimate these 

impacts. 

The ORNL study also did not address 

the transportation of imported ethanol 

within its country of origin or en route 

to the import facility in the United 

States. As in the proposal, we used 

GREET defaults to estimate the impacts 

associated with the transportation of 

sugarcane ethanol within Brazil. We 

updated the GREET default for the 

average distance sugarcane ethanol 

travels by ocean tanker using recent 

shipping data from EIA in order to 

account for both direct Brazilian exports 

and the shipment of ethanol from 

countries in the Caribbean Basin 

Initiative. We received several 

comments on the back-haul emissions 

associated with ocean transport. For the 

final rule, we assumed that these 

emissions were negligible. 

f. Vehicle Tailpipe Emissions 

We updated the CO2 emissions factors 

for ethanol and biodiesel to be 

consistent with those used in the 

October 30, 2009 final rulemaking for 

the Mandatory GHG Reporting Rule. 

These changes caused the tailpipe GHG 

emission factors to increase by 0.8% for 

ethanol and to decrease by 1.5% for 

biodiesel. Specific tailpipe combustion 

values used in this final rule can be 

found in Chapter 2 of the RIA. Estimates 

for CH4 and N2O were made using 

outputs from EPA’s MOVES model. 

3. Petroleum Baseline 

For the proposed rule, we conducted 

an analysis to determine the lifecycle 

greenhouse gas emissions for the 

petroleum baseline against which 

renewable fuels were to be compared. 

We utilized the GREET model (Version 

1.8b), which uses an energy efficiency 

metric to calculate GHG emissions 

associated with the production of 

petroleum-based fuels. We received 

numerous comments regarding this 

approach. 

Petroleum baseline calculation from 

proposed rule: The GREET model relies 

on using average values as inputs to 

estimate aggregate emissions, rather 

than using site-specific values. 

Commenters noted a number of GREET 

input values that they believed to be 

incorrect. These included: energy 

efficiency values for crude oil 

extraction; methane emission factors for 

oil production and flaring; 

transportation distances for crude oil 

and petroleum products; and the oil 

tanker cargo payload value. Commenters 

also noted that GREET does not account 

for the energy consumption associated 

with crude oil transport in the country 

of extraction. 

In addition, commenters stated that 

the crude oil import slate assumed in 

the proposed rule was inconsistent with 

EIA crude oil production and import 

data for 2005. Commenters also noted 

that the gasoline and diesel mix that we 

used for the proposal did not match 

with EIA prime supplier sales volume 

data. One specific comment focused on 

the definition of low-sulfur diesel in 

GREET, where it is defined as being 11 

ppm sulfur content, which is 

inconsistent with EPA’s definition. As a 

result, in the proposed rule, all 

transportation diesel produced in 2005 

was assumed to be ultra-low sulfur 

diesel. 

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14784 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

179 Department of Energy: National Energy 

Technology Laboratory. 2009. NETL: PetroleumBased Fuels Life Cycle Greenhouse Gas Analysis— 

2005 Baseline Model. 

We largely agree with the above 

comments. An updated version of the 

GREET model (Version 1.8c) is 

available, and it may address some of 

the issues raised by commenters. We 

considered using this new version of 

GREET with updated input values from 

publically available sources to 

determine the petroleum baseline for 

the final rule. However, we have 

decided that using the 2005 petroleum 

baseline model developed by the 

National Energy Technology Laboratory 

(NETL) 179 would address the 

commenters’ concerns, and result in a 

more accurate and comprehensive 

assessment of the petroleum baseline 

than we could obtain using the GREET 

model. 

Use of NETL study for final rule 

petroleum baseline calculation: In the 

proposed rule, we requested comment 

on using the NETL study for our 2005 

petroleum baseline for the final 

rulemaking. We only received one 

comment, which agreed that the NETL 

values were generally more accurate and 

better documented than the values in 

GREET. However, the commenter also 

stated that NETL’s use of 2002 crude oil 

extraction data would underestimate 

extraction emissions for 2005, and that 

it would be inconsistent to use the 

GREET model for determining GHG 

emissions from biofuels, but not for 

petroleum. 

We do not agree with the commenters’ 

criticism of the NETL model. We have 

not seen data that indicates that the 

GHG emissions associated with crude 

oil extraction would be appreciably 

different in 2005 than 2002. EPA also 

believes that it is important to use the 

best available tools to estimate a 

petroleum baseline that can be 

compared to renewable fuels. The fact 

that some GREET emission factors are 

used in the calculation of biofuel 

lifecycle GHG impacts is not a reason to 

use the GREET model for the petroleum 

baseline analysis over what we feel to be 

a better tool for the baseline calculation 

needed. 

NETL states that the goal of their 

study is to ‘‘determine the life cycle 

greenhouse gas emissions for liquid 

fuels (conventional gasoline, 

conventional diesel, and kerosene-based 

jet fuel) production from petroleum as 

consumed in the U.S. in 2005 to allow 

comparisons with alternative 

transportation fuel options on the same 

basis (i.e., life cycle modeling 

assumptions, boundaries, and allocation 

procedures).’’ Unlike GREET, the NETL 

study utilized site-specific data, such as 

country-specific crude oil extraction 

profiles and port-to-port travel distances 

for imported crude oil and petroleum 

products. The NETL model also 

accounts for NGLs and unfinished oils 

as refinery inputs, which is not 

available in GREET. 

Thus, we believe that use of the NETL 

model addresses the commenters’ 

concerns with the GREET inputs used in 

the proposed rule. We have also verified 

that the NETL model uses a crude oil 

input mix and gasoline and diesel 

product slate consistent with EIA data 

for 2005. 

For the final rule, we have also 

updated the CO2 emissions factors to be 

consistent with other EPA rulemakings. 

EPA recently revised the CO2 emission 

factors for gasoline and diesel and used 

them in the September 28, 2009 

proposed rule to establish GHG 

standards for light-duty vehicles. These 

new factors are slightly lower than those 

used in the RFS2 proposal and result in 

a decrease in tailpipe GHG emissions of 

0.4% for gasoline of 0.6% and for diesel. 

Overall, with the switch to NETL and 

the updated tailpipe values, the final 

petroleum baseline value calculated for 

the final rule analysis does not differ 

significantly from what we calculated in 

the proposed rule. 

Inclusion of estimate for land use 

change: Numerous commenters raised 

the issue of land use change with regard 

to oil production, both on a direct and 

indirect basis. The proposed rule 

analysis for baseline petroleum 

emissions did not consider any land use 

change emissions associated with crude 

oil extraction. For the final rule, we do 

not consider land use emissions 

associated with road or other 

infrastructure construction for 

petroleum extraction, transport, 

refining, or upgrading, as the land use 

change associated with roads 

constructed for crop and livestock 

production was also not included. 

Furthermore, land use associated with 

natural gas extracted for use in oil sands 

extraction or upgrading was also not 

considered, as the land use change from 

natural gas extracted for biofuels 

production was not considered. 

However, for the final rule we did 

consider the inclusion of land use 

emissions associated with oil extraction. 

Using estimates for land-use change 

from conventional oil production and 

oil sands in conjunction with our data 

for the carbon intensity of land being 

developed, we were able to determine 

GHG emissions associated with land use 

change for oil production. Our analysis 

showed that the value was negligible 

compared to the full petroleum 

lifecycle. More detail on this analysis 

can be found in Chapter 2 of the RIA. 

Consideration of marginal impacts: 

We received several comments stating 

that we did not use consistent system 

boundaries in our comparisons of 

biofuels and petroleum-based fuels, in 

particular by using a marginal 

assessment of GHG emissions related to 

biofuel, but not doing so for baseline 

petroleum fuels. According to 

commenters, by not assessing the 

marginal impacts of petroleum 

production, we overestimated the GHG 

impacts of an increase in biofuel use in 

the proposed rule. Commenters argued 

that a consistent modeling approach 

would involve a marginal analysis for 

both biofuels and the petroleum 

baseline. 

The reason the system boundaries 

used for threshold assessment in the 

proposed rule and the final rule did not 

include a marginal analysis of 

petroleum production was due to the 

definition of ‘‘baseline lifecycle 

greenhouse gas emissions’’ in Section 

211(o)(1)(C) of the CAA. The definitions 

of the different renewable fuel 

categories specify that the lifecycle 

threshold analysis be compared to 

baseline lifecycle greenhouse gas 

emissions, which are defined as: 

The term ‘baseline lifecycle greenhouse gas 

emissions’ means the average lifecycle 

greenhouse gas emissions, as determined by 

the Administrator, after notice and 

opportunity for comment, for gasoline or 

diesel (whichever is being replaced by the 

renewable fuel) sold or distributed as 

transportation fuel in 2005. 

Therefore, the petroleum production 

component of the system boundaries is 

specifically mandated by EISA to be 

based on the 2005 average for crude oil 

used to make gasoline or diesel sold or 

distributed as transportation fuel, and 

not the marginal crude oil that will be 

displaced by renewable fuel. 

Furthermore, as the EISA language 

specifies that the baseline emissions are 

to be only ‘‘average’’ lifecycle emissions 

for this single specified year and 

volume, it does not allow for a 

comparison of alternative scenarios. 

Indirect effects can only be determined 

using such an analysis; therefore there 

are no indirect emissions to include in 

the baseline lifecycle greenhouse gas 

emissions. 

On the other hand, assessing the 

lifecycle GHG emissions of renewable 

fuel is not tied by statute to the 2005 

baseline and could therefore be based 

on a marginal analysis of anticipated 

changes in transportation fuel as would 

result from meeting the EISA mandates. 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14785 

Thus, Congress did not, as many 

commenters suggested, intend to 

accomplish simply a reduction in GHG 

emissions as compared to the situation 

that would exist in the future without 

enactment of EISA, as would be the case 

if Congress had specified that EPA use 

a marginal analysis in assessing the 

GHG emissions related to conventional 

baseline fuels that the EISA-mandated 

biofuels would replace. Rather, the 

statute specifies a logical approach for 

reducing the GHG emissions of 

transportation fuel as compared to those 

emissions that occurred in 2005. 

Therefore, EPA has retained in today’s 

final rule the basic analytical approach 

(marginal analysis for biofuels and 2005 

average for baseline fuels) used in the 

proposed rule. 

C. Threshold Determination and 

Assignment of Pathways 

As required by EISA, EPA is making 

a determination of lifecycle GHG 

emission threshold compliance for the 

range of pathways likely to produce 

significant volumes of biofuel for use in 

the U.S. by 2022. These threshold 

assessments only pertain to biofuels 

which are not produced in production 

facilities that are grandfathered 

(grandfathering of production facilities 

is discussed at the end of Section V.C). 

As described in Section I.A.3, because 

of the inherent uncertainty and the state 

of the evolving science on this issue, 

EPA is basing its GHG threshold 

compliance determinations for this rule 

on an approach that considers the 

weight of evidence currently available. 

For fuel pathways with a significant 

land use impact, the evidence 

considered includes the best estimate as 

well as the range of possible lifecycle 

greenhouse gas emission results based 

on formal uncertainty and sensitivity 

analyses conducted by the Agency. In 

making the threshold determinations for 

this rule, EPA weighed all of the 

evidence available to it, while placing 

the greatest weight on the best estimate 

value for the base yield scenario. In 

those cases where the best estimate for 

the potentially conservative base yield 

scenario exceeds the reduction 

threshold, EPA judges that there is a 

good basis to be confident that the 

threshold will be achieved and is 

determining that the bio-fuel pathway 

complies with the applicable threshold. 

To the extent the midpoint of the 

scenarios analyzed lies further above a 

threshold for a particular biofuel 

pathway, we have increasingly greater 

confidence that the biofuel exceeds the 

threshold. 

EPA recognizes that the state of 

scientific knowledge in this area is 

continuing to evolve, and that as the 

science evolves, the lifecycle 

greenhouse gas assessments for a variety 

of fuel pathways will continue to 

change. Therefore, while EPA is making 

regulatory determinations for fuel 

pathways as required by the statute in 

this final rule based on its current 

assessment, EPA is at the same time 

committing to further reassess these 

determinations and the lifecycle 

estimates. As part of the ongoing effort, 

we will ask for the expert advice of the 

National Academy of Sciences as well 

as other experts and then reflect this 

advice and any updated information in 

a new assessment of the lifecycle GHG 

emission performance of the biofuels 

being evaluated today. EPA will request 

that the National Academy of Sciences 

evaluate the approach taken in this rule, 

and the underlying science of lifecycle 

assessment and in particular indirect 

land use change, and make 

recommendations for subsequent 

rulemakings on this subject. This new 

assessment could in some cases result in 

new determinations of threshold 

compliance compared to those included 

in this rule which would apply to future 

production from plants that are 

constructed after each subsequent rule. 

Nonetheless, EPA is required by EISA 

to make threshold determinations at this 

time as to what fuels qualify for each of 

the four different fuel categories and 

lifecycle GHG thresholds. In the 

previous sections, we have described 

the analytical basis EPA is using for its 

lifecycle GHG assessment. These 

analyses represent the most up to date 

information currently available on the 

GHG emissions associated with each 

element of the full lifecycle assessment. 

Notably these analyses include an 

assessment of uncertainty for key 

parameters of the pathways evaluated. 

The best estimates and ranges of results 

for the different pathways can be used 

to help assess whether a particular 

pathway should be considered as 

attaining the 20%, 50% or 60% 

thresholds, as applicable. The graphs 

included in the discussion below 

provide representative depictions of the 

results of our analysis (including the 

uncertainty in the modeling) for typical 

pathways for corn ethanol, biodiesel 

produced from soy oil and from waste 

oils, fats and greases, sugarcane ethanol 

and cellulosic biofuel from switchgrass. 

We have also conducted lifecycle 

modeling assessments for cellulosic 

biofuel pathways using other feedstock 

sources, for biobutanol and for two 

specific pathways for emerging biofuels 

that would use oil from algae as their 

feedstock. Additional GHG performance 

assessment results for other feedstock/ 

fuel/technology combinations are also 

described below as well as in the RIA 

Chapter 2. 

Below we consider the analytical 

results of scenarios and fuel pathways 

modeled by EPA as well as additional 

appropriate information to determine 

the threshold compliance for an array of 

biofuels likely to be produced in 2022. 

Ethanol from corn starch: While EPA 

analyzed the lifecycle GHG performance 

of a variety of ethanol from corn starch 

pathways (complete results can be 

found in the RIA), for purposes of this 

threshold determination we have 

focused the discussion on the impacts of 

those plant designs that are most likely 

to be built in the future. We have 

focused this discussion on new plant 

designs because production from 

existing plants is grandfathered for 

purposes of compliance with the 20% 

lifecycle GHG threshold. Only new 

plants and expanded capacity at 

existing plants need to comply with a 

20% lifecycle GHG emissions threshold 

to comply with the total renewable fuel 

mandate under the RFS2. 

While we focus our lifecycle GHG 

threshold analysis on the new plant 

designs most likely to be built through 

2022, we also note that some existing 

plant designs, although subject to the 

grandfathering provisions, would not 

qualify if having to meet the 20% 

performance threshold. For example, 

existing designs of ethanol plants using 

coal as their process heat source would 

not qualify. 

As discussed in Section IV, EPA 

anticipates that by 2022 any new dry 

mill plants producing ethanol from corn 

starch will be equipped with more 

energy efficient technology and/or 

enhanced co-product production than 

today’s average plant. These predictions 

are largely based on economic 

considerations. To compete 

economically, future ethanol plants will 

need to employ energy saving 

technologies and other value added 

technologies that have the effect of also 

reducing their GHG footprint. For 

example, while only in limited use 

today, we predict approximately 90% of 

all plants will be producing corn oil as 

a by-product either through a 

fractionation or extraction process; it is 

likely most if not all new plants will 

elect to include such technology. We 

also predict that all will use natural gas, 

biomass or biogas as the process energy 

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14786 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

180 Dry mill corn ethanol plants using coal as a 

process energy source would not qualify as 

exceeding the 20% reduction threshold as modeled. 

We do not expect plants relying on coal for process 

energy to be built through 2022. However, if they 

were built, they would need to use technology 

improvements such as carbon capture and storage 

(CCS) technology. We did not model what the 

performance would be if these plants also installed 

CCS technology. 181We do not believe new wet mill corn ethanol 

plants will be built through 2022 since this design 

is much more complicated and expensive than a 

dry mill plant. Especially since dry mill plants 

equipped with corn oil fractionation will produce 

additional supplies of food grade corn oil (one of 

the products and therefore reasons to construct a 

wet mill plant), we see no near term incentive for 

additional wet mill ethanol production capacity. 

However, we have modeled the lifecycle GHG 

impact of ethanol produced at a wet mill plant 

when relying on biomass as the process energy 

source and have determined it would meet the 20% 

GHG threshold. Therefore, this type of facility is 

also included in Table V.C–6. 

source.180 181 We also expect that, to 

lower their operating costs, most 

facilities will sell a portion of their coproduct DGS prior to drying thus 

reducing energy consumption and 

improving the efficiency and lifecycle 

GHG performance of the plant. The 

current national average plant sells 

approximately 37% of the DGS coproduct prior to drying. 

In analyzing the corn ethanol plant 

designs we expect could be built 

through 2022 using natural gas or 

biomass for process energy and 

employing advanced technology, in all 

cases, the midpoint and therefore the 

majority of the scenarios analyzed are 

above the 20% threshold. This indicates 

that, based on the current modeling 

approaches and sets of assumptions, we 

are over 50% confident the actual GHG 

performance of the ethanol from new 

corn ethanol plants will exceed the 

threshold of 20% improvement in 

lifecycle GHG emissions performance 

compared to the gasoline it is replacing. 

We are determining at this time that 

the corn ethanol produced at such new 

plants (and existing plants with 

expanded capacity employing the same 

technology) will exceed the 20% GHG 

performance threshold. A complete 

listing of complying facilities using 

advanced technologies and operating 

procedures is included in Table V.C–6. 

Figure V.C–1 shows the percent 

change in the lifecycle GHG emissions 

compared to the petroleum gasoline 

baseline in 2022 for a corn ethanol dry 

mill plant using natural gas for its 

process energy source, drying the 

national average of 63% of the DGS it 

produces and employing corn oil 

fractionation technology. Lifecycle GHG 

emissions equivalent to the gasoline 

baseline are represented on the graph by 

the zero on the X-axis. The 20% 

reduction threshold is represented by 

the dashed line at ¥20 on the graph. 

The results for this corn ethanol 

scenario are that the midpoint of the 

range of results is a 21% reduction in 

GHG emissions compared to the 

gasoline 2005 baseline. The 95% 

confidence interval around that 

midpoint ranges from a 7% reduction to 

a 32% reduction compared to the 

gasoline baseline. 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14787 

Table V.C–1 below includes lifecycle 

GHG emissions broken down by several 

stages of the lifecycle impacts for a 

natural gas dry mill corn ethanol facility 

as compared to the 2005 baseline 

average for gasoline. This table (and 

similar tables which follow in the 

discussion for other biofuels) is 

included to transparently demonstrate 

the contribution of each stage and their 

relative significance. Lifecycle 

emissions are normalized per energy 

unit of fuel produced and presented in 

kilograms of carbon-dioxide equivalent 

GHG emissions per million British 

Thermal Units of renewable fuel 

produced (kg CO2e/mmBTU). The 

domestic and international agriculture 

rows include emissions from changes in 

agricultural production (e.g., fertilizer 

and energy use, rice methane) and 

livestock production. The fuel 

production row includes emissions from 

the fuel production or refining facility, 

primarily from energy consumption. For 

renewable fuels, tailpipe emissions only 

include non-CO2 gases, because the 

carbon emitted as a result of fuel 

combustion is offset by the uptake of 

biogenic carbon during feedstock 

production. Note, that while the table 

separates the emissions into different 

categories, the results are based on 

integrated modeling; therefore, one 

component can not be removed without 

impacting the other results. For 

example, domestic land use and 

agricultural sector emissions depend on 

the international assumptions. If a case 

without international impacts were 

modeled, the domestic results would 

likely be significantly different. 

The table includes our mean estimate 

of international land use change 

emissions as well as the 95% 

confidence range from our uncertainty 

assessment, which accounts for 

uncertainty in the types of land use 

changes and the magnitude of resulting 

GHG emissions. The last row includes 

mean, low and high total lifecycle GHG 

emissions based on the 95% confidence 

range for land use change emissions. For 

the petroleum baseline, the fuel 

production stage includes emissions 

from extraction, transport, refining and 

distribution of petroleum transportation 

fuel. Petroleum tailpipe emissions 

include CO2 and non-CO2 gases emitted 

from fuel combustion. 


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TABLE V.C–1—LIFECYCLE GHG EMISSIONS FOR CORN ETHANOL, 2022 

[kg CO2e/mmBTU] 

Fuel type Ethanol 2005 Gasoline baseline 

Fuel Production Technology ........................................................................................... Natural Gas Fired Dry Mill .........................

Net Domestic Agriculture (w/o land use change) ........................................................... 4 .................................................................

Net International Agriculture (w/o land use change) ...................................................... 12 ...............................................................

Domestic Land Use Change ........................................................................................... ¥2 ..............................................................

International Land Use Change, Mean (Low/High) ........................................................ 32 (21/46) ...................................................

Fuel Production ............................................................................................................... 28 ............................................................... 19 

Fuel and Feedstock Transport ........................................................................................ 4 .................................................................

Tailpipe Emissions .......................................................................................................... 1 ................................................................. 79 

Total Emissions, Mean (Low/High) ................................................................................. 79 (54/97) ................................................... 98 

While we are projecting technology 

enhancements which would allow corn 

ethanol plants to exceed the threshold, 

plant designs which do not include 

such advanced technology would not 

comply. For example, a basic plant 

which is not equipped with 

combinations of advanced technologies 

such as corn oil fractionation or dries 

more than 50% of its DGS is predicted 

to not comply. While we do not expect 

such a basic, low technology plant to be 

built nor existing plants to expand their 

production without also installing such 

advanced technology, if this were to 

occur, ethanol produced at such 

facilities would not comply with the 

20% threshold. 

Biodiesel from soybean oil: We 

analyzed the lifecycle GHG emission 

impacts of producing biodiesel using 

soy oil as a feedstock for compliance 

with a lifecycle GHG performance 

threshold of 50%. The modeling 

framework for this analysis was much 

the same as used for the proposal. 

However, as noted above, based on 

comments, updated information and 

enhanced models, the results are 

significantly updated. 

As in the case of ethanol produced 

from corn starch, EPA has relied on a 

weight of evidence in developing its 

threshold assessment for biodiesel 

produced from soybean oil. In analyzing 

the base yield case, the midpoint and 

therefore the majority of the scenarios 

analyzed exceed the threshold. This 

indicates that based on currently 

available information and our current 

analysis over the range of scenarios 

considered, the actual performance of 

soy oil-based biodiesel likely exceeds 

the applicable 50% threshold. 

The scenarios analyzed also indicate, 

based on current data, we are at least 

95% confident biodiesel produced from 

soy oil will have GHG impacts which 

are better than the 2005 baseline diesel 

fuel. From a GHG impact perspective, 

we therefore conclude that even in the 

less likely event the actual performance 

of biodiesel from soy oil does not 

exceed the 50% threshold, GHG 

emission performance of transportation 

fuel would still improve if this biodiesel 

replaced diesel fuel. 

We are further confident that 

biodiesel exceeds the 50% threshold 

since our assessment of biodiesel GHG 

performance does not include any 

prediction of significant improvements 

in plant technology or unanticipated 

energy saving improvements that would 

further improve GHG performance. 

Additionally, our assumption that the 

co-product of glycerin would only have 

GHG value as replacement for residual 

heating oil could be conservative. While 

we have not analyzed the range of 

potential uses of glycerin, potential uses 

of glycerin including as a feedstock to 

the chemical industry could be higher 

in GHG benefit than its assumed use as 

a heating fuel. 

Considering all of the above current 

information and analyses, EPA 

concludes that biodiesel made from soy 

oil will exceed its lifecycle GHG 

threshold. Further, we see no benefit in 

lowering the threshold to as low as 40% 

as allowed under EISA as this will 

neither benefit available supply nor 

GHG performance of the fuel. Therefore, 

the threshold for this rule will be 

maintained at 50%. 

Figure V.C–2 shows the percent 

change in the typical 2022 soybean 

biodiesel lifecycle GHG emissions 

compared to the petroleum diesel fuel 

2005 baseline. Lifecycle GHG emissions 

equivalent to the diesel fuel baseline are 

represented on the graph by the zero on 

the X-axis. The 50% reduction 

threshold is represented by the dashed 

line at ¥50 on the graph. The results for 

soybean biodiesel are that the midpoint 

of the range of results is a 57% 

reduction in GHG emissions compared 

to the diesel fuel baseline. The 95% 

confidence interval around that 

midpoint results in range of a 22% 

reduction to an 85% reduction 

compared to the diesel fuel 2005 

baseline. 

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Biodiesel from waste oils, fats and 

greases: The lifecycle assessment of 

GHG performance for biodiesel 

produced from waste oils, fats and 

greases is much simpler than 

comparable assessments for biofuels 

made from crops. In the case of 

biodiesel made from waste material, 

there is no land use impact so the 

agricultural assessments required for 

crop-based biofuels are unnecessary. 

Without the uncertainty concerns due to 

land use impacts, there was no need to 

conduct an uncertainty analysis for 

biodiesel from waste oils, fats and 

greases. The assessment methodology 

for biofuel from waste oils fats and 

greases is much the same as that 

analyzed for the proposal. As was the 

case for the proposal, the assessment of 

each element in the lifecycle process is 

straight forward and includes collecting 

and transporting the feedstock, 

transforming it into a biofuel and 

distributing and using the fuel. Based on 

the lifecycle assessment for this final 

rule, we are estimating biofuel from 

waste oils, fats and greases result in an 

86% reduction in GHG emissions 

compared to the 2005 baseline for 

petroleum diesel. As was the case for 

the assessment included in the 

proposal, biofuel from these feedstock 

sources easily exceeds the applicable 

threshold of 50%. 

Table V.C–2 below breaks down by 

stage the lifecycle GHG emissions for 

soy-based biodiesel, biodiesel from 

waste grease feedstocks and the 2005 

diesel baseline. The average 2022 

biodiesel production process reflected 

in this table assumes that natural gas is 

used for process energy and accounts for 

co-product glycerin displacing residual 

oil. This table demonstrates the 

contribution of each stage and their 

relative significance. 

TABLE V.C–2—LIFECYCLE GHG EMISSIONS FOR BIODIESEL, 2022 

[kg CO2e/mmBTU] 

Fuel type Soy-based 

biodiesel 

Waste grease 

biodiesel 

2005 Diesel 

baseline 

Net Domestic Agriculture (w/o land use change) ........................................................................ ¥10 0 

Net International Agriculture (w/o land use change) ................................................................... 1 0 

Domestic Land Use Change ....................................................................................................... ¥9 0 

International Land Use Change, ..................................................................................................

Mean (Low/High) ......................................................................................................................... 43 (15/76) 0 


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TABLE V.C–2—LIFECYCLE GHG EMISSIONS FOR BIODIESEL, 2022—Continued 

[kg CO2e/mmBTU] 

Fuel type Soy-based 

biodiesel 

Waste grease 

biodiesel 

2005 Diesel 

baseline 

Fuel Production ............................................................................................................................ 13 10 18 

Fuel and Feedstock Transport .................................................................................................... 3 3 

Tailpipe Emissions ....................................................................................................................... 1 1 79 

Total Emissions, Mean ................................................................................................................

(Low/High) .................................................................................................................................... 42 (14/76) 14 97 

Biodiesel from algae oil: We analyzed 

the lifecycle GHG emission impacts of 

producing biodiesel from algae oil as a 

feedstock for compliance with a 

lifecycle performance threshold of 50%. 

Our analyses were based on 

technoeconomic modeling completed by 

NREL, as previously discussed. The 

NREL modeling included algae 

cultivation, harvesting, extraction, and 

recovery of algae oil. Algae oil is further 

assumed to use the same oil to biodiesel 

production technology as soy oil, which 

was updated based on enhanced 

models. As algae are expected to be 

grown on relatively small amounts of 

non-arable lands, it is expected that the 

land use impact will be negligible. 

Based on our current lifecycle 

assessment of algae oil for the final rule, 

we are determining that biodiesel from 

algae oil will comply with the lifecycle 

performance advanced biofuel threshold 

of 50%. 

Ethanol from sugarcane: As is the 

case for other crop-based biofuels, EPA 

considered the weight of evidence 

currently available information in 

assessing the lifecycle GHG performance 

of this fuel. As noted in Section I.A.3, 

this lifecycle GHG assessment includes 

significant updates from the analysis 

performed for the proposal. We have 

added pathways for sugarcane ethanol 

such that we now distinguish sugarcane 

ethanol produced assuming most crop 

residue (leaves and stalks) are collected 

and therefore available for burning as 

process energy, or sugarcane produced 

without the extra crop residue being 

collected nor burned as process energy. 

We also analyzed pathways assuming 

the ethanol is distilled in Brazil or 

alternatively being distilled in the 

Caribbean. We did not analyze a ‘‘high 

yield’’ case for sugarcane as we did for 

corn and soy since we had no 

information available suggesting there 

could be an appreciable range in 

expected sugarcane yields. 

Based on the currently available 

information, the midpoint and thus the 

majority of the scenarios analyzed 

exceed the 50% threshold applicable to 

advanced biofuels. This indicates that 

based on currently available information 

and our current analysis, it is more than 

50% likely that the actual performance 

of ethanol produced from sugarcane 

exceeds the applicable 50% threshold. 

The analyses also indicate, based on 

current data, ethanol produced from 

sugarcane will clearly have GHG 

impacts which are better than the 2005 

baseline gasoline. From a GHG impact 

perspective, we therefore conclude that 

even in the less likely event the actual 

performance of sugarcane does not 

exceed the 50% threshold, GHG 

emission performance of ethanol from 

sugarcane would be better than gasoline. 

We also considered what would 

happen if we determine that ethanol 

from sugarcane does not comply with a 

50% threshold due to the relatively low 

risk that this biofuel will actually be 

below that threshold. Based on our 

current analysis of available pathways 

for producing advanced biofuel, we 

believe that it will be necessary to 

include over 2 billion gallons of 

sugarcane ethanol in order to meet the 

advanced biofuel volumes anticipated 

by EISA. If sugarcane ethanol was not 

an eligible source of advanced biofuel 

and other unanticipated sources did not 

become available, the standard for 

advanced biofuel would have to be 

lower to the extent necessary to 

compensate for the lack of eligible 

sugarcane ethanol. The lower amount of 

advanced biofuel would then most 

likely be replaced with petroleum-based 

gasoline. The replacement fuel would 

have a worse GHG performance than the 

sugarcane ethanol. Therefore, GHG 

performance of the transportation fuel 

pool would suffer. 

Considering the above, EPA has 

concluded that, based on currently 

available information and our analysis, 

ethanol from sugarcane qualifies as an 

advanced biofuel. 

Figure V.C–3 shows the percent 

change in the average 2022 sugarcane 

ethanol lifecycle GHG emissions 

compared to the petroleum gasoline 

2005 baseline. These results assume the 

ethanol is produced and dehydrated in 

Brazil prior to being imported into the 

U.S. Lifecycle GHG emissions 

equivalent to the gasoline baseline are 

represented on the graph by the zero on 

the X-axis. The 50% reduction 

threshold is represented by the dashed 

line at ¥50 on the graph. The results for 

this sugarcane ethanol scenario are that 

the midpoint of the range of results is 

a 61% reduction in GHG emissions 

compared to the gasoline baseline. The 

95% confidence interval around that 

midpoint results in a range of a 52% to 

71% reduction compared to the gasoline 

2005 baseline. 

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Table V.C–3 below presents results for 

sugarcane ethanol production and use 

by lifecycle stage. This table 

demonstrates the contribution of each 

stage and their relative significance. The 

fuel production emissions include 

displacement of marginal Brazilian 

electricity because electricity is 

generated with the sugarcane bagasse 

co-product. As in similar previous 

tables, domestic emissions include all 

emissions sources in the United States, 

with all other emissions—including 

emissions from Brazil—presented in the 

international categories. 

TABLE V.C–3—LIFECYCLE GHG EMISSIONS FOR SUGARCANE ETHANOL, 2022 

[kg CO2e/mmBTU] 

Fuel type Sugarcane 

ethanol 

2005 Gasoline 

baseline 

Net Domestic Agriculture (w/o land use change) .................................................................................................. 0 0 

Net International Agriculture (w/o land use change) ............................................................................................. 38 0 

Domestic Land Use Change ................................................................................................................................. 1 0 

International Land Use Change, Mean (Low/High) ............................................................................................... 4(¥5/12) 0 

Fuel Production ...................................................................................................................................................... ¥11 19 

Fuel and Feedstock Transport .............................................................................................................................. 5 0 

Tailpipe Emissions ................................................................................................................................................. 1 79 

Total Emissions, Mean (Low/High) ................................................................................................................ 38 (29/46) 98 

Cellulosic Biofuels: In the proposal, 

we analyzed biochemical cellulosic 

ethanol pathways from both switchgrass 

and corn stover, and on that basis 

proposed that such cellulosic biofuels 

met the required 60% lifecycle 

threshold by a considerable margin. As 

described in Section V.B, we have 

considerably updated our lifecycle 

analysis, and have analyzed additional 

cellulosic biofuel pathways (i.e., 

thermochemical cellulosic ethanol and a 


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BTL diesel pathway). We analyzed the 

GHG impacts of each element of the 

lifecycle for producing and using 

biofuels from cellulosic biomass, and as 

for other fuel pathways, considered the 

range of possible outcomes. 

Figure V.C–4 shows the percent 

change in the average lifecycle GHG 

emissions in 2022 for ethanol produced 

from switchgrass using the biochemical 

process compared to the petroleum 

gasoline 2005 baseline. Lifecycle GHG 

emissions equivalent to the gasoline 

baseline are represented on the graph by 

the zero on the X-axis. The 60% 

reduction threshold is represented by 

the dashed line at ¥60 on the graph. 

The results for this switchgrass ethanol 

scenario are that the midpoint of the 

range of results is a 110% reduction in 

GHG emissions compared to the 

gasoline baseline. The 95% confidence 

interval around that midpoint ranges 

from 102% reduction to a 117% 

reduction compared to the gasoline 

baseline. 

Table V.C–4 below shows lifecycle 

GHG emissions for cellulosic ethanol 

produced from switchgrass (as depicted 

in Figure V.C–4, above) and also corn 

residue by lifecycle stage, comparing 

these to the 2005 baseline gasoline. This 

table is included to demonstrate the 

contribution of each stage and their 

relative significance. Results are 

presented for the biochemical 

production technology depicted in 

Figure V.C–4 above and also for 

thermochemical production 

technologies. The fuel production 

emissions for the biochemical pathway 

include credit for excess electricity 

generation at the fuel production 

facility. 

TABLE V.C–4—LIFECYCLE GHG EMISSIONS FOR CELLULOSIC ETHANOL, 2022 

[kg CO2e/mmBTU] 

Fuel type Switchgrass ethanol Corn residue 2005 Gasoline 

baseline Fuel production technology Bio-chemical Thermo-chemical Bio-chemical Thermo-chemical 

Net Domestic Agriculture (w/o land use 

change) .............................................. 6 6 11 11 0 


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TABLE V.C–4—LIFECYCLE GHG EMISSIONS FOR CELLULOSIC ETHANOL, 2022—Continued 

[kg CO2e/mmBTU] 

Fuel type Switchgrass ethanol Corn residue 2005 Gasoline 

baseline Fuel production technology Bio-chemical Thermo-chemical Bio-chemical Thermo-chemical 

Net International Agriculture (w/o land 

use change) ....................................... 0 0 0 0 0 

Domestic Land Use Change .................. ¥2 ¥3 ¥11 ¥11 0 

International Land Use Change, Mean 

(Low/High) .......................................... 15 (9/23) 16 1(9/24) 0 0 0 

Fuel Production ...................................... ¥33 4 ¥33 4 19 

Fuel and Feedstock Transport ............... 3 3 2 2 0 

Tailpipe Emissions ................................. 1 1 1 1 79 

Total Emissions, Mean (Low/High) ¥10 (¥17/¥2) 27 (20/35) ¥29 7 98 

Table V.C–5 below presents lifecycle 

GHG emissions for cellulosic diesel 

produced with a Fischer-Tropsch 

process by lifecycle stage. 

TABLE V.C–5—LIFECYCLE GHG EMISSIONS FOR CELLULOSIC DIESEL, 2022 

[kg CO2e/mmBTU] 

Fuel type Switchgrass diesel Corn residue diesel 

2005 Diesel baseline 

Fuel production technology F–T diesel F–T diesel 

Net Domestic Agriculture (w/o land use change) .............................................. 6 11 0 

Net International Agriculture (w/o land use change) ......................................... 0 0 0 

Domestic Land Use Change ............................................................................. ¥3 ¥11 0 

International Land Use Change, Mean (Low/High) ........................................... 16 (9/24) 0 0 

Fuel Production .................................................................................................. 5 5 18 

Fuel and Feedstock Transport .......................................................................... 3 2 0 

Tailpipe Emissions ............................................................................................. 1 1 79 

Total Emissions, Mean (Low/High) ............................................................ 29 (22/37) 9 97 

Based on the currently available 

information, we conclude that all 

modeled cellulosic biofuel pathways are 

expected to exceed the 60% threshold 

applicable to cellulosic biofuels. 

Assessments of similar feedstock 

sources: In the proposal, we indicated 

that although we did not specifically 

analyze all potential feedstock sources, 

some feedstock sources are similar 

enough to those modeled that we 

believe the modeled results could be 

extended to these similar feedstock 

types. Comments received supported 

this approach and the specific 

recommendations for similar feedstock 

designations as proposed. 

For this final rule, consistent with 

what was proposed, we are relying on 

modeling results and only expanding to 

additional pathways where we have 

good information these additional 

pathways will have lifecycle GHG 

results which either will not impact our 

overall assessment of the performance of 

that fuel pathway or would have at least 

as good as the modeled pathways. The 

agricultural sector modeling used for 

our lifecycle analysis does not predict 

any soybean biodiesel or corn ethanol 

will be imported into the U.S., or any 

imported sugarcane ethanol from 

production in countries other than 

Brazil. However, these rules do not 

prohibit the use in the U.S. of these 

fuels produced in countries not 

modeled if they are also expected to 

comply with the eligibility requirements 

including meeting the thresholds for 

GHG performance. Although the GHG 

emissions of producing these fuels from 

feedstock grown or biofuel produced in 

other countries has not been specifically 

modeled, we do not anticipate their use 

would impact our conclusions regarding 

these feedstock pathways. The 

emissions of producing these fuels in 

other countries could be slightly higher 

or lower than what was modeled 

depending on a number of factors. Our 

analyses indicate that crop yields for the 

crops in other countries where these 

fuels are also most likely to be produced 

are similar or lower than U.S. values 

indicating the same or slightly higher 

GHG impacts. Agricultural sector inputs 

for the crops in these other countries are 

roughly the same or lower than the U.S. 

pointing toward the same or slightly 

lower GHG impacts. If crop production 

were to expand due to biofuels in the 

countries where the models predict 

these biofuels might additionally be 

produced, this would tend to lower our 

assessment of international indirect 

impacts but could increase our 

assessment of the domestic (i.e., the 

country of origin) land use impacts. EPA 

believes, because of these offsetting 

factors along with the small amounts of 

fuel potentially coming from other 

countries, that incorporating fuels 

produced in other countries will not 

impact our threshold analysis. 

Therefore, fuels of the same fuel type, 

produced from the same feedstock using 

the same fuel production technology as 

modeled fuel pathways will be assessed 

the same GHG performance decisions 

regardless of country of origin. 

We are also able to conclude that 

some feedstock types not specifically 

modeled should be covered as we have 

good reason to believe their 

performance would be better than the 

feedstock pathways modeled. Thus for 

example, we can conclude that, as in the 

case of corn stover which we have 

modeled as a feedstock source, 

cellulosic biofuel produced from other 

agricultural waste will also have no land 

use impact and would be expected to 

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have lifecycle GHG emission impacts 

similar enough to the modeled corn 

stover feedstock pathway such that they 

would also comply. Similarly, we have 

information on miscanthus indicating 

that this perennial will yield more 

feedstock per acre than the modeled 

switchgrass feedstock without 

additional GHG inputs such as fertilizer. 

Therefore we are concluding that since 

cellulosic biofuel from switchgrass 

complies with the cellulosic threshold 

of 60% reduction, fuel produced using 

miscanthus and other perennial grasses 

will also surely comply. 

We are also determined that biofuel 

from separated yard and food wastes 

(which may contain incidental and postrecycled paper and wood wastes) satisfy 

biofuel thresholds. Separated food waste 

is largely starch-based and thus qualifies 

for the advanced biofuel standard of 

50% reduction. If the biofuel producer 

can demonstrate that it is able to 

quantify the cellulosic portion of food 

wastes, fuel made from the cellulosic 

portion can qualify as cellulosic biofuel. 

Since we have determined that yard 

wastes are largely cellulosic, biofuel 

from yard waste will qualify as 

cellulosic biofuel. The use of separated 

yard and food wastes for biofuel 

production including the requirements 

for demonstrating what portion of food 

waste is cellulosic feedstock is 

discussed further in Section II.B.4.d. 

EPA believes that renewable fuel 

produced from feedstocks consisting of 

wastes that would normally be 

discarded or put to a secondary use, and 

which have not been intentionally 

rendered unfit for productive use, 

should be assumed to have little or no 

land use emissions of GHGs. The use of 

wastes that would normally be 

discarded does not increase the demand 

for land. For example, the use in biofuel 

production of food waste from a food 

processing facility that would normally 

be placed in a landfill will not increase 

the demand for land to grow the crops 

that were purchased by the food 

processing facility. Similarly, wastes 

that would not normally be discarded 

because there are alternative secondary 

uses for them (for example 

contaminated vegetable oil might be 

burned in a boiler) are not produced for 

the purpose of such secondary use and 

the use of these feedstocks also does not 

increase demand for land. Since these 

waste-derived feedstocks have little or 

no land use impact, the lifecycle GHG 

emissions associated with their use for 

biofuel production are largely the result 

of the energy required to collect and 

process the feedstock prior to 

conversion, and the energy required to 

convert that feedstock into a biofuel. 

This has led us to conclude it is 

reasonable to include a restricted set of 

additional feedstocks in pathways 

complying with the applicable 

threshold. 

The look-up table identifies a number 

of individual fuel ‘‘pathways’’ that allow 

for the use of waste feedstocks. These 

feedstocks include (1) waste ethanol 

from beverage production, (2) waste 

starches from food production and 

agricultural residues, (3) waste oils/fats/ 

greases, (4) waste sugar from food and 

beverage production, and (5) food and 

beverage production wastes. For the 

purpose of this rule only, EPA will 

consider these feedstocks to be ‘‘wastes’’ 

if they are used as feedstock to produce 

fuel, but would otherwise normally be 

discarded or used for another secondary 

purpose because they are no longer 

suitable for their original intended use. 

They may be unsuitable for their 

original intended use either because 

they are themselves waste from that 

original use (e.g., table scraps) or 

because of contamination, spoilage or 

other unintentional acts. EPA will not 

consider any material that has been 

intentionally rendered unsuitable for its 

original use to be a ‘‘waste.’’ 

As discussed in more detail in Section 

II.B.4.d, EPA has also determined that 

the biogenic portion of post recycled 

MSW is eligible to produce renewable 

fuel and will largely be made up of 

cellulosic material. Therefore biofuel 

made from this waste-derived material 

will qualify as cellulosic biofuel. 

EPA has also considered biofuels 

produced from annual cover crops such 

as cover crops grown in the winter. 

These annual cover crops are normally 

planted as a rotation between primary 

planted crops or between trees and 

vines in orchards and vineyards, 

typically to protect soil from erosion, 

improve the soil between periods of 

regular crops, or for other conservation 

purposes. For annual cover crops grown 

on the same land as the primary crops, 

we have determined that there is little 

or no land use impact such that the 

GHG emissions associated with them 

would largely result due to inputs 

required to grow the crop, harvesting 

and transporting to the biofuel 

production facility, turning that 

feedstock into a biofuel and transporting 

it to its end use. As such, the biofuel 

from cellulosic biomass from annual 

cover crops are, for example, 

determined to meet requirements of 

cellulosic biofuel, oil from annual cover 

crops are determined to meet the 

requirements of renewable diesel and 

starches from annual cover crops are 

determined to meet the requirements of 

advanced biofuel. 

While we have not been able to model 

all possible feedstocks that can and are 

being used for renewable fuel 

production, there are a variety of 

feedstocks that should have similar 

enough characteristics to those already 

modeled to allow them to be grouped in 

with already modeled fuel pathways. In 

particular, as discussed below, there are 

five categories of biofuel feedstock 

sources for which we are confident, by 

virtue of their lack of any land-use 

change impact, in qualifying them for 

particular renewable fuel standards (Dcodes) on the basis of our existing 

modeling. 

1. All crop residues which provide 

starch or cellulosic feedstock. By virtue 

of the fact that they do not cause any 

land-use change impacts, they should 

all have similar lifecycle GHG impacts. 

Thus, modeling conducted for corn 

stover is being extended to other crop 

residues such as wheat straw, rice straw, 

and citrus residue. These residues are 

what remains after a primary crop is 

harvested, and can be similarly 

collected, transported and used in 

biofuel production. 

2. Slash, forest thinnings, and forest 

residue providing cellulosic feedstock. 

As excess material, these represent 

another form of residue which should 

also result in no land-use change GHG 

impacts. Their GHG emission impacts 

would only be associated with 

collection, transport, and processing 

into biofuel. Consequently, modeling 

conducted for corn stover is also being 

extended to these residues. 

3. Annual cover crops planted on 

existing crop land such as winter cover 

crops and providing cellulosic material, 

starch or oil for biofuel production. 

While different from crop residues, 

these secondary crops also have no land 

use impact since they are planted on 

land otherwise used for primary crop 

production. GHG emissions would only 

be associated with growing, harvesting 

and transporting the secondary crop and 

then processing into biofuel. In the case 

of secondary crops that might be used 

for cellulosic biofuel production, they 

would also have no land-use change 

impact, and consequently modeling 

conducted for corn stover is also being 

extended to these crops. In the case of 

secondary crops used for oil production, 

they would then have no land-use 

change similar to waste fats, oils and 

greases. Consequently, modeling 

conducted for biodiesel and renewable 

diesel from these waste oils is also being 

extended to these annual cover crops. 

4. Separated food and yard wastes, 

including food and beverage wastes 

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from food production and processing 

are another category of waste product 

that would not have any land-use 

change impact. These waste products 

can be used as feedstock for advanced 

biofuel production or cellulosic biofuel 

production. Waste oils have already 

been modeled as complying with the 

biomass-based diesel standard. 

Applying our sugarcane results without 

the land-use change component to waste 

sugars clearly demonstrates compliance 

with the advanced biofuel threshold. 

Applying our corn results without the 

land-use component to waste starches 

clearly demonstrates compliance with 

the renewable fuel standard 

5. Perennial grasses including 

switchgrass and miscanthus. We 

modeled switchgrass and miscanthus 

has higher yield per acre without any 

significant (or perhaps less) inputs such 

as fertilizer per acre. We believe other 

perennial grasses likely to compete as 

feedstock sources will have similar land 

use and agricultural inputs are therefore 

confident the results from switchgrass 

can be extended to miscanthus and 

other perennial grasses. However, we 

note that the energy crop industry is just 

starting to develop and therefore as 

favored perennial grasses start to 

emerge, additional analyses may be 

warranted. 

Applicable D-Codes for Fuel 

Pathways: Based on the above, corn 

ethanol facilities using natural gas or 

biomass as the process energy source 

will meet the applicable 20% GHG 

performance threshold if it either also 

uses at least two of the technologies 

Table V.C–6 or one of the technologies 

in Table V.C–6 but marketing at least 

35% of its DGS as wet. Alternatively, a 

facility using none of the advanced 

technologies listed in Table V.C–6 will 

qualify as producing ethanol meeting 

the 20% performance threshold if it 

sells at least 50% of its DGS prior to 

drying. 

TABLE V.C–6—MODELED ADVANCED

TECHNOLOGIES

Corn oil fractionation 

Corn oil extraction 

Membrane separation 

Raw starch hydrolysis 

Combined heat and power 

Following the criteria for D-Codes 

defined in Section II.A–1, the following 

renewable fuel pathways have been 

found to comply with the applicable 

lifecycle GHG thresholds and are 

therefore eligible for the D-Codes 

specified in Table V.C–7. 

TABLE V.C–7—D-CODE DESIGNATIONS

Fuel type Feedstock Production process 

requirements D-Code 

Ethanol .................................................. Corn starch .......................................... All of the following: 6 (renewable fuel) 

Drymill process, using natural gas, 

biomass or biogas for process energy and at least two advanced 

technologies from Table V.C–6).

Ethanol .................................................. Corn starch .......................................... All of the following: 6 (renewable fuel) 

Dry mill process, using natural gas, 

biomass or biogas for process energy and one of the advanced technologies from Table V.C–6 plus drying no more than 65% of the DGS it 

markets annually.

Ethanol .................................................. Corn starch .......................................... All of the following: 6 (renewable fuel) 

Dry mill process, using natural gas, 

biomass or biogas for process energy and drying no more than 50% 

of the DGS it markets annually.

Ethanol .................................................. Corn starch .......................................... Wet mill process using biomass or 

biogas for process energy.

6 (renewable fuel) 

Ethanol .................................................. Starches from agricultural residues; 

starches from annual cover crops.

Fermentation using natural gas, biomass or biogas for process energy.6 (renewable fuel) 

Biodiesel, and renewable diesel ........... Soy bean oil; One of the following: 4 (biomass-based 

diesel) 

Oil from annual cover crops ................ Trans-Esterification.

Algal oil ................................................ Hydrotreating.

Biogenic waste oils/fats/greases; Excluding processes that coprocess 

renewable biomass and petroleum.

Non-food grade corn oil.

Biodiesel, and renewable diesel ........... Soy bean oil; One of the following: 5 (Advanced) 

Oil from annual cover crops ................ Trans-Esterification.

Algal oil ................................................ Hydrotreating.

Biogenic waste oils/fats/greases; Includes only processes that coprocess renewable biomass and petroleum.

Non-food grade corn oil.

Ethanol .................................................. Sugarcane ............................................ Fermentation (Any) .............................. 5 (Advanced) 

Ethanol .................................................. Cellulosic Biomass from agricultural 

residues, slash, forest thinnings, forest product residues, annual cover 

crops, switchgrass and miscanthus; 

cellulosic components of separated 

yard wastes; cellulosic components 

of separated food wastes; and cellulosic components of separated 

MSW.

Any ....................................................... 3 (Cellulosic Biofuel) 

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TABLE V.C–7—D-CODE DESIGNATIONS—Continued 

Fuel type Feedstock Production process 

requirements D-Code 

Cellulosic Diesel, Jet Fuel and Heating 

Oil.

Cellulosic Biomass from agricultural 

residues, slash, forest thinnings, forest product residues, annual cover 

crops, switchgrass and miscanthus; 

cellulosic components of separated 

yard wastes, cellulosic components 

of separated food wastes, and cellulosic components of separated 

MSW.

Any ....................................................... 7 (Cellulosic Biofuel 

or Biomass-Based 

Diesel) 

Butanol .................................................. Corn starch .......................................... Fermentation; dry mill using natural 

gas, biomass or biogas for process 

energy.

6 (renewable fuel) 

Cellulosic Naphtha ................................ Cellulosic Biomass from agricultural 

residues, slash, forest thinnings, forest product residues, annual cover 

crops, switchgrass and miscanthus; 

cellulosic components of separated 

yard wastes, cellulosic components 

of separated food wastes, and cellulosic components of separated 

MSW.

Fischer-Tropsch process ..................... 3 (Cellulosic Biofuel) 

Ethanol, renewable diesel, jet fuel, 

heating oil, and naphtha.

The non-cellulosic portions of separated food wastes.Any ....................................................... 5 (Advanced) 

Biogas ................................................... Landfills, sewage and waste treatment 

plants, manure digesters.

Any ....................................................... 5 (Advanced) 

Pathways for which we have not made 

a threshold compliance decision: The 

pathways identified in the Table V.C–6 

represent those pathways we have 

analyzed and determined meet the 

applicable thresholds as establish by 

EISA. We did not analyze all pathways 

that might be feasible through 2022. In 

some cases, we did not have sufficient 

time to complete the necessary lifecycle 

GHG impact assessment for this final 

rule. In addition to the pathways 

identified in Table V.C–6, EPA 

anticipates modeling grain sorghum 

ethanol, woody pulp ethanol, and palm 

oil biodiesel after this final rule and 

including the determinations in a 

rulemaking within 6 months. Based on 

current and projected commercial 

trends and the status of current analysis 

at EPA, biofuels from these three 

pathways are either currently being 

produced or are planned production in 

the near-term. Our analyses project that 

they will be used in meeting the RFS2 

volume standard in the near-term. 

During the course of the NPRM 

comment period, EPA received detailed 

information on these pathways and is 

currently in the process of analyzing 

these pathways. We have received 

comments on several additional 

feedstock/fuel pathways, including 

rapeseed/canola, camelina, sweet 

sorghum, wheat, and mustard seed, and 

we welcome parties to utilize the 

petition process described below to 

request EPA to examine additional 

pathways. 

In other cases, we have not modeled 

the lifecycle GHG performance of 

pathways because we did not have 

sufficient information. For those fuel 

pathways that are different than those 

pathways EPA has listed in today’s 

regulations, EPA is establishing a 

petition process whereby a party can 

petition the Agency to consider new 

pathways for GHG reduction threshold 

compliance. The petition process is 

meant for parties with serious intention 

to moved forward with production via 

the petitioned fuel pathway and who 

have moved sufficiently forward in the 

business process to show feasibility of 

the fuel pathway’s implementation. The 

Agency will not consider frivolous 

petitions with insufficient information 

and clarity for Agency analysis. In 

addition, if the petition addresses a fuel 

pathway that already complies for one 

or more types of renewable fuels under 

RFS (e.g., renewable fuel or advanced 

biofuel), the pathway must have the 

potential to result in the pathway 

qualifying for a new renewable fuel 

category for which it was not previously 

qualified. Thus, for example, the 

Agency will not undertake any 

additional review for a party wishing to 

get a modified LCA value for a 

previously approved fuel pathway if the 

desired new value would not change the 

overall pathway classification. EPA will 

process these petitions as expeditiously 

as possible, taking into consideration 

that some fuel pathways are closer to 

the commercial production stage than 

others. In all events, parties are 

expected to begin this process with 

ample lead time as compared to their 

commercial start dates. 

In addition to the technical 

information described below and listed 

in today’s regulations (see § 80.1416), a 

petition must include all information 

required in the registration process 

except the engineering review. The 

petition should demonstrate technical 

and commercial feasibility. For 

example, a petition could include 

copies of applications for air or 

construction permits, copies of blue 

prints of the facility, or photographs of 

the facility or pilot plant. The petition 

must include information necessary to 

allow EPA to effectively determine the 

lifecycle green house gas emissions of 

the fuel. The petitioner must describe 

the alternative production facility 

technology applied and supply data 

establishing the energy savings that will 

result from the use of the alternative 

technology. The information required 

would include, at a minimum, a mass 

and energy balance for the proposed 

fuel production process. This would 

include for example, mass inputs of raw 

material feedstocks and consumables, 

mass outputs of fuel product produced 

as well as co-products and waste 

materials production. Energy inputs 

information should include fuels used 

by type, including purchased electricity. 

If steam or hot water is purchased, the 

source and fuel required for its 

generation would also be reported. 

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Energy output information should 

include energy content of the fuel 

product produced (with heating value 

specified) as well as energy content of 

any co-products. The petitioner should 

also report the extent to which excess 

electricity is generated and distributed 

outside the production facility. 

Information on co-products should 

include the expected use of the coproducts and their market value. All 

information should be provided in a 

format such that it can be normalized on 

a fuel output basis (for example, tons 

feedstock per gallon of fuel produced). 

Other process descriptions necessary to 

understand the fuel production process 

should be included (e.g., process 

modeling flowcharts). Any other 

relevant information, including that 

pertaining to energy saving technologies 

or other process improvements that 

document significant differences 

between the fuel production processes 

outlined in this rule and that used by 

the renewable fuel producer, should 

also be submitted with the petition. 

For fuel pathways that utilize 

feedstocks that have not yet been 

modeled for this rulemaking, the 

petition must also submit information 

on the feedstock. Information would 

include, at a minimum, the feedstock 

type and feedstock production source 

and data on the market value of the 

feedstock and current uses of the 

feedstock, if any. The petition should 

also include chemical input 

requirements (e.g., fertilizer, pesticides, 

etc.) and energy use in feedstock 

production listed by type of energy. 

Yield information would also be 

required for both the current yields of 

the feedstock as well as anticipated 

changes in feedstock yields over time. 

EPA will use the data supplied in the 

petition and other data and information 

available to the Agency to technically 

evaluate whether the information is 

sufficient for EPA to make a 

determination of the RFS standards for 

which the fuel pathway may qualify. If 

EPA determines that the petition is 

insufficient for determination, the 

petitioner will be so notified. If EPA 

determines it has been provided 

sufficient data from the petitioner to 

evaluate the fuel pathway, we will then 

proceed with any analyses required to 

make a technical determination of 

compliance. 

EPA anticipates that for some 

petitioned fuel pathways with unique 

modifications or enhancements to 

production technologies of pathways 

otherwise modeled for the regulations 

listed today, EPA may be able to 

evaluate the pathway as a reasonably 

straight-forward extension of our 

current assessments. We expect such a 

determination would be pathway 

specific, and would be based on a 

technical analysis that compared the 

applicant fuel pathway to the fuel to 

pathway(s) that had already been 

analyzed. In these cases, EPA would be 

able to make a determination without 

proceeding through a full rulemaking 

process. For example, petitions may 

submit unique biofuel production 

facility configurations, operations, or coproduct pathways that could result in 

greater efficiencies than the pathways 

modeled for this rulemaking, but 

otherwise do not differ greatly from the 

modeled fuel pathways. In such cases, 

we would expect to make a decision for 

that specific pathway without 

conducting a full rulemaking process. 

We would expect to evaluate whether 

the pathway is consistent with the 

definitions of renewable fuel types in 

the regulations, generally without going 

through rulemaking, and issue an 

approval or disapproval that applies to 

the petitioner. We anticipate that we 

will subsequently propose to add the 

pathway to the regulations. 

If EPA determines that a petitioned 

fuel pathway requires significant new 

analysis and/or modeling, EPA will 

need to give notice and seek public 

comment. For example, we anticipate 

that pathways with feedstocks or fuel 

types not yet modeled by EPA will 

require additional modeling and public 

comment before a determination of 

compliance can be made. In these cases, 

the determination would be 

incorporated into the annual rulemaking 

process established in today’s 

regulations. 

When EPA makes a technical 

determination is made that a petitioned 

fuel pathway qualifies for a RFS volume 

standard, a D-code will be assigned to 

the fuel pathway. We anticipate that 

renewable fuel producers and importers 

will be able to generate RINs for the 

additional pathway after the next 

available update of the EPA Moderated 

Transaction System (EMTS) that follows 

a determination. EPA expects to update 

the EMTS quarterly, as long as 

necessary. Renewable fuel producers 

will be able to register the fuel pathway 

through the EPA Fuels Programs 

Registration System two weeks after the 

date of determination, but as described 

above, will not be able to generate RINs 

until the quarterly EMTS update. 

In the proposal, we suggested a 

system of temporary D-codes for biofuel 

pathways we had not analyzed. This 

was proposed as a means of assuring no 

undue hardship for biofuel producers 

using feedstock sources or processing 

technologies not analyzed by EPA. As 

proposed, these producers could market 

their fuel on the basis of temporarily 

assigned D-codes. While the objective 

was sound, EPA now believes it is best 

to properly assure compliance with 

thresholds on the basis of completed 

lifecycle GHG assessments. As noted 

above, the Agency commits to expedited 

assessment and rulemaking for those 

pathways most likely to generate biofuel 

in the immediate future, including 

ethanol produced from grain sorghum, 

ethanol, woody pulp ethanol, and palm 

oil biodiesel. We also plan to continue 

to model additional pathways we expect 

will be commercially available in the 

U.S. as soon as sufficient information is 

available to complete a quality lifecycle 

assessment. For these reasons, EPA is 

not finalizing a provision for assigning 

temporary D-codes. 

D. Total GHG Reductions 

Similar to the analysis done in our 

proposal, our analysis of the overall 

GHG emission impacts of increased 

volumes of renewable fuel was 

performed in parallel with the lifecycle 

analysis performed to develop the 

individual fuel thresholds described in 

previous sections. The same sources of 

emissions 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. 

The main difference between the 

results of the proposal analysis and the 

final rule analysis are higher domestic 

land use change emissions in the final 

rule analysis. As was the case in the 

proposal, simply adding up the 

individual lifecycle results determined 

in Section V.C. multiplied by their 

respective volumes would yield a 

different assessment of the overall 

impacts. The two analyses are separate 

in that the overall 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. 

While individual fuel analysis 

generally had small domestic land use 

change emission impacts, the overall 

impacts had larger domestic land use 

change emissions. The primary reason 

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14798 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

182MiniCAM 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 (GHGs), 

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. 

183MAGICC 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. 

184The reference scenario is the MiniCAM 

reference (no climate policy) scenario used as the 

basis for the Representative Concentration Pathway 

RCP4.5 using historical emissions until 2005. This 

scenario is used because it contains a 

comprehensive suite of greenhouse and pollutant 

gas emissions including carbonaceous aerosols. The 

four RCP scenarios will be used as common inputs 

into a variety of Earth System Models for intermodel comparisons leading to the IPCC AR5 (Moss 

et al. 2008). The MiniCAM RCP4.5 is based on the 

scenarios presented in Clarke et al. (2007) with nonCO2 and pollutant gas emissions implemented as 

described in Smith and Wigley (2006). Base-year 

information has been updated to the latest available 

data for the RCP process. 

185 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/. 

for the difference in domestic land use 

change between 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. 

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 313 million 

metric tons of CO2-eq. emissions 

increase. There are, however, based on 

the biofuel use replacing petroleum 

fuels, GHG reductions in each year. 

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 4.15 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 VIII.C.3. 

This annualized value is based on 

converting the lump sum present values 

described above into their annualized 

equivalents. 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 138 million 

metrics tons of CO2-eq. emissions. 

We also considered the uncertainty in 

the international land use change 

emission estimates for the overall 

impacts. Based on the range of results 

for the international land use change 

emissions the overall annualized 

average emission reductions of 

increased volumes of renewable fuel 

could range from ¥136 to ¥140 million 

metrics tons of CO2-eq. emissions. 

E. Effects of GHG Emission Reductions 

and Changes in Global Temperature 

and Sea Level 

The reductions in CO2 and other 

GHGs associated with increased 

volumes of renewable fuel will affect 

climate change projections. GHGs mix 

well in the atmosphere and have long 

atmospheric lifetimes, so changes in 

GHG emissions will affect future climate 

for decades to centuries. Two common 

indicators of climate change are global 

mean surface temperature and global 

mean sea level rise. This section 

estimates the response in global mean 

surface temperature and global mean sea 

level rise projections to the estimated 

net global GHG emissions reductions 

associated with increased volumes of 

renewable fuel. 

EPA estimated changes in projected 

global mean surface temperatures to 

2050 using the MiniCAM (Mini Climate 

Assessment Model) integrated 

assessment model 182 coupled with the 

MAGICC (Model for the Assessment of 

Greenhouse-Gas Induced Climate 

Change) simple climate model.183

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 increased volumes of renewable 

fuel, a simple climate model such as 

MAGICC is reasonable for estimating the 

climate response. 

EPA applied the estimated annual 

GHG emissions changes for the final 

rule to a MiniCAM baseline emissions 

scenario.184 Specifically, the CO2, N2O, 

and CH4 annual emission changes from 

2022–2052 from Section V.D were 

applied as net reductions to this 

baseline scenario for each GHG. 

Table V.E–1 provides our estimated 

reductions in projected global mean 

surface temperatures and mean sea level 

rise associated with the reductions in 

GHG emissions due to the 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.185 To 

illustrate the time profile of the 

estimated reductions in projected global 

mean surface temperatures and mean 

sea level rise, we have also provided 

Figures V.E–1 and V.E–2. 

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186 IPCC WGI, 2007. 187 ‘‘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. 

188NOX and VOC are precursors to the criteria 

pollutant ozone; we group them with criteria 

pollutants in this chapter for ease of discussion. 

TABLE V.E–1—ESTIMATED REDUCTIONS IN PROJECTED GLOBAL MEAN SURFACE TEMPERATURE AND GLOBAL MEAN SEA

LEVEL RISE FROM BASELINE IN 2020–2050 

Climate sensitivity 

1.5 2 2.5 3 4.5 6 

Year Change in global mean surface temperatures (degrees Celsius) 

2020 ......................................................................................................... 0.000 0.000 0.000 0.000 0.000 0.000 

2025 ......................................................................................................... 0.000 0.000 0.000 0.000 0.000 0.000 

2030 ......................................................................................................... 0.000 0.000 0.000 0.000 0.000 0.000 

2035 ......................................................................................................... ¥0.001 ¥0.001 ¥0.001 ¥0.001 ¥0.001 ¥0.001 

2040 ......................................................................................................... ¥0.001 ¥0.001 ¥0.001 ¥0.001 ¥0.001 ¥0.001 

2045 ......................................................................................................... ¥0.001 ¥0.001 ¥0.001 ¥0.001 ¥0.002 ¥0.002 

2050 ......................................................................................................... ¥0.001 ¥0.001 ¥0.002 ¥0.002 ¥0.002 ¥0.002 

Year Change in global mean sea level rise (centimeters) 

2020 ......................................................................................................... 0.000 0.000 0.000 0.000 0.000 0.000 

2025 ......................................................................................................... 0.000 0.000 0.000 0.000 0.000 0.000 

2030 ......................................................................................................... ¥0.001 ¥0.001 ¥0.001 ¥0.001 ¥0.001 ¥0.001 

2035 ......................................................................................................... ¥0.002 ¥0.002 ¥0.002 ¥0.003 ¥0.003 ¥0.003 

2040 ......................................................................................................... ¥0.003 ¥0.004 ¥0.004 ¥0.005 ¥0.005 ¥0.006 

2045 ......................................................................................................... ¥0.005 ¥0.006 ¥0.006 ¥0.007 ¥0.008 ¥0.009 

2050 ......................................................................................................... ¥0.006 ¥0.008 ¥0.009 ¥0.009 ¥0.011 ¥0.012 

The results in Table V.E–1 and 

Figures V.E–1 and V.E–2 show small 

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.186 Although IPCC 

does not issue ‘‘best estimate’’ sea level 

rise projections, the model-based range 

across SRES scenarios is 18 to 59 cm by 

2099.187 While the distribution of 

potential temperatures in any particular 

year is shifting down, the shift is not 

uniform. The magnitude of the decrease 

is larger for higher climate sensitivities. 

The same pattern appears in the 

reductions in the sea level rise 

projections. Thus, we can conclude that 

the impact of increased volumes of 

renewable fuel is to lower the risk of 

climate change, as the probabilities of 

temperature increase and sea level rise 

are reduced. 

VI. How Would the Proposal Impact 

Criteria and Toxic Pollutant Emissions 

and Their Associated Effects? 

This section presents our assessment 

of the changes in emissions and air 

quality resulting from the increased 

renewable fuel volumes needed to meet 

the RFS2 standards. Increases in 

emissions of hydrocarbons, nitrogen 

oxides, particulate matter, and other 

pollutants are projected to lead to 

increases in population-weighted 

annual average ambient PM and ozone 

concentrations. The air quality impacts, 

however, are highly variable from region 

to region. Ambient PM2.5 is likely to 

increase in areas associated with biofuel 

production and transport and decrease 

in other areas; for ozone, many areas of 

the country will experience increases 

and a few areas will see decreases. 

Ethanol concentrations will increase 

substantially; for the other modeled air 

toxics there are some localized impacts, 

but relatively little impact on national 

average concentrations. 

A. Overview of Emissions Impacts 

Today’s action will affect the 

emissions of ‘‘criteria’’ pollutants (those 

pollutants for which EPA has 

established a National Ambient Air 

Quality Standard has been established), 

criteria pollutant precursors,188 and air 

toxics, which may affect overall air 

quality and health. Emissions are 

affected by the processes required to 

produce and distribute large volumes of 

biofuels required by today’s action and 

the direct effects of these fuels on 

vehicle and equipment emissions. As 

detailed in Chapter 3 of the Regulatory 

Impact Analysis (RIA), we have 

estimated emissions impacts of 

production and distribution-related 

emissions using the life cycle analysis 

methodology described in Section V 

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. 

In the proposal we analyzed a single 

renewable fuel volume scenario, largely 

dependent on ethanol, relative to three 

different reference cases, including the 

RFS1 base case. For today’s rule we are 

presenting emission impacts for three 

fuel volume scenarios relative to two 

reference cases (RFS1 mandate and 

AEO) to show a range of the possible 

effects of biofuels depending on the 

relative quantities of various biofuels 

that may be used to meet the overall 

renewable fuel requirements. We have 

also updated our modeling for the RFS1 

mandate reference case to better reflect 

the emissions for this case. Table VI.A– 

1 shows the fuel volumes for the two 

reference cases and all three control 

scenarios. Further discussion of these 

fuel volumes and the subcategories 

within each are available in Section 

IV.A. The emission impacts of the 

primary control scenario (22.2 Bgal of 

ethanol) are presented here relative to 

both reference cases. The corresponding 

results for all three control cases are 

available in Chapter 3 of the Regulatory 

Impact Analysis for this rule. 

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14800 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

189 ‘‘Analysis of Fuel Ethanol Transportation 

Activity and Potential Distribution Constraints,’’ 

Oak Ridge National Laboratory, U.S. Department of 

Energy, March 2009. 

TABLE VI.A–1—RENEWABLE FUEL VOLUMES FOR EACH REFERENCE CASE AND CONTROL SCENARIO

[Bgal/year in 2022] 

Scenario 

Ethanol 

Biodiesel Renewable 

diesel 

Cellulosic 

diesel Corn Cellulosic Imported Total 

RFS1 Ref ................................................. 7.046 0.0 0.0 7.046 0.303 0.0 0.0 

AEO Ref ................................................... 12.29 0.25 0.64 13.18 0.38 0.0 0.0 

Low Ethanol ............................................. 15.0 0.25 2.24 17.49 1.67 0.15 9.26 

Mid Ethanol (Primary) .............................. 15.0 4.92 2.24 22.16 1.67 0.15 6.52 

High Ethanol ............................................ 15.0 16.0 2.24 33.24 1.67 0.15 0.0 

There have been a number of other 

enhancements and corrections to the 

non-GHG emission inventory estimates 

since the NPRM, some of which were 

included in the air quality modeling 

inventories, while others occurred later 

than that. The major changes are 

mentioned here, and all the significant 

changes are explained in detail in 

Chapter 3 of the RIA. 

One significant change relates to the 

‘‘downstream’’ vehicle and equipment 

emission impacts of using the increased 

proportions of renewable fuels. In the 

proposal we provided two different 

analyses based on two different 

assumptions regarding the effects of E10 

and E85 versus E0 on exhaust emissions 

from cars and trucks. Those were 

referred to as ‘‘less sensitive’’ and ‘‘more 

sensitive’’ cases. Based on analysis of 

recent emissions test data conducted 

since publication of the NPRM, we are 

modeling a single case. As detailed in 

Section VI.C, the case modeled for the 

final rule is a hybrid approach, applying 

‘‘more sensitive’’ impacts for E10 and 

pre-Tier 2 light duty vehicles, and 

applying the ‘‘less sensitive’’ E10 effects 

for Tier 2 light duty cars and trucks, 

which means no impact for NOX or nonmethane hydrocarbons (NMHC). We 

have also updated our estimates of 

evaporative permeation impacts of E10 

based on recent studies. Finally, for the 

final rule inventories we are only 

claiming emission effects with use of 

E85 in flex-fueled vehicles relative to E0 

for two pollutants: ethanol and 

acetaldehyde, for which data suggests 

the effects are more certain. For the 

‘‘more sensitive case’’ presented in the 

NPRM, and used in the air quality 

modeling, we had estimated changes to 

additional pollutants (including 

significant PM reductions) based on 

some very limited data. Until such time 

as additional data is collected to 

enhance this analysis it is premature to 

use such assumptions. 

For ‘‘upstream’’ emissions associated 

with fuel production and distribution, 

the largest change that was included in 

the air quality modeling was the 

improved estimate of VOC and ethanol 

vapor emissions during ethanol 

transport, made possible by a detailed 

analysis of costs and transport modes 

conducted by Oak Ridge National 

Laboratory (ORNL).189 This change 

alone more than doubled the predicted 

overall increase in ethanol emissions 

from the increased use of renewable 

fuels, increasing the VOC enough to 

change the overall VOC impact from a 

decrease to a substantial increase. 

Significant updates have also been 

made to emissions from cellulosic 

biofuel plants, in part to reflect the 

assumed shift in volumes from 

cellulosic ethanol to diesel between the 

proposed and final rules. For cellulosic 

ethanol plants, after the air quality 

modeling was done we discovered that 

the calculation of emissions from these 

plants had been overestimated due to 

failing to account for the portion of 

biomass that is not used for process 

energy. This change decreases the 

estimated NOX and CO impacts, and 

shifts the PM impact of these plants 

from an increase to a small decrease. 

However, these changes are 

counterbalanced by varying degrees by 

shifting some of the cellulosic volume 

from ethanol to diesel, which requires 

nearly twice the biomass as needed by 

ethanol to produce one gallon. While 

the net effect of the changes in 

cellulosic plant emissions is a decrease 

in NOX and CO emission impacts 

relative to the proposal, the shift to 

cellulosic diesel under the primary 

scenario results in a larger increase in 

‘‘upstream’’ PM emissions than reported 

in the NPRM or used in the air quality 

analysis. 

Updates to agricultural modeling 

assumptions made between proposal 

and final had a significant impact on 

ammonia (NH3) emissions. Final 

modeling reflects an increase in 

fertilizer use with the primary control 

case, which results in a 1.2 percent 

increase in NH3 emissions, a change 

from the 0.5 percent decrease projected 

for the proposal and negligible impact 

used in the air quality analyses. 

Analysis of criteria and toxic emission 

impacts was performed for calendar 

year 2022, since this year reflects the 

full implementation of today’s rule. 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 analysis presented here provides 

estimates of the change in national 

emission totals that would result from 

the increased use of renewable fuels to 

meet the statutory requirements of EISA. 

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 the 

increased use of renewable fuels, so fullscale photochemical air quality 

modeling was also performed to 

accurately assess this. These localized 

impacts are discussed in Section VI.D. 

Our projected emission impacts for 

the primary renewable fuel scenario 

relative to the two reference cases are 

shown in Table VI.A–2 for 2022. This 

shows 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 that increases in the use of 

renewable fuels will result in significant 

increases in ethanol and acetaldehyde 

emissions—increasing the total U.S. 

inventories of these pollutants by 16–18 

percent in 2022 relative to the RFS1 

mandate case. We project more modest 

increases in NOX, HC, PM, 

formaldehyde, 1,3-butadiene, acrolein, 

and ammonia (NH3) relative to the RFS1 

mandate case. We project a 5 percent 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14801 

decrease in CO (due to impacts of 

ethanol on exhaust emissions from 

vehicles and nonroad equipment), and a 

2.4 percent decrease in benzene (due to 

displacement of gasoline with ethanol 

in the fuel pool). Impacts on SO2 and 

naphthalene are much smaller. Relative 

to the AEO reference case the results are 

similar directionally, but smaller in 

magnitude due to the less drastic 

differences in fuel volumes. 

TABLE VI.A–2—TOTAL COMBINED UPSTREAM AND DOWNSTREAM EMISSION IMPACTS IN 2022 FOR PRIMARY SCENARIO

RELATIVE TO EACH REFERENCE CASE

Pollutant 

RFS1 Mandate AEO 

Annual short 

tons 

% of total U.S. 

inventory 

Annual short 

tons 

% of Total 

U.S. inventory 

NOX .................................................................................................................. 247,604 1.95 184,820 1.45 

HC .................................................................................................................... 100,762 0.87 24,523 0.21 

PM10 ................................................................................................................. 69,013 1.92 63,323 1.76 

PM2.5 ................................................................................................................ 15,549 0.46 14,393 0.42 

CO .................................................................................................................... ¥2,869,842 ¥5.30 ¥376,419 ¥0.69 

Benzene ........................................................................................................... ¥4,264 ¥2.41 ¥1,004 ¥0.57 

Ethanol ............................................................................................................. 100,123 18.20 54,137 9.84 

1,3–Butadiene .................................................................................................. 224 1.70 59 0.45

Acetaldehyde ................................................................................................... 5,848 15.80 3,108 8.40 

Formaldehyde .................................................................................................. 355 0.48 130 0.17

Naphthalene ..................................................................................................... ¥1 ¥0.01 ¥4 ¥0.03 

Acrolein ............................................................................................................ 22 0.38 21 0.35 

SO2 .................................................................................................................. 3,286 0.04 5,065 0.06 

NH3 .................................................................................................................. 48,711 1.15 48,711 1.15 

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 increased use of 

renewable fuels were estimated in 

conjunction with the development of 

life cycle GHG emission impacts and the 

GHG emission inventories discussed in 

Section V. 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 V 

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 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). Per-gallon emission 

factors for new corn ethanol plants were 

updated based on EPA analysis of 

energy efficiency technologies currently 

available (such as combined heat and 

power) and their expected market 

penetrations. There are no new 

standards planned at this time that 

would offer any additional control of 

emissions from corn or cellulosic 

ethanol plants. EPA also updated the 

fuel and feedstock transport emission 

factors to account for recent EPA 

emission standards and modeling, such 

as the locomotive and commercial 

marine standards finalized in 2008, and 

revised heavy-duty truck emission rates 

contained in EPA’s draft MOVES2009 

model. EPA also modified the ethanol 

transport distances based on a detailed 

analysis of costs versus transport mode 

conducted by Oak Ridge National 

Laboratory. 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 reference case in 2022 are 

shown in Table VI.B–1 for the criteria 

pollutants, ammonia, ethanol and 

individual air toxic pollutants. 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 RFS1 mandate reference 

case. So the fertilizer and pesticide 

quantities, livestock counts, and total 

agricultural acres were the same for both 

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. 

The fuel production and distribution 

impacts of the increased use of 

renewable fuels 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 PM2.5, SOX and especially 

NOX are driven by stationary 

combustion emissions from the 

substantial increase in corn and 

cellulosic ethanol production. Biofuel 

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 also due to increases in 

agricultural chemical production and 

transport, while substantial PM 

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14802 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

190The impact of renewable diesel was not 

estimated for this analysis; 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. 

increases are also associated with 

fugitive dust from agricultural 

operations. Ammonia emissions are 

expected to increase substantially due to 

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 US 

total reference case emissions with 

RFS1 mandate ethanol volumes, 

increases of 4–13 percent 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 0.4–1 

percent. There are also very small 

decreases in benzene, 1,3-butadiene and 

naphthalene relative to the US total 

emissions. 

TABLE VI.B–1—‘‘UPSTREAM’’ FUEL PRODUCTION AND DISTRIBUTION IMPACTS OF THE PRIMARY SCENARIO IN 2022 

RELATIVE TO EACH REFERENCE CASE

Pollutant 

RFS1 mandate AEO 

Annual short 

tons 

% of Total 

U.S. inventory 

Annual short 

tons 

% of Total 

U.S. inventory 

NOX .................................................................................................................. 169,665 1.34 164,170 1.29 

HC .................................................................................................................... 77,014 0.67 19,737 0.17 

PM10 ................................................................................................................. 69,583 1.94 63,892 1.78 

PM2.5 ................................................................................................................ 15,864 0.47 14,707 0.43 

CO .................................................................................................................... 135,658 0.25 130,172 0.24 

Benzene ........................................................................................................... ¥231 ¥0.13 ¥236 ¥0.13 

Ethanol ............................................................................................................. 69,445 12.63 35,865 6.52 

1,3–Butadiene .................................................................................................. ¥1 ¥0.01 0 0.00 

Acetaldehyde ................................................................................................... 1,617 4.37 933 2.52 

Formaldehyde .................................................................................................. 293 0.39 187 0.25

Naphthalene ..................................................................................................... ¥8 ¥0.06 ¥6 ¥0.04 

Acrolein ............................................................................................................ 67 1.13 37 0.63 

SO2 .................................................................................................................. 3,266 0.04 5,044 0.06 

NH3 .................................................................................................................. 48,711 1.15 48,711 1.15 

C. Vehicle and Equipment Emission 

Impacts of Fuel Program 

The effects of the increased use of 

renewable fuels 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 the increased use of renewable 

fuels on gasoline vehicles, nonroad 

spark-ignited engines and portable fuel 

containers; E85 on cars and light trucks; 

biodiesel on diesel vehicles; and 

increased refueling events due to lower 

energy density of biofuels.190

In the proposal we provided two 

different analyses based on two different 

assumptions regarding the effects of E10 

and E85 on exhaust emissions from cars 

and trucks. Those were referred to as 

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

cases. Based on analysis of recent 

studies, today’s analysis is based on a 

hybrid of these two scenarios. As 

detailed in the RIA, EPA and other 

parties have been gathering additional 

data on the emission impacts of ethanol 

fuels on later model vehicles. Data 

available in time for this analysis 

supports the hypothesis of the ‘‘less 

sensitive’’ case that newer technology 

Tier 2 vehicles are generally able to 

control for changes to emissions 

associated with low level ethanol 

blends; for this analysis we therefore are 

not attributing any NOX or VOC impact 

to the use of E10 on these vehicles. The 

data does show sensitivity for older 

technology (pre-Tier 2) vehicles, so this 

analysis does attribute an increase in 

NOX and decrease in NMHC to the use 

of E10 in these vehicles. This analysis 

does not include any emission impacts 

with use of E85 in flex-fueled vehicles, 

except for increases in ethanol and 

acetaldehyde, as the limited data 

currently available is insufficient to 

quantify the impact with any degree of 

certainty. Overall the sensitivity of 

exhaust emissions to ethanol assumed 

for the final rule analysis is closer to the 

‘‘less sensitive’’ case presented in the 

proposal; and is generally less sensitive 

than the case used for the air quality 

modeling, as discussed in Section VI.D. 

We have also updated our estimates of 

E10 effects on permeation emissions 

from light-duty vehicles based on 

testing recently completed by the 

Coordinating Research Council (CRC), 

showing that the relative increase in 

VOC emissions is higher for newer 

technology vehicles. 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 unchanged from the 

proposal, and are based on an analysis 

of recent biodiesel testing, detailed in 

the RIA, showing a 2 percent increase in 

NOX with a 20 percent biodiesel blend, 

a 16 percent decrease in PM, and a 14 

percent decrease in HC. These results 

essentially confirm the results of an 

earlier EPA analysis. This analysis does 

not attribute any downstream emission 

impact from the use of renewable diesel 

or cellulosic-based diesel relative to 

conventional diesel due to their 

chemical similarity to diesel fuel and 

limited test data. 

Summarized vehicle and equipment 

emission impacts in 2022, updated as 

noted above, are shown in Table VI.C– 

1 relative to each reference case. 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. Additional 

breakdowns by mobile source category 

can be found in Chapter 3 of the RIA. 

Carbon monoxide, PM, benzene, and 

acrolein are projected to decrease in 

2022 as a result of the increased use of 

renewable fuels, while NOX, HC and the 

other air toxics, especially ethanol and 

acetaldehyde, are projected to increase 

due to the impacts of E10. 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14803 

TABLE VI.C–1—‘‘DOWNSTREAM’’ VEHICLE AND EQUIPMENT EMISSION IMPACTS OF THE PRIMARY SCENARIO IN 2022 

RELATIVE TO EACH REFERENCE CASE

Pollutant 

RFS1 Mandate AEO 

Annual short 

tons 

% of Total 

U.S. inventory 

Annual short 

tons 

% of Total 

U.S. inventory 

NOX .................................................................................................................. 77,939 0.61 20,650 0.16 

HC .................................................................................................................... 23,748 0.21 4,786 0.04 

PM10 ................................................................................................................. ¥569 ¥0.02 ¥569 ¥0.02 

PM2.5 ................................................................................................................ ¥315 ¥0.01 ¥315 ¥0.01 

CO .................................................................................................................... ¥3,005,500 ¥5.55 ¥506,591 ¥0.94 

Benzene ........................................................................................................... ¥4,033 ¥2.28 ¥768 ¥0.43 

Ethanol ............................................................................................................. 30,678 5.58 18,272 3.32 

1,3–Butadiene .................................................................................................. 225 1.71 59 0.45

Acetaldehyde ................................................................................................... 4,231 11.43 2,175 5.88 

Formaldehyde .................................................................................................. 62 0.08 ¥57 ¥0.08 

Naphthalene ..................................................................................................... 7 0.05 2 0.01 

Acrolein ............................................................................................................ ¥44 ¥0.75 ¥16 ¥0.28 

SO2 .................................................................................................................. 21 0.00 21 0.00 

NH3 .................................................................................................................. 0 0.00 0 0.00

D. Air Quality Impacts 

Air quality modeling was performed 

to assess the projected impact of the 

renewable fuel volumes required by 

RFS2 on emissions of criteria and air 

toxic pollutants. Our air quality 

modeling reflects the impact of 

increased renewable fuel use required 

by RFS2 compared with two different 

reference cases that include the use of 

renewable fuels: A 2022 reference case 

projection based on the RFS1-mandated 

volume of 7.1 billion gallons of 

renewable fuels, and a 2022 reference 

case projection based on the AEO 2007 

volume of roughly 13.6 billion gallons 

of renewable fuels. Thus, the results 

represent the impact of an incremental 

increase in ethanol and other renewable 

fuels. We note that the air quality 

modeling results presented in this final 

rule do not constitute the ‘‘antibacksliding’’ analysis required by Clean 

Air Act section 211(v). EPA will be 

analyzing air quality impacts of 

increased renewable fuel use through 

that study and will promulgate 

appropriate mitigation measures under 

section 211(v), separate from this final 

action. 

It is critical to note that a key 

limitation of the analysis is that it 

employed interim emission inventories, 

which were somewhat enhanced 

compared to what was described in the 

proposal, but due to the timing of the 

analysis did not include some of the 

later enhancements and corrections of 

the final emission inventories presented 

in this FRM (see Section VI.A through 

VI.C of this preamble). Most 

significantly, our modeling of the air 

quality impacts of the renewable fuel 

volumes required by RFS2 relied upon 

interim inventories that assumed that 

ethanol will make up 34 of the 36 

billion gallon renewable fuel mandate, 

that approximately 20 billion gallons of 

this ethanol will be in the form of E85, 

and that the use of E85 results in fewer 

emissions of direct PM2.5 from vehicles. 

The emission impacts and air quality 

results would be different if, instead of 

E85, more non-ethanol biofuels are used 

or mid-level ethanol blends are 

approved. 

In fact, as explained in Section IV, our 

more recent analyses indicate that 

ethanol and E85 volumes are likely to be 

significantly lower than what we 

assumed in the interim inventories. 

Furthermore, the final emission 

inventories do not include vehiclerelated PM reductions associated with 

E85 use, as discussed in Section VI.A 

and VI.C of this preamble. There are 

additional, important limitations and 

uncertainties associated with the 

interim inventories that must be kept in 

mind when considering the results: 

• Error in PM2.5 emissions from 

locomotive engines 

After the air quality modeling was 

completed, we discovered an error in 

the way that PM2.5 emissions from 

locomotive engines were allocated to 

counties in the inventory. Although 

there was very little impact on nationallevel PM2.5 emissions, PM2.5 emission 

changes were too high in some counties 

and too low in others, by varying 

degrees. As a result, we do not present 

the modeling results for specific 

localized PM2.5 impacts. However, we 

have concluded that PM2.5 modeling 

results are still informative for nationallevel benefits assessment, as discussed 

at more length in Section VIII.D of this 

preamble and the RIA. 

• Sensitivity of light-duty vehicle 

exhaust emissions to ethanol blends 

As discussed above in Sections VI.A 

and VI.C of this preamble, the interim 

emission inventories used for the air 

quality modeling analysis are the ‘‘more 

sensitive’’ case described in the 

proposal. As a result, the interim 

inventories used for air quality 

modeling assume that vehicles 

operating on E10 have higher NOX

emissions and lower VOC, CO and PM 

exhaust emissions compared to the FRM 

inventories. 

• Cellulosic plant emissions 

The interim emission inventories 

used in air quality modeling generally 

assumed higher emissions from 

cellulosic plants than the FRM 

inventories, which used revised 

estimates based on updates to the 

fraction of biomass burned at these 

plants. However, as noted in Section 

VI.A, the shift of some cellulosic 

volume from ethanol to diesel results in 

higher PM emissions from cellulosic 

plants in the final rule inventories than 

used in the air quality modeling 

inventories. 

• Ethanol volume 

As mentioned above, the interim 

emission inventories used in our air 

quality modeling reflect the use of 

ethanol in about 34 of the mandated 36 

billion gallons and do not include any 

cellulosic diesel. As shown in Table 

VI.A–1, the FRM inventories assume 22 

billion gallons of ethanol in the primary 

case and 6.5 billion gallons of cellulosic 

diesel. The inventories used for air 

quality modeling assume ethanol 

volumes are more consistent with the 

FRM’s high-ethanol case inventory, 

which reflects the use of 33 billion 

gallons of ethanol and no cellulosic 

diesel. 

• Renewable fuel transport emissions 

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191US EPA (2009). Final Rule ‘‘Control of 

Emissions from New Marine Compression-Ignition 

Engines at or Above 30 Liters per Cylinder’’. (This 

rule was signed on December 18, 2009 but has not 

yet been published in the Federal Register. The 

signed version of the rule is available at http:// 

epa.gov/otaq/oceanvessels.htm). 

As discussed in Section 3.3, the 

estimates of renewable fuel transport 

volumes and distances differ between 

the air quality modeling and final rule 

inventories. 

In this section, we present 

information on current modeled levels 

of pollution as well as projections for 

2022, with respect to ambient PM2.5, 

ozone, selected air toxics, and nitrogen 

and sulfur deposition. The air quality 

modeling results indicate that ambient 

PM2.5 is likely to increase in areas 

associated with biofuel production and 

transport and decrease in other areas. 

The results of the air quality modeling 

also indicate that many areas of the 

country will experience increases in 

ambient ozone and a few areas will see 

decreases in ambient ozone as a result 

of the renewable fuel volumes required 

by RFS2. The modeling also shows that 

ethanol concentrations increase 

substantially with increases in 

renewable fuel volumes. For the other 

modeled air toxics, there are some 

localized impacts, but relatively little 

impact on national average 

concentrations. Our air quality 

modeling does not show substantial 

overall nationwide impacts on the 

annual total sulfur and nitrogen 

deposition occurring across the U.S. 

However, the air quality modeling 

results indicate that the entire Eastern 

half of the U.S. along with the Pacific 

Northwest would see increases in 

nitrogen deposition as a result of 

increased renewable fuel use. The 

results of the modeling also show that 

sulfur deposition will increase in the 

Midwest and in some rural areas of the 

west associated with biofuel production. 

The results are discussed in more detail 

below and in Section 3.4 of the RIA. 

We used the Community Multi-scale 

Air Quality (CMAQ) photochemical 

model, version 4.7, for our analysis. 

This version of CMAQ includes a 

number of improvements to previous 

versions of the model that are important 

in assessing impacts of the increased 

use of renewable fuels, including 

additional pathways for formation of 

soluble organic aerosols (SOA). These 

improvements are discussed in Section 

3.4 of the RIA. 

In addition to the limitations of the 

analysis that result from the use of 

interim emission inventories rather than 

the FRM inventories, there are 

uncertainties in the air quality analysis 

that should be noted. First, there are 

uncertainties inherent in the modeling 

process. Pollutants such as ozone, PM, 

acetaldehyde, formaldehyde, acrolein, 

and 1,3-butadiene can be formed 

secondarily through atmospheric 

chemical processes. These processes can 

be very complex, and there are 

uncertainties in emissions of precursor 

compounds and reaction pathways. In 

addition, simplifications of chemistry 

must be made in order to handle 

reactions of thousands of chemicals in 

the atmosphere. Another source of 

uncertainty involves the hydrocarbon 

speciation profiles, which are applied to 

the VOC inventories to break VOC down 

into individual constituent compounds 

which react in the atmosphere. Given 

the complexity of the atmospheric 

chemistry, the hydrocarbon speciation 

has an important influence on the air 

quality modeling results. Speciation 

profiles for a number of key sources are 

based on data with significant 

limitations. Finally, there are 

uncertainties in the surrogates used to 

allocate emissions spatially and 

temporally; this is particularly 

significant in projecting the location of 

new ethanol plants, especially future 

cellulosic biofuel plants. These plants 

can have large impacts on local 

emissions. A more detailed discussion 

of these and additional uncertainties 

and limitations associated with our air 

quality modeling is presented in Section 

3.4 of the RIA. 

1. Particulate Matter 

a. Current Levels 

PM2.5 concentrations exceeding the 

level of the PM2.5 NAAQS occur in 

many parts of the country. In 2005, EPA 

designated 39 nonattainment areas for 

the 1997 PM2.5 NAAQS (70 FR 943, 

January 5, 2005). These areas are 

composed of 208 full or partial counties 

with a total population exceeding 88 

million. The 1997 PM2.5 NAAQS was 

recently revised and the 2006 24-hour 

PM2.5 NAAQS became effective on 

December 18, 2006. On October 8, 2009, 

the EPA issued final nonattainment area 

designations for the 2006 24-hour PM2.5

NAAQS (74 FR 58688, November 13, 

2009). These designations include 31 

areas composed of 120 full or partial 

counties with a population of over 70 

million. In total, there are 54 PM2.5

nonattainment areas composed of 245 

counties with a population of 101 

million people. 

b. Projected Levels Without RFS2 

Volumes 

States with PM2.5 nonattainment areas 

are required to take action to bring those 

areas into compliance in the future. 

Areas designated as not attaining the 

1997 PM2.5 NAAQS will need to attain 

the 1997 standards in the 2010 to 2015 

time frame, and then maintain them 

thereafter. The 2006 24-hour PM2.5

nonattainment areas will be required to 

attain the 2006 24-hour PM2.5 NAAQS 

in the 2014 to 2019 time frame and then 

be required to maintain the 2006 24- 

hour PM2.5 NAAQS thereafter. 

EPA has already adopted many 

emission control programs that are 

expected to reduce ambient PM2.5 levels 

and which will assist in reducing the 

number of areas that fail to achieve the 

PM2.5 NAAQS. Even so, recent air 

quality modeling for the ‘‘Control of 

Emissions from New Marine 

Compression-Ignition Engines at or 

Above 30 Liters per Cylinder’’ rule 

projects that in 2020, at least 10 

counties with a population of almost 25 

million may not attain the 1997 annual 

PM2.5 standard of 15 μg/m3 and 47 

counties with a population of over 53 

million may not attain the 2006 24-hour 

PM2.5 standard of 35 μg/m3.191 These 

numbers do not account for those areas 

that are close to (e.g., within 10 percent 

of) the PM2.5 standards. These areas, 

although not violating the standards, 

will also benefit from any reductions in 

PM2.5 ensuring long-term maintenance 

of the PM2.5 NAAQS. 

c. Projected Levels With RFS2 Volumes 

We are not able to present air quality 

modeling results which detail changes 

in PM2.5 design values for specific local 

areas due to the error in the locomotive 

inventory mentioned in the introduction 

to this section. However, we do know 

that ambient PM2.5 increases in some 

areas of the country and decreases in 

other areas of the country. Ambient 

PM2.5 is likely to increase as a result of 

emissions at biofuel production plants 

and from biofuel transport, both of 

which are more prevalent in the 

Midwest. PM concentrations are likely 

to decrease in some areas due to 

reductions in SOA formation and 

reduced emissions from gasoline 

refineries. In addition, decreases in 

ambient PM are predicted because our 

modeling inventory assumed that E85 

usage reduces PM tailpipe emissions. 

The decreases in ambient PM from 

reductions in SOA and tailpipe 

emissions are likely to occur where 

there is a higher density of vehicles, 

such as the Northeast. See Section 

VIII.D for a discussion of the changes in 

national average population-weighted 

PM2.5 concentrations. 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14805 

192EPA recently proposed to reconsider the 2008 

NAAQS. Because of the uncertainty the 

reconsideration proposal creates regarding the 

continued applicability of the 2008 ozone NAAQS, 

EPA has used its authority to extend by 1 year the 

deadline for promulgating designations for those 

NAAQS. The new deadline is March 2011. EPA 

intends to complete the reconsideration by August 

31, 2010. 

2. Ozone 

a. Current Levels 

8-hour ozone concentrations 

exceeding the level of the ozone 

NAAQS occur in many parts of the 

country. In 2008, the U.S. EPA amended 

the ozone NAAQS (73 FR 16436, March 

27, 2008). The final 2008 ozone NAAQS 

rule set forth revisions to the previous 

1997 NAAQS for ozone to provide 

increased protection of public health 

and welfare. As of January 6, 2010 there 

are 51 areas designated as 

nonattainment for the 1997 8-hour 

ozone NAAQS, comprising 266 full or 

partial counties with a total population 

of over 122 million people. These 

numbers do not include the people 

living in areas where there is a future 

risk of failing to maintain or attain the 

1997 8-hour ozone NAAQS. The 

numbers above likely underestimate the 

number of counties that are not meeting 

the ozone NAAQS because the 

nonattainment areas associated with the 

more stringent 2008 8-hour ozone 

NAAQS have not yet been 

designated.192 Table VI.D–1 provides an 

estimate, based on 2005–07 air quality 

data, of the counties with design values 

greater than the 2008 8-hour ozone 

NAAQS of 0.075 ppm. 

TABLE VI.D–1—COUNTIES WITH DESIGN VALUES GREATER THAN THE 2008 OZONE NAAQS BASED ON 2005–2007 AIR

QUALITY DATA

Number of 

counties Population a

1997 Ozone Standard: Counties within the 51 areas currently designated as nonattainment (as of 1/6/10) ....... 266 122,343, 799 

2008 Ozone Standard: Additional counties that would not meet the 2008 NAAQSb ............................................ 227 41,285,262 

Total .................................................................................................................................................................. 493 163,629,061 

Notes: 

aPopulation numbers are from 2000 census data. 

bArea designations for the 2008 ozone NAAQS have not yet been made. Nonattainment for the 2008 Ozone NAAQS would be based on three 

years of air quality data from later years. Also, the county numbers in this row include only the counties with monitors violating the 2008 Ozone 

NAAQS. The numbers in this table may be an underestimate of the number of counties and populations that will eventually be included in areas 

with multiple counties designated nonattainment. 

b. Projected Levels Without RFS2 

Volumes 

States with 8-hour ozone 

nonattainment areas are required to take 

action to bring those areas into 

compliance in the future. Based on the 

final rule designating and classifying 8- 

hour ozone nonattainment areas for the 

1997 standard (69 FR 23951, April 30, 

2004), most 8-hour ozone nonattainment 

areas will be required to attain the 

ozone NAAQS in the 2007 to 2013 time 

frame and then maintain the NAAQS 

thereafter. EPA has recently proposed to 

reconsider the 2008 ozone NAAQS. If 

EPA promulgates different ozone 

NAAQS in 2010 as a result of the 

reconsideration, they would fully 

replace the 2008 ozone NAAQS and 

there would no longer be a requirement 

to designate areas for the 2008 NAAQS. 

EPA would designate nonattainment 

areas for a potential new 2010 primary 

ozone NAAQS based on the 

reconsideration of the 2008 ozone 

NAAQS in 2011. The attainment dates 

for areas designated nonattainment for a 

potential new 2010 primary ozone 

NAAQS are likely to be in the 2014 to 

2031 timeframe, depending on the 

severity of the problem. 

EPA has already adopted many 

emission control programs that are 

expected to reduce ambient ozone levels 

and assist in reducing the number of 

areas that fail to achieve the ozone 

NAAQS. Even so, our air quality 

modeling projects that in 2022, with all 

current controls but excluding the 

impacts of the renewable fuel volumes 

required by RFS2, up to 7 counties with 

a population of over 22 million may not 

attain the 2008 ozone standard of 0.075 

ppm (75 ppb). These numbers do not 

account for those areas that are close to 

(e.g., within 10 percent of) the 2008 

ozone standard. These areas, although 

not violating the standards, will also 

benefit from any reductions in ozone 

ensuring long-term maintenance of the 

ozone NAAQS. 

c. Projected Levels With RFS2 Volumes 

Our modeling indicates that the 

required renewable fuel volumes will 

cause increases in ozone design value 

concentrations in many areas of the 

country and decreases in ozone design 

value concentrations in a few areas. Air 

quality modeling of the expected 

impacts of the renewable fuel volumes 

required by RFS2 shows that in 2022, 

most counties with modeled data, 

especially those in the southeast U.S., 

will see increases in their ozone design 

values. These adverse impacts are likely 

due to increased upstream emissions of 

NOX in many areas that are NOX-limited 

(acting as a precursor to ozone 

formation). The majority of these design 

value increases are less than 0.5 ppb. 

The maximum projected increase in an 

8-hour ozone design value is in Morgan 

County, Alabama, 1.56 ppb and 1.27 

ppb when compared with the RFS1 

mandate and AEO 2007 reference cases 

respectively. As mentioned above there 

are some areas which see decreases in 

their ozone design values. This is likely 

due to VOC emission reductions at the 

tailpipe in urban areas that are VOClimited (reducing VOC’s role as a 

precursor to ozone formation). The 

maximum decrease projected in an 8- 

hour ozone design value is in Riverside, 

CA, 0.66 ppb and 0.6 ppb when 

compared with the RFS1 mandate and 

AEO 2007 reference cases respectively. 

On a population-weighted basis, the 

average modeled future-year 8-hour 

ozone design values are projected to 

increase by 0.28 ppb in 2022 when 

compared with the RFS1 mandate 

reference case and increase by 0.16 ppb 

when compared with the AEO 2007 

reference case. On a populationweighted basis the design values for 

those counties that are projected to be 

above the 2008 ozone standard in 2022 

will see decreases of 0.14 ppb when 

compared with the RFS1 mandate 

reference case and 0.15 ppb when 

compared with the AEO 2007 reference 

case. 

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14806 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

193U. S. EPA. (2009) 2002 National-Scale Air 

Toxics Assessment. http://www.epa.gov/ttn/atw/ 

nata2002/. 194U.S. Environmental Protection Agency (2007). 

Control of Hazardous Air Pollutants from Mobile 

Sources; Final Rule. 72 FR 8434, February 26, 2007. 195U.S. EPA. (2009) 2002 National-Scale Air 

Toxics Assessment. http://www.epa.gov/ttn/atw/ 

nata2002/. 

196 ‘‘Summary of recent findings for fuel effects of 

a 10% ethanol blend on light duty exhaust 

emissions’’, Memo from Aron Butler to Docket EPA– 

HQ–OAR–2005–0161. 

3. Air Toxics 

a. Current Levels 

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.193 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 

detail in U.S. EPA’s recent Mobile 

Source Air Toxics Rule.194 According to 

the National Air Toxic Assessment 

(NATA) for 2002,195 mobile sources 

were responsible for 47 percent of 

outdoor toxic emissions, over 50 percent 

of the cancer risk, and over 80 percent 

of the noncancer hazard. Benzene is the 

largest contributor to cancer risk of all 

124 pollutants quantitatively assessed in 

the 2002 NATA and mobile sources 

were responsible for 59 percent of 

benzene emissions in 2002. Over the 

years, EPA has implemented a number 

of mobile source and fuel controls 

resulting in VOC reductions, which also 

reduce benzene and other air toxic 

emissions. 

b. Projected Levels 

Our modeling indicates that, while 

there are some localized impacts, the 

renewable fuel volumes required by 

RFS2 have relatively little impact on 

national average ambient concentrations 

of the modeled air toxics. An exception 

is increased ambient concentrations of 

ethanol. For more information on the air 

toxics modeling results, see Section 3.4 

of the RIA for annual average results 

and Appendix 3A of the RIA for 

seasonal average results. Our discussion 

of the air quality modeling results 

focuses primarily on impacts of the 

renewable fuel volumes required by 

RFS2 in reference to the RFS1 mandate 

for 2022. Except where specifically 

discussed below, air quality modeling 

results of increased renewable fuel use 

with RFS2 as compared to the AEO 

2007 reference case are presented in 

Appendix 3A of this RIA. 

i. Acetaldehyde 

Our air quality modeling does not 

show substantial overall nationwide 

impacts on ambient concentrations of 

acetaldehyde as a result of the 

renewable fuel volumes required by this 

rule, although there is considerable 

uncertainty associated with the results. 

Annual percent changes in ambient 

concentrations of acetaldehyde are less 

than 1% for most of the country, and 

annual absolute changes in ambient 

concentrations of acetaldehyde are 

generally less than 0.1 μg/m3. Some 

urban areas show decreases in ambient 

acetaldehyde concentrations ranging 

from 1 to 10%, and some rural areas 

associated with new ethanol plants 

show increases in ambient acetaldehyde 

concentrations ranging from 1 to 10% 

with RFS2 volumes. This increase is 

due to an increase in emissions of 

primary acetaldehyde and precursor 

emissions from ethanol plants. A key 

reason for the decrease in urban areas is 

reductions in certain acetaldehyde 

precursors, primarily alkenes (olefins). 

Most ambient acetaldehyde is formed 

from secondary photochemical reactions 

of numerous precursor compounds, and 

many photochemical mechanisms are 

responsible for this process. 

The uncertainty associated with these 

results is described in more detail in 

Section 3.4 of the RIA. For example, 

some of the modeled decreases would 

likely become increases using data 

recently collected by EPA’s Office of 

Research and Development on the 

composition of hydrocarbon emissions 

from gasoline storage, gasoline 

distribution, and gas cans. Furthermore, 

as noted in the introduction to Section 

VI.D, the inventories used for air quality 

modeling may overestimate NOX, 

because they assumed that use of E10 

would lead to increases in NOX

emissions for later model year vehicles. 

The emission inventories for the final 

rule no longer make this assumption, 

based on recent EPA testing results.196

Because increases in NOX may result in 

more acetyl peroxy radical forming PAN 

rather than acetaldehyde, our air quality 

modeling results may underestimate the 

ambient concentrations of acetaldehyde. 

Some previous U.S. monitoring 

studies have suggested an insignificant 

or small impact of increased use of 

ethanol in fuel on ambient 

acetaldehyde, as discussed in more 

detail in Section 3.4 of the RIA. These 

studies suggest that increases in direct 

emissions of acetaldehyde are offset by 

decreases in the secondary formation of 

acetaldehyde. Other past studies have 

shown increases in ambient 

acetaldehyde with increased use of 

ethanol in fuel, although factors such as 

differences in vehicle fleet, lack of RVP 

control, and exclusion of upstream 

impacts may limit the ability of these 

studies to inform expected impacts on 

ambient air quality Given the conflicting 

results among past studies and the 

limitations of our analysis, considerable 

additional work is needed to address the 

impacts of the renewable fuel volumes 

required by this rule on ambient 

concentrations of acetaldehyde. 

ii. Formaldehyde 

Our air quality modeling results do 

not show substantial impacts on 

ambient concentrations of formaldehyde 

from the renewable fuel volumes 

required by this rule. Most of the U.S. 

experiences a 1% or less change in 

ambient formaldehyde concentrations. 

Decreases in ambient formaldehyde 

concentrations range between 1 and 5% 

in a few urban areas. Increases range 

between 1 and 2.5% in some rural areas 

associated with new ethanol plants; this 

result is due to increases in emissions 

of primary formaldehyde and 

formaldehyde precursors from the new 

ethanol plants. Absolute changes in 

ambient concentrations of formaldehyde 

are generally less than 0.1 μg/m3. 

iii. Ethanol 

Our modeling projects that the 

renewable fuel volumes required by this 

rule will lead to significant nationwide 

increases in ambient ethanol 

concentrations. Increases ranging 

between 10 to 50% are seen across most 

of the country. The largest increases 

(more than 100%) occur in urban areas 

with high amounts of on-road emissions 

and in rural areas associated with new 

ethanol plants. Absolute increases in 

ambient ethanol concentrations are 

above 1.0 ppb in some urban areas. 

Analysis of a modeling error that 

impacted ethanol emissions suggests 

that this error resulted in overestimates 

of ethanol impacts by more than 10% 

across much of the country. For a 

detailed discussion of this error, please 

refer to the emissions modeling TSD, 

found in the docket for this rule (EPA– 

HQ–OAR–2005–0161). 

iv. Benzene 

Our modeling projects that the 

renewable fuel volumes required by this 

rule will lead to small nationwide 

decreases in ambient benzene 

concentrations. Decreases in ambient 

benzene concentrations range between 1 

and 10% across most of the country and 

can be higher in a few urban areas. 

Absolute changes in ambient 

concentrations of benzene show 

reductions up to 0.2 μg/m3. 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14807 

v. 1,3-Butadiene 

The results of our air quality 

modeling show small increases and 

decreases in ambient concentrations of 

1,3-butadiene in parts of the U.S. as a 

result of increases in renewable fuel 

volumes required by RFS2. Generally, 

decreases occur in some southern areas 

of the country and increases occur in 

some northern areas and areas with high 

altitudes. Percent changes in 1,3- 

butadiene concentrations are over 50% 

in several areas; but the changes in 

absolute concentrations of ambient 1,3- 

butadiene are generally less than 0.005 

μg/m 3. Annual increases in ambient 

concentrations of 1,3-butadiene are 

driven by wintertime changes. These 

increases appear in rural areas with cold 

winters and low ambient levels but high 

contributions of emissions from 

snowmobiles, and a major reason for 

this modeled increase may be 

deficiencies in available emissions test 

data used to estimate snowmobile 1,3- 

butadiene emission inventories. 

vi. Acrolein 

Our air quality modeling shows small 

regional increases and decreases in 

ambient concentrations of acrolein as a 

result of increases in renewable fuel 

volumes required by this rule. Decreases 

in acrolein concentrations occur in 

some eastern and southern parts of the 

U.S. and increases occur in some 

northern areas and areas associated with 

new ethanol plants. Changes in absolute 

ambient concentrations of acrolein are 

between ± 0.001 μg/m3 with the 

exception of the increases associated 

with new ethanol plants. These 

increases can be up to and above 0.005 

μg/m3 with percent changes above 50% 

and are due to increases in emissions of 

acrolein from the new plants. Ambient 

acrolein increases in northern regions 

are driven by wintertime changes, and 

occur in the same areas of the country 

that have wintertime increases in 

ambient 1,3-butadiene. 1,3-butadiene is 

a precursor to acrolein, and these 

increases are likely associated with the 

same emission inventory issues in areas 

of high snowmobile usage seen for 1,3- 

butadiene, as described above. 

vii. Population Metrics 

To assess the impact of projected 

changes in ambient air toxics as a result 

of increases in renewable fuel volumes 

required by this rule, we developed 

population metrics that show the 

population experiencing increases and 

decreases in annual ambient 

concentrations of the modeled air 

toxics. Table VI.D–2 below illustrates 

the percentage of the population 

impacted by changes of various 

magnitudes in annual ambient 

concentrations with the renewable fuel 

volumes required by RFS2, as compared 

to the RFS1 mandate reference case. 

TABLE VI.D–2—PERCENT OF TOTAL POPULATION IMPACTED BY CHANGES IN ANNUAL AMBIENT CONCENTRATIONS OF

TOXIC POLLUTANTS: RFS2 COMPARE TO RFS1 MANDATE

Percent change in annual 

ambient concentration 

Acetaldehyde 

(percent) 

Acrolein 

(percent) 

Benzene 

(percent) 

1,3–Butadiene 

(percent) 

Ethanol 

(percent) 

Formaldehyde 

(percent) 

≤¥100 .............................. ............................ ............................ ............................ ............................ ............................ ............................

>¥100 to ≤¥50 .............. ............................ ............................ ............................ ............................ ............................ ............................

>¥50 to ≤¥10 ................ 0.76 ............................ 1.18 1.38 ............................ ............................

>¥10 to ≤¥5 .................. 8.17 0.18 12.92 28.11 ............................ ............................

>¥5 to ≤¥2.5 ................. 13.29 13.66 48.76 31.98 ............................ 4.11 

>¥2.5 to ≤¥1 ................. 25.26 40.13 23.60 12.87 ............................ 19.30 

>¥1 to <1 ........................ 52.24 36.03 13.55 19.37 ............................ 76.08 

≥1 to <2.5 ......................... 0.24 3.44 ............................ 1.53 ............................ 0.48 

≥2.5 to <5 ......................... 0.04 2.93 ............................ 1.13 0.22 0.01 

≥5 to <10 .......................... 0.02 2.00 ............................ 1.13 1.23 ............................

≥10 to <50 ........................ ............................ 1.51 ............................ 2.15 63.29 ............................

≥50 to <100 ...................... ............................ 0.08 ............................ 0.28 34.49 ............................

≥100 ................................. ............................ 0.05 ............................ 0.06 0.77 ............................

Table VI.D–3 shows changes in the 

population-weighted average ambient 

concentrations of air toxics that are 

projected to occur in 2022 with 

increased renewable fuel use as required 

by this rule. 

TABLE VI.D–3—POPULATION-WEIGHTED AVERAGE AMBIENT CONCENTRATIONS OF AIR TOXICS IN 2022 WITH RFS2 

RENEWABLE FUEL REQUIREMENTS

Population-weighted concentration 

(Annual average in μg/m 3) 

Population-weighted concentration 

(Annual average in μg/m 3) 

RFS2 v. RFS1 mandate reference case RFS2 v. AEO 2007 reference case 

RFS2 RFS1 

mandate 

Diff. 

RFS2– 

RFS1 

RFS2 AEO 2007 Diff. 

RFS2–AEO 

Acetaldehyde ................................................................... 1.590 1.618 ¥0.028 1.590 1.613 ¥0.023 

Acrolein ............................................................................ 0.017 0.018 ¥0.001 0.017 0.017 ¥0.0001 

Benzene ........................................................................... 0.520 0.535 ¥0.015 0.520 0.527 ¥0.007 

1,3-Butadiene ................................................................... 0.022 0.023 ¥0.001 0.022 0.230 ¥0.208 

Ethanol ............................................................................. 1.521 1.039 0.482 1.521 1.112 0.409 

Formaldehyde .................................................................. 1.549 1.558 ¥0.009 1.549 0.004 ¥0.006 

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14808 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

197U.S. EPA. U.S. EPA’s 2008 Report on the 

Environment (Final Report). U.S. Environmental 

Protection Agency, Washington, DC, EPA/600/R– 

07/045F (NTIS PB2008–112484). 

198U.S. EPA (2004). Air Quality Criteria for 

Particulate Matter. Volume I EPA600/P–99/002aF 

and Volume II EPA600/P–99/002bF. Retrieved on 

March 19, 2009 from Docket EPA–HQ–OAR–2003– 

0190 at http://www.regulations.gov/. 

199U.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–05–005a. Retrieved March 19, 2009 from 

http://www.epa.gov/ttn/naaqs/standards/pm/data/

pmstaffpaper_20051221.pdf. 

200The PM NAAQS is currently under review and 

the EPA is considering all available science on PM 

health effects, including information which has 

been published since 2004, in the development of 

the upcoming PM Integrated Science Assessment 

Document (ISA). A second draft of the PM ISA was 

completed in July 2009 and was submitted for 

review by the Clean Air Scientific Advisory 

Committee (CASAC) of EPA’s Science Advisory 

Board. Comments from the general public have also 

been requested. For more information, see http:// 

cfpub.epa.gov/ncea/cfm/recordisplay.

cfm?deid=210586. 

4. Nitrogen and Sulfur Deposition 

a. Current Levels 

Over the past two decades, the EPA 

has undertaken numerous efforts to 

reduce nitrogen and sulfur deposition 

across the U.S. Analyses of long-term 

monitoring data for the U.S. show that 

deposition of both nitrogen and sulfur 

compounds has decreased over the last 

17 years although many areas continue 

to be negatively impacted by deposition. 

Deposition of inorganic nitrogen and 

sulfur species routinely measured in the 

U.S. between 2004 and 2006 were as 

high as 9.6 kilograms of nitrogen per 

hectare per year (kg N/ha/yr) and 21.3 

kilograms of sulfur per hectare per year 

(kg S/ha/yr). The data show that 

reductions were more substantial for 

sulfur compounds than for nitrogen 

compounds. These numbers are 

generated by the U.S. national 

monitoring network and they likely 

underestimate nitrogen deposition 

because neither ammonia nor organic 

nitrogen is measured. In the eastern 

U.S., where data are most abundant, 

total sulfur deposition decreased by 

about 36% between 1990 and 2005, 

while total nitrogen deposition 

decreased by 19% over the same time 

frame.197

b. Projected Levels 

Our air quality modeling does not 

show substantial overall nationwide 

impacts on the annual total sulfur and 

nitrogen deposition occurring across the 

U.S. as a result of increased renewable 

fuel volumes required by this rule. For 

sulfur deposition, when compared to 

the RFS1 mandate reference case, the 

RFS2 renewable fuel volumes will result 

in annual percent increases in the 

Midwest ranging from 1% to more than 

4%. Some rural areas in the west, likely 

associated with new ethanol plants, will 

also have increases in sulfur deposition 

ranging from 1% to more than 4% as a 

result of the RFS2 renewable fuel 

volumes. When compared to the AEO 

2007 reference case, the changes are 

more limited. The Midwest will still 

have sulfur deposition increases ranging 

from 1% to more than 4%, but the size 

of the area with these changes will be 

smaller. The Pacific Northwest has 

minimal areas with increases in sulfur 

deposition when compared to the AEO 

2007 reference case. When compared to 

both the RFS1 mandate and AEO 2007 

reference cases, areas along the Gulf 

Coast in Louisiana and Texas will 

experience decreases in sulfur 

deposition of 2% to more than 4%. The 

remainder of the country will see only 

minimal changes in sulfur deposition, 

ranging from decreases of less than 1% 

to increases of less than 1%. For a map 

of 2022 sulfur deposition impacts and 

additional information on these 

impacts, see Section 3.4.2.2 of the RIA. 

Overall, nitrogen deposition impacts 

in 2022 resulting from the renewable 

fuel volumes required by RFS2 are more 

widespread than the sulfur deposition 

impacts. When compared to the RFS1 

mandate 2007 reference case, nearly the 

entire eastern half of the United States 

will see nitrogen deposition increases 

ranging from 0.5% to more than 2%. 

The largest increases will occur in the 

states of Illinois, Michigan, Indiana, 

Wisconsin, and Missouri, with large 

portions of each of these states seeing 

nitrogen deposition increases of more 

than 2%. The Pacific Northwest will 

also experience increases in nitrogen of 

0.5% to more than 2%. When compared 

to the AEO 2007 reference case, the 

changes in nitrogen deposition are more 

limited. The eastern half of the United 

States will still see nitrogen deposition 

increases ranging from 0.5% to more 

than 2%; however, the size of the area 

with these changes will be smaller. 

Increases of more than 2% will 

primarily occur only in Illinois, Indiana, 

Michigan, and Missouri. Fewer areas in 

the Pacific Northwest will have 

increases in nitrogen deposition when 

compared to the AEO 2007 reference 

case. In both the RFS1 mandate and 

AEO 2007 reference cases, the Mountain 

West and Southwest will see only 

minimal changes in nitrogen deposition, 

ranging from decreases of less than 

0.5% to increases of less than 0.5%. A 

few areas in Minnesota and western 

Kansas would experience reductions of 

nitrogen up to 2%. See Section 3.4.2.2 

of the RIA for a map and additional 

information on nitrogen deposition 

impacts. 

E. Health Effects of Criteria and Air 

Toxics Pollutants 

1. Particulate Matter 

a. Background 

Particulate matter is a generic term for 

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. Since 1987, 

EPA has delineated that subset of 

inhalable particles small enough to 

penetrate to the thoracic region 

(including the tracheobronchial and 

alveolar regions) of the respiratory tract 

(referred to as thoracic particles). 

Current NAAQS use PM2.5 as the 

indicator for fine particles (with PM2.5

referring to particles with a nominal 

mean aerodynamic diameter less than or 

equal to 2.5 μm), and use PM10 as the 

indicator for purposes of regulating the 

coarse fraction of PM10 (referred to as 

thoracic coarse particles or coarsefraction particles; generally including 

particles with a nominal mean 

aerodynamic diameter greater than 2.5 

μm and less than or equal to 10 μm, or 

PM10–2.5). Ultrafine particles are a subset 

of fine particles, generally less than 100 

nanometers (0.1 μm) in aerodynamic 

diameter. 

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 EPA’s 2004 

Particulate Matter Air Quality Criteria 

Document (PM AQCD) and the 2005 PM 

Staff Paper.198 199 200 Further discussion 

of health effects associated with PM can 

also be found in the RIA for this rule. 

Health effects associated with shortterm exposures (hours to days) to 

ambient PM include premature 

mortality, aggravation of cardiovascular 

and lung disease (as indicated by 

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201U.S. EPA. (2006). National Ambient Air 

Quality Standards for Particulate Matte. 71 FR 

61144, October 17, 2006. 

202 Ku ̈nzli, N., Jerrett, M., Mack, W.J., et al. 

(2004). Ambient air pollution and atherosclerosis in 

Los Angeles. Environ Health Perspect.,113, 201– 

206. 

203This study is included in the 2006 Provisional 

Assessment of Recent Studies on Health Effects of 

Particulate Matter Exposure. The provisional 

assessment did not and could not (given a very 

short timeframe) undergo the extensive critical 

review by CASAC and the public, as did the PM 

AQCD. The provisional assessment found that the 

‘‘new’’ studies expand the scientific information and 

provide important insights on the relationship 

between PM exposure and health effects of PM. The 

provisional assessment also found that ‘‘new’’ 

studies generally strengthen the evidence that acute 

and chronic exposure to fine particles and acute 

exposure to thoracic coarse particles are associated 

with health effects. Further, the provisional science 

assessment found that the results reported in the 

studies did not dramatically diverge from previous 

findings, and taken in context with the findings of 

the AQCD, the new information and findings did 

not materially change any of the broad scientific 

conclusions regarding the health effects of PM 

exposure made in the AQCD. However, it is 

important to note that this assessment was limited 

to screening, surveying, and preparing a provisional 

assessment of these studies. For reasons outlined in 

Section I.C of the preamble for the final PM NAAQS 

rulemaking in 2006 (see 71 FR 61148–49, October 

17, 2006), EPA based its NAAQS decision on the 

science presented in the 2004 AQCD. 

204 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. Retrieved on March 19, 2009 from 

http://content.nejm.org/cgi/content/full/329/24/ 

1753. 

205Pope, C.A., III, Thun, M.J., Namboodiri, M.M., 

Dockery, D.W., Evans, J.S., Speizer, F.E., and Heath, 

C.W., Jr. (1995). Particulate air pollution as a 

predictor of mortality in a prospective study of U.S. 

adults. Am. J. Respir. Crit. Care Med, 151, 669–674. 

206 Krewski, D., Burnett, R.T., Goldberg, M.S., et 

al. (2000). Reanalysis of the Harvard Six Cities 

study and the American Cancer Society study of 

particulate air pollution and mortality. A special 

report of the Institute’s Particle Epidemiology 

Reanalysis Project. Cambridge, MA: Health Effects 

Institute. Retrieved on March 19, 2009 from 

http://es.epa.gov/ncer/science/pm/hei/ReanExecSumm.pdf. 

207Pope, C. A., III, Burnett, R.T., Thun, M. J., 

Calle, E.E., Krewski, D., Ito, K., Thurston, G.D., 

(2002). Lung cancer, cardiopulmonary mortality, 

and long-term exposure to fine particulate air 

pollution. J. Am. Med. Assoc., 287, 1132–1141. 

208U.S. EPA. (2006). Air Quality Criteria for 

Ozone and Related Photochemical Oxidants (Final). 

EPA/600/R–05/004aF–cF. Washington, DC: U.S. 

EPA. Retrieved on March 19, 2009 from Docket 

EPA–HQ–OAR–2003–0190 at http:// 

www.regulations.gov/. 

209U.S. EPA. (2006). Air Quality Criteria for 

Ozone and Related Photochemical Oxidants (Final). 

EPA/600/R–05/004aF–cF. Washington, DC: U.S. 

EPA. Retrieved on March 19, 2009 from Docket 

EPA–HQ–OAR–2003–0190 at http:// 

www.regulations.gov/. 

210U.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. Washington, DC, U.S. EPA. Retrieved on 

March 19, 2009 from Docket EPA–HQ–OAR–2003– 

0190 at http://www.regulations.gov/. 211National Research Council (NRC), 2008. 

Estimating Mortality Risk Reduction and Economic 

Benefits from Controlling Ozone Air Pollution. The 

National Academies Press: Washington, DC. 

increased hospital admissions and 

emergency department visits), increased 

respiratory symptoms including cough 

and difficulty breathing, decrements in 

lung function, altered heart rate rhythm, 

and other more subtle changes in blood 

markers related to cardiovascular 

health.201 Long-term exposure to PM2.5

and sulfates has also been associated 

with mortality from cardiopulmonary 

disease and lung cancer, and effects on 

the respiratory system such as reduced 

lung function growth or development of 

respiratory disease. A new analysis 

shows an association between long-term 

PM2.5 exposure and a subclinical 

measure of atherosclerosis.202 203

Studies examining populations 

exposed over the long term (one or more 

years) to different levels of air pollution, 

including the Harvard Six Cities Study 

and the American Cancer Society Study, 

show associations between long-term 

exposure to ambient PM2.5 and both all 

cause and cardiopulmonary premature 

mortality.204 205 206 In addition, an 

extension of the American Cancer 

Society Study shows an association 

between PM2.5 and sulfate 

concentrations and lung cancer 

mortality.207

2. Ozone 

a. Background 

Ground-level ozone pollution is 

typically formed by the reaction of VOC 

and 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.208 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 Air Quality 

Criteria Document (ozone AQCD) and 

2007 Staff Paper.209 210 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.211 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 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 

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212U.S. EPA (2008). Integrated Science 

Assessment for Oxides of Nitrogen—Health Criteria 

(Final Report). EPA/600/R–08/071. Washington, 

DC,: U.S.EPA. Retrieved on March 19, 2009 from 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?

deid=194645. 

213U.S. EPA. (2008). Integrated Science 

Assessment (ISA) for Sulfur Oxides—Health 

Criteria (Final Report). EPA/600/R–08/047F. 

Washington, DC: U.S. Environmental Protection 

Agency. Retrieved on March 18, 2009 from 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?

deid=198843. 

214U.S. EPA (2000). Air Quality Criteria for 

Carbon Monoxide, EPA/600/P–99/001F. This 

document is available in Docket EPA–HQ–OAR– 

2004–0008. 

215U.S. EPA (2000). Air Quality Criteria for 

Carbon Monoxide, EPA/600/P–99/001F. This 

document is available in Docket EPA–HQ–OAR– 

2004–0008. 

216The CO NAAQS is currently under review and 

the EPA is considering all available science on CO 

health effects, including information which has 

been published since 2000, in the development of 

the upcoming CO Integrated Science Assessment 

Document (ISA). A second draft of the CO ISA was 

completed in September 2009 and was submitted 

for review by the Clean Air Scientific Advisory 

Committee (CASAC) of EPA’s Science Advisory 

Board. For more information, see http:// 

cfpub.epa.gov/ncea/cfm/recordisplay.

cfm?deid=213229. 

217U. S. EPA. 2002 National-Scale Air Toxics 

Assessment. http://www.epa.gov/ttn/atw/nata2002/

risksum.html. 

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 

suggestive evidence of a contribution of 

ozone to cardiovascular-related 

morbidity and non-accidental and 

cardiopulmonary mortality. 

3. NOX and SOX

a. Background 

Nitrogen dioxide (NO2) is a member of 

the NOX family of gases. Most NO2 is 

formed in the air through the oxidation 

of nitric oxide (NO) emitted when fuel 

is burned at a high temperature. SO2, a 

member of the sulfur oxide (SOX) family 

of gases, is formed from burning fuels 

containing sulfur (e.g., coal or oil 

derived), extracting gasoline from oil, or 

extracting metals from ore. 

SO2 and NO2 can dissolve in water 

vapor and further oxidize to form 

sulfuric and nitric acid which react with 

ammonia to form sulfates and nitrates, 

both of which are important 

components of ambient PM. The health 

effects of ambient PM are discussed in 

Section VI.D.1 of this preamble. NOX

along with non-methane hydrocarbon 

(NMHC) are the two major precursors of 

ozone. The health effects of ozone are 

covered in Section VI.D.2. 

b. Health Effects of NOX

Information on the health effects of 

NO2 can be found in the U.S. 

Environmental Protection Agency 

Integrated Science Assessment (ISA) for 

Nitrogen Oxides.212 The U.S. EPA has 

concluded that the findings of 

epidemiologic, controlled human 

exposure, and animal toxicological 

studies provide evidence that is 

sufficient to infer a likely causal 

relationship between respiratory effects 

and short-term NO2 exposure. The ISA 

concludes that the strongest evidence 

for such a relationship comes from 

epidemiologic studies of respiratory 

effects including symptoms, emergency 

department visits, and hospital 

admissions. The ISA also draws two 

broad conclusions regarding airway 

responsiveness following NO2 exposure. 

First, the ISA concludes that NO2

exposure may enhance the sensitivity to 

allergen-induced decrements in lung 

function and increase the allergeninduced airway inflammatory response 

following 30-minute exposures of 

asthmatics to NO2 concentrations as low 

as 0.26 ppm. In addition, small but 

significant increases in non-specific 

airway hyperresponsiveness were 

reported following 1-hour exposures of 

asthmatics to 0.1 ppm NO2. Second, 

exposure to NO2 has been found to 

enhance the inherent responsiveness of 

the airway to subsequent nonspecific 

challenges in controlled human 

exposure studies of asthmatic subjects. 

Enhanced airway responsiveness could 

have important clinical implications for 

asthmatics since transient increases in 

airway responsiveness following NO2

exposure have the potential to increase 

symptoms and worsen asthma control. 

Together, the epidemiologic and 

experimental data sets form a plausible, 

consistent, and coherent description of 

a relationship between NO2 exposures 

and an array of adverse health effects 

that range from the onset of respiratory 

symptoms to hospital admission. 

Although the weight of evidence 

supporting a causal relationship is 

somewhat less certain than that 

associated with respiratory morbidity, 

NO2 has also been linked to other health 

endpoints. These include all-cause 

(nonaccidental) mortality, hospital 

admissions or emergency department 

visits for cardiovascular disease, and 

decrements in lung function growth 

associated with chronic exposure. 

c. Health Effects of SOX

Information on the health effects of 

SO2 can be found in the U.S. 

Environmental Protection Agency 

Integrated Science Assessment for 

Sulfur Oxides.213 SO2 has long been 

known to cause adverse respiratory 

health effects, particularly among 

individuals with asthma. Other 

potentially sensitive groups include 

children and the elderly. During periods 

of elevated ventilation, asthmatics may 

experience symptomatic 

bronchoconstriction within minutes of 

exposure. Following an extensive 

evaluation of health evidence from 

epidemiologic and laboratory studies, 

the EPA has concluded that there is a 

causal relationship between respiratory 

health effects and short-term exposure 

to SO2. Separately, based on an 

evaluation of the epidemiologic 

evidence of associations between shortterm exposure to SO2 and mortality, the 

EPA has concluded that the overall 

evidence is suggestive of a causal 

relationship between short-term 

exposure to SO2 and mortality. 

4. 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 exposures to lower levels of 

CO is most serious for those who suffer 

from cardiovascular disease, 

particularly those with angina or 

peripheral vascular disease. 

Epidemiological studies have suggested 

that exposure to ambient levels of CO is 

associated with increased risk of 

hospital admissions for cardiovascular 

causes, fetal effects, and possibly 

premature cardiovascular mortality. 

Healthy individuals also are affected, 

but only when they are exposed to 

higher CO levels. Exposure of healthy 

individuals 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.214

Additional information on CO related 

health effects can be found in the 

Carbon Monoxide Air Quality Criteria 

Document (CO AQCD).215 216

5. 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.’’217 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 

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218U.S. EPA .2009. National-Scale Air Toxics 

Assessment for 2002. http://www.epa.gov/ttn/atw/

nata2002. 

219U.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 http://www.epa.gov/iris/ 

subst/0290.htm. 

220U.S. Department of Health and Human 

Services National Toxicology Program 11th Report 

on Carcinogens available at: ntp.niehs.nih.gov/

index.cfm?objectid=32BA9724–F1F6–975E–

7FCE50709CB4C932. 

221 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. 

222U.S. EPA. 1991. Integrated Risk Information 

System File of Acetaldehyde. This material is 

available electronically at http://www.epa.gov/iris/ 

subst/0290.htm. 

223Appleman, 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. 

224Appleman, 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. 

225Myou, 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. 

226Sim VM, Pattle RE. Effect of possible smog 

irritants on human subjects JAMA165: 1980–2010, 

1957. 

227U.S. EPA (U.S. Environmental Protection 

Agency). (2003) Toxicological review of acrolein in 

support of summary information on Integrated Risk 

Information System (IRIS) National Center for 

Environmental Assessment, Washington, DC. EPA/ 

635/R–03/003. Available online at: http:// 

www.epa.gov/ncea/iris. 

228Weber-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 

229 Integrated Risk Information System File of 

Acrolein. Office of Research and Development, 

National Center for Environmental Assessment, 

Washington, DC. This material is available at 

http://www.epa.gov/iris/subst/0364.htm. 

230U.S. EPA (U.S. Environmental Protection 

Agency). (2003) Toxicological review of acrolein in 

support of summary information on Integrated Risk 

Information System (IRIS) National Center for 

Environmental Assessment, Washington, DC. EPA/ 

635/R–03/003. Available online at: http:// 

www.epa.gov/ncea/iris. 

231Morris JB, Symanowicz PT, Olsen JE, 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. 

232U.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. 

233 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. 

234U.S. EPA. 2000. Integrated Risk Information 

System File for Benzene. This material is available 

electronically at http://www.epa.gov/iris/subst/

0276.htm. 

235 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. 

236 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. 

(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 2002 National-scale 

Air Toxics Assessment (NATA).218

PAN, which is formed from precursor 

compounds by atmospheric processes, 

is not assessed in NATA. Emissions and 

ambient concentrations of compounds 

are discussed in Chapter 3 of the RIA 

and Section VI.D.3 of this preamble. 

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.219 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.220 221 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.222 In short-term (4 

week) rat studies, degeneration of 

olfactory epithelium was observed at 

various concentration levels of 

acetaldehyde exposure.223 224 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.225 The agency 

is currently conducting a reassessment 

of the health hazards from inhalation 

exposure to acetaldehyde. 

b. Acrolein 

Acrolein is extremely acrid and 

irritating to humans when inhaled, with 

acute exposure resulting in upper 

respiratory tract irritation, mucus 

hypersecretion and congestion. 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.226 These data and additional 

studies regarding acute effects of human 

exposure to acrolein are summarized in 

EPA’s 2003 IRIS Human Health 

Assessment for acrolein.227 Evidence 

available from studies in humans 

indicate that levels as low as 0.09 ppm 

(0.21 mg/m3) for five minutes may elicit 

subjective complaints of eye irritation 

with increasing concentrations leading 

to more extensive eye, nose and 

respiratory symptoms.228 Lesions to the 

lungs and upper respiratory tract of rats, 

rabbits, and hamsters have been 

observed after subchronic exposure to 

acrolein.229 Acute exposure effects in 

animal studies report bronchial hyperresponsiveness.230 In a recent study, the 

acute respiratory irritant effects of 

exposure to 1.1 ppm acrolein were more 

pronounced in mice with allergic 

airway disease by comparison to nondiseased mice which also showed 

decreases in respiratory rate.231 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. 

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.232 The IARC 

determined in 1995 that acrolein was 

not classifiable as to its carcinogenicity 

in humans.233

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 

genetic changes in both humans and 

animals and increased proliferation of 

bone marrow cells in mice.234 235 236 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 

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237 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. 

238U.S. Department of Health and Human 

Services National Toxicology Program 11th Report 

on Carcinogens available at: http://ntp.

niehs.nih.gov/go/16183. 

239Aksoy, M. (1989). Hematotoxicity and 

carcinogenicity of benzene. Environ. Health 

Perspect. 82: 193–197. 

240 Goldstein, B.D. (1988). Benzene toxicity. 

Occupational medicine. State of the Art Reviews. 3: 

541–554. 

241Rothman, 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. 

242U.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. 

243Qu, 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. 

244Qu, 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. 

245Lan, Qing, Zhang, L., Li, G., Vermeulen, R., et 

al. (2004) Hematotoxically in Workers Exposed to 

Low Levels of Benzene. Science 306: 1774–1776. 

246Turtletaub, 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. 

247U.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. 

248U.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. 

249 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. 

250U.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. 

251Bevan, 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. 

252 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. 

253U.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. 

254U.S. Department of Health and Human 

Services. 2000. 10th Special Report to the U.S. 

Congress on Alcohol and Health. June. 2000. 

benzene as a known human 

carcinogen.237 238

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.239 240

The most sensitive noncancer effect 

observed in humans, based on current 

data, is the depression of the absolute 

lymphocyte count in blood.241 242 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.243 244 245 246 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.247 248 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.249 250 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.251

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 2010. 

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.252 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.253 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 

consumption. Effects include 

neurological impairment, 

developmental effects, cardiovascular 

effects, immune system depression, and 

effects on the liver, pancreas and 

reproductive system.254 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 

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255 Goodlett CR, KH Horn, F Zhou. 2005. Alcohol 

teratogeniesis: mechanisms of damage and 

strategies for intervention. Exp. Biol. Med. 230:394– 

406. 256Riley EP, CL McGee. 2005. Fetal alcohol 

spectrum disorders: an overview with emphasis on 

changes in brain and behavior. Exp. Biol. Med. 

230:357–365. 257Zhang X, JH Sliwowska, J Weinberg. 2005. 

Prenatal alcohol exposure and fetal programming: 

effects on neuroendocrine and immune function. 

Exp. Biol. Med. 230:376–388. 258Riley 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. 259 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. 260World 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 261Chen W–JA, SE Maier, SE Parnell, FR West. 

2003. Alcohol and the developing brain: 

neuroanatomical studies. Alcohol Res. Health 

27:174–180. 262 Driscoll CD, AP Streissguth, EP Riley. 1990. 

Prenatal alcohol exposure comparability of effects 

in humans and animal models. Neurotoxicol. 

Teratol. 12:231–238. 

263U.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. 

264Hauptmann, M.; Lubin, J. H.; Stewart, P. A.; 

Hayes, R. B.; Blair, A. 2003. Mortality from 

lymphohematopoetic malignancies among workers 

in formaldehyde industries. Journal of the National 

Cancer Institute 95: 1615–1623. 

265Hauptmann, 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. 

266Beane Freeman, L. E.; Blair, A.; Lubin, J. H.; 

Stewart, P. A.; Hayes, R. B.; Hoover, R. N.; 

Hauptmann, M. 2009. Mortality from 

lymphohematopoietic malignancies among workers 

in formaldehyde industries: The National Cancer 

Institute cohort. J. National Cancer Inst. 101: 751– 

761. 

267Pinkerton, L. E. 2004. Mortality among a 

cohort of garment workers exposed to 

formaldehyde: an update. Occup. Environ. Med. 61: 

193–200. 

268Coggon, 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. 

269 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. 

270Agency 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. 

271WHO (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. 

272U.S. EPA. 2006. Air quality criteria for ozone 

and related photochemical oxidants (Ozone CD). 

Research Triangle Park, NC: National Cetner for 

Environmental Assesssment; report no. EPA/600/R– 

05/004aF–cF.3v. page 5–78 Available at http:// 

cfpub.epa.gov/ncea/. 

273U.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. page 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. 

274U.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. page 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. 

275U. 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. 

276Oak 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. 

memory.255 256 257 258 259 260 261 262 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.263 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.264 265 In an 

analysis of the lymphohematopoietic 

cancer mortality from an extended 

follow-up of these workers, NCI 

confirmed an association between 

lymphohematopoietic cancer risk and 

peak exposures.266 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.267 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.268

Recently, the IARC re-classified 

formaldehyde as a human carcinogen 

(Group 1).269

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.270 271

g. 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 

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.272

Effects of ground-level smog causing 

intense eye irritation have been 

attributed to photochemical oxidants, 

including PAN.273 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.274

h. 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.275 The draft reassessment 

completed external peer review.276

Based on external peer review 

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14814 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

277National 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. 

278 International Agency for Research on Cancer 

(IARC). (2002). Monographs on the Evaluation of 

the Carcinogenic Risk of Chemicals for Humans. 

Vol. 82. Lyon, France. 

279U. 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. 

280U.S. EPA Integrated Risk Information System 

(IRIS) database is available at: http://www.epa.gov/ 

iris. 

281National 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/. 282U.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. 283U.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. 284These 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. 

285U.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. 

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. 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.277

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.278 Naphthalene 

also causes a number of chronic noncancer effects in animals, including 

abnormal cell changes and growth in 

respiratory and nasal tissues.279

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 

final 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.280

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.281 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 

significant 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.282 283

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).284 In July 

1999, the regional haze rule (64 FR 

35714) was put in place to protect the 

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 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.285

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 

nitrogen via atmospheric deposition. 

The nitrogen-nutrient enrichment 

contributes to toxic algae blooms and 

zones of depleted oxygen, which can 

lead to fish kills, frequently in coastal 

waters. Deposition of heavy metals or 

other toxins may lead to the human 

ingestion of contaminated fish, human 

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 

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286U.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. 

287 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. 

288 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. 

289Lu, 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. 

290Marvin, 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. 

291Nouchi 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. 

292Oka 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. 

293Sun 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. 

294 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. 

295Thompson CR, G Kats. 1975. Effects of 

ambient concentrations of peroxyacetyl nitrate on 

navel orange trees. Env. Sci. Technol. 9:35–38. 

296Bytnerowicz A, ME Fenn. 1995. Nitrogen 

deposition in California forests: A Review. Environ. 

Pollut. 92:127–146. 

297US EPA. 1991. Effects of organic chemicals in 

the atmosphere on terrestrial plants. EPA/600/3–91/ 

001. 

investigated.286 287 288 289 290

Atmospheric deposition of nitrogen 

and sulfur contributes to acidification, 

altering biogeochemistry and affecting 

animal and plant life in terrestrial and 

aquatic ecosystems across the U.S. The 

sensitivity of terrestrial and aquatic 

ecosystems to acidification from 

nitrogen and sulfur deposition is 

predominantly governed by geology. 

Prolonged exposure to excess nitrogen 

and sulfur deposition in sensitive areas 

acidifies lakes, rivers and soils. 

Increased acidity in surface waters 

creates inhospitable conditions for biota 

and affects the abundance and 

nutritional value of preferred prey 

species, threatening biodiversity and 

ecosystem function. Over time, 

acidifying deposition also removes 

essential nutrients from forest soils, 

depleting the capacity of soils to 

neutralize future acid loadings and 

negatively affecting forest sustainability. 

Major effects include a decline in 

sensitive forest tree species, such as red 

spruce (Picea rubens) and sugar maple 

(Acer saccharum), and a loss of 

biodiversity of fishes, zooplankton, and 

macro invertebrates. 

In addition to the role nitrogen 

deposition plays in acidification, 

nitrogen deposition also causes 

ecosystem nutrient enrichment leading 

to eutrophication that alters 

biogeochemical cycles. Excess nitrogen 

also leads to the loss of nitrogen 

sensitive lichen species as they are 

outcompeted by invasive grasses as well 

as altering the biodiversity of terrestrial 

ecosystems, such as grasslands and 

meadows. For a broader explanation of 

the topics treated here, refer to the 

description in Section 3.6.2 of the RIA. 

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. 

Atmospheric deposition of pollutants 

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. Atmospheric deposition may 

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 

Elevated ozone levels contribute to 

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 

low 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 impaired 

photosynthesis, both of which can lead 

to reduced plant growth and 

reproduction, resulting in reduced crop 

yields, forestry production, and use of 

sensitive ornamentals in landscaping. In 

addition, the impairment of 

photosynthesis, the process by which 

the plant makes carbohydrates (its 

source of energy and food), can lead to 

a subsequent reduction in root growth 

and carbohydrate storage below ground, 

resulting in other, more subtle plant and 

ecosystems impacts. 

These latter impacts 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. Lastly, 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. Environmental 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).291 292 293 PAN has been 

demonstrated to inhibit photosynthetic 

and non-photosynthetic processes in 

plants and retard the growth of young 

navel orange trees.294 295 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 IX, 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.296

Volatile organic compounds (VOCs), 

some of which are considered air toxics, 

have long been suspected to play a role 

in vegetation damage.297 In laboratory 

experiments, a wide range of tolerance 

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298Cape 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. 

299Cape 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. 

300 Viskari E–L. 2000. Epicuticular wax of Norway 

spruce needles as indicator of traffic pollutant 

deposition. Water, Air, and Soil Pollut. 121:327– 

337. 301Ugrekhelidze D, F Korte, G Kvesitadze. 1997. 

Uptake and transformation of benzene and toluene 

by plant leaves. Ecotox. Environ. Safety 37:24–29. 

302 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. 

303 Kwaitkowski, J.R., Macon, A., Taylor, F., 

Johnston, D.B.; Industrial Crops and Products 23 

(2006) 288–296. 

304Shapouri, H., Gallagher, P.; USDA’s 2002 

Ethanol Cost-of-Production Survey (published July 

2005). 

305Projected 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. 

to VOCs has been observed.298

Decreases in harvested seed pod weight 

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.299

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.300 301 302 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. 

VII. 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 VIII.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. 303 304 The USDA models were 

adjusted to reflect the energy usage we 

anticipate for the average ethanol plant 

in 2022 and intermediate years, as well 

as the prices of energy and agricultural 

commodities as projected by AEO and 

the FASOM model respectively. 

For our policy case scenario, we used 

corn prices of $3.60/bu in 2022 with 

corresponding DDGS prices of $124.74/ 

ton (all 2007$). These estimates are 

taken from agricultural economics 

modeling work done for this rule using 

the Forestry and Agricultural Sector 

Optimization Model (see Section 

VIII.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 54% of the final pergallon cost, while utilities, facility, 

chemical and enzymes, and labor 

comprise about 22%, 13%, 7%, 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 RIA Section 1.4), which are 

presented by their projected 2022 

volume production share in Table 

VII.A.1–1 and cost impacts for each in 

Table VII.A.1–2.305

TABLE VII.A.1–1—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 

% 

Coal 

% 

Natural gas 

% 

Biogas 

% All fuels 

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 VII.A.1–2—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 ....................................................................... +$0.009 +$0.009 

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306Capital 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. 

TABLE VII.A.1–2—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 

Coal/Biomass Boiler + CHP .......................................................... ¥0.021 ¥0.021 

Natural Gas Boiler ......................................................................... ...................... ...................... baseline +$0.00 

Natural Gas Boiler + CHP ............................................................. ...................... ...................... ¥$0.032 

Total by Fuel Type .................................................................. ...................... ...................... ...................... ...................... ¥$0.006 

aAssumes biomass has same plant-delivered cost as coal. 

bAssumes biogas has same plant-delivered cost as natural gas. 

In addition to the primary fuel type 

used by ethanol production facilities, 

we also anticipate new technologies and 

efficiency improvements will impact the 

cost of ethanol production. More 

efficient motors and turbines are 

currently under development and are 

likely to be adopted by ethanol 

producers as ways to lower green house 

gas emissions and reduce energy costs. 

Several new process technologies, 

including corn oil extraction, corn 

fractionation, cold starch fermentation, 

and ethanol dehydration membranes 

will allow ethanol producers to further 

reduce energy consumption and 

produce higher value co-products. 

These technologies are discussed in 

sections 1.4.1.3 and 1.5.1.3 of the RIA. 

In order to reflect the cost advantages of 

ethanol producers using these 

technologies the USDA models were 

adapted to take into account the capital 

costs, lower energy usage, and higher 

value co-products that result from the 

adoption of these new technologies. The 

projected adoption rates of these 

technologies, and their impacts on the 

production cost of corn ethanol, are 

summarized in Table VII.A.1–3 below. 

More detail on how the USDA models 

were adjusted and the impact this had 

on the average price of ethanol 

production can be found in section 

4.1.1.1 of the RIA. 

TABLE VII.A.1–3—PROJECTED COST IMPACTS OR NEW CORN ETHANOL TECHNOLOGIES

Technology 

Percent of 

plants 

adopting 

technology 

(percent) 

Cost impact 

(change from 

baseline) 

Weighted 

cost impact 

More Efficient Boilers/Motors/Turbines ....................................................................... 100 Baseline ............................. $0.00/gal 

Raw Starch Hydrolysis ................................................................................................ 22 ¥$0.066/gal ....................... ¥$0.015/gal 

Corn Fractionation ...................................................................................................... 20 ¥$0.093/gal ....................... ¥$0.019/gal 

Corn Oil Extraction ...................................................................................................... 70 ¥$0.079/gal ....................... ¥$0.055/gal 

Membrane Separation ................................................................................................ 5 ¥$0.064/gal ....................... ¥$0.003/gal 

Total Cost Impact ................................................................................................ N/A N/A ..................................... ¥$0.092/gal 

Whether or not the distillers grains 

and solubles (DGS) are dried also has an 

impact on the cost of ethanol 

production. Drying the DGS is an energy 

intensive process and results in a 

significant increase in energy usages as 

well as cost. The advantages of dry DGS 

are reduced transportation costs and a 

product that is less susceptible to 

spoilage, and can therefore be sold to a 

much wider market. If the DGS can be 

sold wet, the cost of ethanol production 

can be reduced by $0.083 per gallon. A 

2007 survey of ethanol producers 

indicated that 37% of DGS were being 

sold wet. We anticipate that this 

percentage of wet DGS will remain 

constant in 2022. The net cost impact of 

selling 37% of the DGS wet is an 

average cost reduction of $0.031 per 

gallon. 

TABLE VII.A.1–4—AVERAGE ETHANOL

COST OF PRODUCTION

Baseline Cost of Production 

(Natural Gas, no new technologies, 100% dry DGS).

$1.627/gal 

Fuel Type Cost Impact ............. ¥$0.006/ 

gal 

New Technology Cost Impact .. ¥$0.092/ 

gal 

DGS Drying Cost Impact .......... ¥$0.031/ 

gal 

Average Cost of Ethanol Production (2022).$1.499/gal 

Based on energy prices from EIA’s 

Annual Energy Outlook (AEO) April 

2009 updated reference case ($116/bbl 

crude oil), we arrive at a production cost 

of $1.50/gal. More details on the ethanol 

production cost estimates can be found 

in Chapter 4 of the RIA. 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 

$97MM (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 $184MM.306 Despite the lower 

operating costs of coal and biomass fired 

plants the higher capital costs result, on 

average, ethanol produced in a facility 

using coal or biomass as a primary 

energy source results in a per-gallon 

cost $0.01/gal higher compared to 

production using natural gas. See 

Chapter 4.1 of the RIA for more details. 

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In this cost estimation work, we did 

not assume any pelletizing of DDGS. 

Pelletizing is expected to improve ease 

of shipment to more distant markets, 

which may become more important at 

the larger volumes projected for the 

future. However, while many in 

industry are aware of this technology, 

those we spoke with are not employing 

it in their plants, and do not expect 

widespread use in the foreseeable 

future. According to USDA’s model, 

pelletizing adds $0.035/gal to the 

ethanol production cost. 

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). 

Our feedstock supply analysis 

projected that energy crops would be 

the most abundant of the cellulosic 

feedstocks, comprising about 49% of the 

total biomass feedstock inventory. 

Agricultural residues, predominantly 

corn stover, make up approximately 

36% of the total, followed by MSW at 

approximately 15% and forestry residue 

at about 1%. 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 

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 68% 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 corn stover would 

cost $34.49 per dry ton at the farm gate. 

This reflects the cost to mow, rake, bale, 

and field haul the bales and replace 

nutrients. 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. Energy crops such as switchgrass 

and miscanthus would be harvested, 

baled, stored and transported in a 

manner very similar to crop residues. 

The FASOM model estimates switch 

grass, which we are using to be 

representative of all energy crops, 

would be available at farm side at a cost 

of $40.85. 

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 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 

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307Personal Communication, Eini C. Lowell, 

Research Scientist, USDA Forest Service 

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.307

As with agricultural residues and 

energy crops we relied on the FASOM 

model for road side costs for forestry 

residue. The FASOM model estimates 

costs for both hardwood and softwood 

logging residues. We anticipate that 

forestry residue for the production of 

cellulosic biofuels would be a mixture 

of both hard and soft woods. In order to 

obtain a cost for forest residues to be 

used as a feedstock for cellulosic 

biofuels we averaged the costs of the 

hardwood and softwood logging residue 

prices reported by FASOM. This 

resulted in a forestry residue price of 

$20.79 at the roadside. Note that this 

does not include the cost of the grinding 

operation that would be required before 

the forestry residues can be processed 

by the biofuel producer. 

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. 

In today’s regulation the definition of 

‘‘renewable biomass’’ includes the 

separated yard and food waste portion 

of MSW. As discussed in Section 

III.B.4.d, we are including as part of 

separated yard and food waste, 

incidental and post-recycled paper and 

wood wastes. Thus, firms planning on 

using MSW for producing cellulosic 

biofuels will be required to account for 

those components of the waste. We offer 

three methods for performing such 

accounting. One method is ‘‘feedstock 

accounting’’ in which the components of 

the waste stream are inventoried to 

obtain the fraction representing the 

portion of the waste stream that 

qualifies as renewable biomass. The 

second method is that upon verification 

that the food and yard waste is 

reasonably separated, that 100 percent 

of such waste may be counted as 

renewable biomass for purpose of 

generating RINs. Reasonable separation 

is considered to occur where curbside 

recycling is implemented, or where 

technologies are employed that ensure a 

maximum degree of separation, 

including but not limited to material 

recovery facilities. Under the second 

method, the renewable portion of the 

fuel so produced must be verified via a 

carbon dating method (ASTM D–6866 

method) which is specified and 

incorporated by reference in today’s 

regulation. The third method is the 

application of a default fraction of 50% 

to be applied to the waste stream 

purchased and used by the fuel 

producer. 

One method for sorting that would 

qualify to ensure reasonable separation 

has occurred is single stream recycling, 

in which the waste is sorted 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. The second is that the sorting 

occurs at the waste collection facility. 

The sorting would likely be done by 

hand or by automated equipment at the 

facility known as material recovery 

facilities (MRFs). 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. 

Another method 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. 

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 require 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 

uncontaminated 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 

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14820 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

308We plan on conducting a more thorough 

analysis of tipping fees by waste type for the final 

rulemaking. 

likely much lower, in the $30 per ton 

range.308

The wide variance in the cost of many 

of these areas affecting the final cost of 

MSW as a cellulosic feedstock, 

including costs for collecting and 

sorting MSW as well as the tipping fees 

for disposing of waste materials, makes 

approximating the cost of MSW a 

difficult task. Rather than attempt to 

build a model ourselves that would 

estimate the cost of sorted MSW, we 

decided to contact several companies 

that are currently planning on using 

MSW as a feedstock for cellulosic 

biofuel production. In confidential 

conversations with these companies 

they indicated that they believed that 

sorted MSW would be available at a 

near zero cost. In one case they had 

already begun securing MSW sources of 

feedstock for future biofuel production 

facilities. They indicated to us that 

while there would be a significant cost 

associated with sorting the MSW, this 

would be offset, or nearly so, by income 

generated from the sale of recovered 

materials (paper, metals, plastics, etc.) 

and the avoidance of tipping fees. There 

would still, however, be some costs 

associated with the transportation and 

disposal of materials unfit for the 

biofuels production process. Based on 

this information, we conservatively 

estimate that MSW would be available 

for use in a cellulosic biofuel 

production process at a cost of $15 per 

ton. See section 4.1 of the RIA for 

further discussion on the cost of MSW 

as a feedstock for cellulosic biofuels 

production. 

Secondary Storage and Transportation 

In addition to the roadside costs cited 

in the preceding sections, there will also 

be a cost to transport the cellulosic 

materials from the farm or forest to the 

production facility. We relied on our 

own cost analysis to determine the 

transportation costs. For MSW we do 

not anticipate any additional costs to 

transport the cellulosic material to the 

biofuel production facility if it is 

sourced from within the same county as 

the production facility. This is because 

this material is already being collected 

and transported to a sorting center 

landfill, and would simply be re-routed 

to the production facility. 

For agricultural residues, energy 

crops, and forestry residue, however, 

there will be additional costs associated 

with transporting them from the farm or 

forest side to the production facility. 

These costs are heavily dependent on 

the distance that the feedstock must be 

transported from the places where it is 

produced to the biofuel production 

facility. In order to estimate these costs 

we created a cost estimating tool that 

calculated transportation costs based on 

the distance the cellulosic material 

would have to be transported from the 

farm or forest side to the production 

facility. This tool relies on data 

provided by the National Agricultural 

Statistics Service for information on the 

availability and location of agricultural 

residue. Information on abandoned crop 

land, which was assumed to be the 

source of energy crops, was provided by 

Elliot Campbell at UC Davis. Data on the 

availability and location of forest 

residues was provided by the national 

forestry service. For more information 

on this secondary storage and 

transportation cost estimating tool that 

we used to estimate transportation costs 

see Chapter 4.1 of the RIA. 

We also believe that some cellulosic 

feedstocks will require secondary 

storage. Agricultural residues and 

energy crops will generally be harvested 

annually, sometimes in time periods as 

short as a few weeks in order to 

complete the harvest before the onset of 

winter weather. The large quantity of 

feedstock required for a commercial 

scale biofuel production plant makes it 

highly unlikely that a year’s worth of 

feedstock would be stored at the 

production facility. It is also unlikely 

that farmers would tolerate the baled 

agricultural residues or energy crops to 

be stored on their farms and transported 

to the production facility on an as 

needed basis unless they were 

compensated for the space bales occupy 

and damage done to their fields by the 

heavy traffic that would be involved in 

the collection of this material from their 

farms. Bales left exposed to the weather 

would also decompose much more 

rapidly resulting in a higher cost per ton 

of usable cellulosic material to biofuel 

producers. This loss would be 

minimized if the bales are stored in 

covered sheds. Our cost estimating tool 

takes these secondary storage costs into 

account for agricultural residues and 

energy crops. MSW and forestry 

residues have no secondary storage 

costs as they can be collected and 

transported on an as needed basis. 

Cellulosic Feedstock Cost Curve 

When the various costs described 

above are combined, together with the 

cost of grinding the cellulosic material 

($11/ton), the result is not a single cost, 

but rather a cost curve. This is due to 

the fact that each feedstock source has 

a unique price based on the FASOM 

estimate of the cost of production of the 

feedstock and the cost of transportation 

and secondary storage (if appropriate), 

where feedstocks have the lowest total 

cost in the parts of the country where 

the cellulosic plants are likely to be 

located. The cost per ton of feedstock is 

lower when the total production of 

cellulosic biofuel is low as the cheapest 

feedstocks are utilized first. As 

cellulosic biofuel production increases, 

so does the cost of cellulosic feedstocks, 

as more expensive sources of feedstock 

are used. The cost curve for cellulosic 

feedstocks for the production of up to 16 

billion ethanol equivalent gallons of 

cellulosic biofuels is shown in Graph 

VIII.A.1–1 below. The average cost of 

cellulosic feedstock at a production 

level of 16 billion ethanol equivalent 

gallons is $67.42, and is summarized in 

Table VII.A.1–5. 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14821 

TABLE VII.A.1–5—SUMMARY OF CELLULOSIC FEEDSTOCK COSTS

Ag Residue Switchgrass Forest Residue MSW 

36% of Total Feedstock ................. 49% of total Feedstock ................. 1% of Total Feedstock ................. 15% of Total Feedstock 

Mowing, Raking, Baling, Hauling, 

Nutrients and Farmer Payment 

$34.49/ton.

Mowing, Raking, Baling, Hauling, 

Nutrients and Farmer Payment 

$40.85/ton.

Harvesting, Hauling to Forest 

Edge, $20.79/ton.

Sorting, Contaminant Removal, 

Tipping Fees Avoided, $15/ton 

Hauling to Secondary Storage, Secondary Storage, Hauling to Plant 

$21.53/ton (average) 

Grinding 

$11/ton 

Total 

$67.42/ton 

ii. Production Costs for Cellulosic 

Biofuels 

In this section, we discuss the cost to 

biochemically and thermochemically 

convert cellulosic feedstocks into fuel 

ethanol. 

Biochemical 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 for EPA 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 nearterm improvements including the rapid 

improvements being made in enzyme 

technology. The year 2022 technology 

captures the cost of mature biochemical 

cellulosic plant technology. Table 

VII.A.1–6 summarizes NREL’s estimated 

and projected production costs for 

biochemical cellulosic ethanol plant 

technology for their projected year 2022 

technology in 2007 dollars reflecting a 

7 percent before tax rate of return on 

investment. The biochemical cellulosic 


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ethanol costs are based on a cellulosic 

feedstock cost of 67 per dry ton. 

TABLE VII.A.1–6—YEAR 2022 BIOCHEMICAL CELLULOSIC ETHANOL PRODUCTION COSTS PROVIDED BY NREL 

[2007 dollars and 7% before tax rate of return] 

Year technology 2022 

Plant Size .................................................................................................................................................................. 71 

MMgal/yr 

Capital Cost ............................................................................................................................................................... 199 

$MM 

$MM/yr c/gal 

Capital Cost 7% ROI before taxes ........................................................................................................................... 22 31 

Fixed Costs ............................................................................................................................................................... 8 12 

Feedstock Cost ......................................................................................................................................................... 52 73 

Other raw matl. costs ................................................................................................................................................ 12 16 

Enzyme Cost ............................................................................................................................................................. 5 8 

Enzyme nutrients ...................................................................................................................................................... 2 2 

Electricity ................................................................................................................................................................... ¥12 ¥16 

Waste disposal .......................................................................................................................................................... 1 1 

Total Costs ......................................................................................................................................................... 90 127 

Thermochemical Ethanol 

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 could then be 

converted into mixed alcohols, 

hydrocarbon fuels, chemicals, and 

power. In the case that the syngas is 

converted to ethanol, a possible means 

for doing so would be to pass the syngas 

over a catalyst which converts the 

syngas to mixed alcohols—mainly 

methanol. The methanol can be reacted 

further to ethanol. 

NREL has authored a thermochemical 

report: Phillips, S Thermochemical 

Ethanol via Indirect Gasification and 

Mixed Alcohol Synthesis of 

Lignocellulosic Biomass; April, 2007, 

which already provided a cost estimate. 

However, this report only hypothesized 

how a thermochemical ethanol plant 

could achieve production costs at a very 

low cost of $1 per gallon. Rather than 

rely on a very aggressively analyzed cost 

assessment that may not be achievable 

within the timeframe of our program, 

EPA contracted NREL to assess the costs 

for a thermochemical technology which 

produces mixed alcohols for years 2010, 

2015 and 2022. Table VII.A.1–7 

summarizes NREL’s estimated and 

projected production costs for 

biochemical cellulosic ethanol plant 

technology for their projected year 2022 

technology in 2007 dollars reflecting a 

7 percent before tax rate of return on 

investment. The costs are based on a 

cellulosic feedstock cost of 67 per dry 

ton. 

TABLE VII.A.1–7—YEAR 2022 THERMOCHEMICAL CELLULOSIC PRODUCTION COSTS OF MIXED ALCOHOLS PROVIDED BY

NREL 

[2007 dollars and 7% before tax rate of return] 

Year technology 2022 

Plant Size .................................................................................................................................................................. 72.7 Total Alcohol. 

MMgal/yr .................................................................................................................................................................... 61.9 Ethanol. 

Capital Cost ............................................................................................................................................................... 207. 

$MM 

$MM/yr c/gal 

Capital Cost 7% ROI before taxes ........................................................................................................................... 23 37 

Fixed Costs ............................................................................................................................................................... 13 21 

Feedstock Cost ......................................................................................................................................................... 52 85 

Coproduct Credit ....................................................................................................................................................... ¥13 ¥21 

Other Raw Material, Waste Disposal and Catalyst Costs ........................................................................................ 1 4 

Total Costs ................................................................................................................................................................ 76 126 

Cost estimates for both biochemical 

and thermochemical ethanol pathways 

ended up being ultimately identical. For 

our cost analysis, we based the 

cellulosic ethanol costs on the average 

of the biochemical and thermochemical 

cellulosic ethanol costs. 

BTL Diesel Fuel 

If cellulose is converted to syngas, 

rather than converting the syngas to 

mixed alcohols, a Fischer Tropsch 

reactor can be added to convert the 

syngas to diesel fuel and naphtha. This 

technology is commonly termed 

biomass-to-liquids (BTL) because of its 

similarity to gas-to-liquids and coal-tomstockstill on DSKH9S0YB1PROD with RULES2

Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14823 

309 International Energy Agency (IEA), ‘‘Biofuels 

for Transport: An International Perspective,’’ 2004. 

liquids technology. Diesel fuel’s higher 

energy density per gallon than ethanol 

and even biodiesel provides it an 

inherent advantage over these other 

fuels. In addition, BTL diesel fuel can be 

more easily distributed from production 

to retail outlets and used by motor 

vehicles. The diesel fuel produced by 

the Fischer Tropsch process tends to be 

comprised of paraffins which provide a 

much higher cetane number than 

petroleum diesel fuel, with a downside 

of poorer cloud point which reduces its 

widespread use in cold temperatures. 

The naphtha produced by the BTL 

process is also largely comprised of 

paraffins, however, as a gasoline 

blendstock it is poor because of its very 

low octane (potentially as low as 50 

octane). This material could be 

processed by refinery isomerization 

units raising its octane to perhaps 70 

octane, but it cannot be processed by 

refinery reformers since it does not 

contain the naphthenic compounds that 

are necessary for octane improvement 

by those units. Because of the large 

amount of octane rich ethanol which is 

expected to be made available from both 

corn and cellulose, it could be that BTL 

naphtha could be blended along with 

the ethanol into the gasoline pool. 

Rather than prejudge how this naphtha 

may be utilized in the future, for our 

cost analysis we simply assigned it a 

coproduct credit. So we set the BTL 

naphtha cost to be 83% as much of the 

cost of BTL diesel fuel based on its 

relative energy density. 

Although there were several studies 

available which provided costs 

estimates for BTL diesel fuel, they did 

not provide sufficient detail to 

understand all the cost elements of BTL 

diesel fuel and naphtha. EPA therefore 

asked NREL to estimate the production 

costs for BTL diesel fuel and naphtha. 

Like the other technologies, we asked 

for cost estimates for the same years 

assessed above for cellulosic ethanol 

which was for 2010, 2015 and 2022, 

however, NREL did not believe that the 

costs would change that much over this 

time span. So NREL only provided the 

costs for 2022, advising us that the costs 

would only be slightly less for earlier 

years, and most of that difference would 

because of the poorer economies of scale 

for the initial smaller sized plants. 

Table VII.A.1–8 summarizes NREL’s 

estimated and projected production 

costs for a thermochemical Fischer 

Tropsch biochemical cellulosic ethanol 

plant technology for their projected year 

2022 technology in 2007 dollars 

reflecting a 7 percent before tax rate of 

return on investment. The costs are 

based on a cellulosic feedstock cost of 

67 per dry ton. 

TABLE VII.A.1–8—YEAR 2022 PRODUCTION COSTS OF THERMOCHEMICAL (BTL) CELLULOSIC FISCHER TROPSCH DIESEL

FUEL PROVIDED BY NREL 

[2007 dollars and 7% before tax rate of return] 

Plant Size MMgal/yr 33.2 Diesel fuel 

49.4 all liquid 

Capital Cost $MM .................................................................................................................................................................... 346 

Capital Cost 7% ROI before taxes ($MM/yr) .......................................................................................................................... 38 

Fixed Costs ($MM/yr) .............................................................................................................................................................. 18 

Feedstock Cost ($MM/yr) ........................................................................................................................................................ 52 

Coproduct Credit ($MM/yr)a .................................................................................................................................................... ¥32 

Other raw matl. Costs ($MM/yr) .............................................................................................................................................. 1.5 

Waste Disposal and Catalyst Costs ($MM/yr) ........................................................................................................................ 1.5 

Total Costs ($MM/yr) ............................................................................................................................................................... 79 

Total Costs (cents/gallon of diesel fuel) .................................................................................................................................. 237 

aBased on a naphtha coproduct value of 198 cents per gallon. 

Other Cellulosic Diesel Fuel Costs 

For our volumes analysis, we 

assumed early on for our final rule 

analysis that there would likely be 

several different cellulosic biofuel 

technologies, other than BTL, producing 

cellulosic diesel fuel. However, we were 

either not able to obtain cost 

information from them, or we were 

uncertain enough about their future that 

we felt that we should not base the cost 

of the program on them. For example, 

Cello Energy has already built a 

cellulosic diesel fuel facility in Alabama 

here in the US with projected costs of 

about one dollar per gallon of diesel 

fuel. However, the facility has had 

difficulty operating as designed. As a 

result, perhaps very conservatively, we 

assumed that the other cellulosic diesel 

fuel costs would be the same as the BTL 

diesel fuel costs, and used the 237 cents 

per gallon cost for BTL diesel fuel for 

the entire cost for cellulosic diesel fuel. 

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 RIA, 

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).309

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 

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14824 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

310 Goldemberg, J. as sited in Rothkopf, Garten, ‘‘A 

Blueprint for Green Energy in the Americas,’’ 2006. 

311Unicamp ‘‘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. 

312 Ibid. 

313 Ibid. 314 Ibid. 

315Macedo. 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. 

316Smeets 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. 

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 VII.A.1–9. 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 VII.A.1–9—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. 

Variable sugarcane production 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%.310 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 in the 

future as the production process and 

cane practices have matured. Industrial 

efficiency gains are already at about 

85% and are expected to increase to 

90% in 2015.311 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 

2025.312 Sugarcane quality is also 

expected to improve, with sucrose 

content growing from 14.5% to 17.3% 

in 2025.313 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 2025.314 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, variable 

sugarcane ethanol production 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 

using the estimates from 

Table VII.A.1–7, 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 VII.A.1–7, 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, 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 40 kWh per 

ton sugarcane, however, future 

sugarcane plants are expected to 

produce 135 kWh per ton sugarcane 

assuming the use of higher efficiency 

condensing-extraction steam turbine 

(CEST) systems and use of 40% of 

available straw.315 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 have included 

this potential additional credit from 

greater use of bagasse and straw in our 

estimates at this time, calculated as a 

decrease in operating costs from $0.26 

per gallon to $0.04 per gallon. 

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.316 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 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14825 

317Official Statistics of the U.S. Department of 

Commerce, USITC. 

and port costs. The total average 

logistical and port cost for sugarcane 

ethanol is $0.20/gal and $0.09/gal, 

respectively, as shown in Table VII.A.1– 

10. 

TABLE VII.A.1–10—IMPORTED ETHANOL COST AT PORT IN BRAZIL

[2006 $] 

Region 

Logistical 

costs 

US 

($/gal) 

Port cost 

US 

($/gal) 

NE Sao Paulo .......................................................................................................................................................... 0.150 0.097 

W Sao Paulo ............................................................................................................................................................ 0.210 0.097 

SE Sao Paulo .......................................................................................................................................................... 0.103 0.097 

S Sao Paulo ............................................................................................................................................................. 0.175 0.097 

N Parana .................................................................................................................................................................. 0.238 0.097 

S Goias .................................................................................................................................................................... 0.337 0.097 

E Mato Grosso do sul .............................................................................................................................................. 0.331 0.097 

Triangulo mineiro ..................................................................................................................................................... 0.207 0.097 

NE Cost ................................................................................................................................................................... 0.027 0.060 

Sao Francisco Valley ............................................................................................................................................... 0.193 0.060 

Average .................................................................................................................................................................... 0.197 0.089 

Total fuel costs must also include the 

cost to ship ethanol from Brazil to the 

U.S. The average cost from 2006–2008 

was estimated to be approximately 

$0.17 per gallon of ethanol.317 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. 

from 2006–2008 was approximately 

$0.13 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 $0.17 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 VII.A.1–11, at 

$1.50/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 

VII.A.1–12 in the ‘‘Brazil Direct w/Tax & 

Tariff’’ and ‘‘CBI w/Tax’’ columns for 

2022. 

TABLE VII.A.1–11—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 

US 

($/gal) 

Total cost 

($/gal) 

0.51 .......................................................... 0.04 0.49 0.20 0.09 0.17 1.50 

TABLE VII.A.1–12—AVERAGE IMPORTED ETHANOL COSTS IN 2022 

Brazil direct 

($/gal) 

Brazil direct w/ 

tax & tariff 

($/gal) 

CBI 

($/gal) 

CBI w/tax 

($/gal) 

1.50 .............................................................................................................................................. 2.08 1.50 1.54 

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 acid pre-treatment steps 

required to utilize feedstocks with high 

free fatty acid content. 

The 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 

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14826 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

318Haas, M.J, A process model to estimate 

biodiesel production costs, Bioresource Technology 

97 (2006) 671–678. 

319See Technical Memo in the docket entitled 

‘‘Techno-economic analysis of microalgae-derived 

biofuel production’’ by Ryan Davis of the National 

Renewable Energy Laboratory. 

320A New Development in Renewable Fuels: 

Green Diesel, AM–07–10 Annual Meeting NPRA, 

March 18–20, 2007. 

321Taken from Syntroleum Investor Presentation, 

November 5, 2009. See http://

www.syntroleum.com/Presentations/

SyntroleumInvestorPresentation.

November%205.2009.FINAL.pdf. 

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. 318 For the purpose of 

estimating biodiesel production cost for 

this rulemaking, a model with updated 

facility, labor, and chemical costs was 

used. Installed capital cost was $11.9 

million, and energy prices were taken 

from AEO 2009: natural gas at $7.75/ 

MMBtu and electricity at $0.066/kWh. 

Capital charge plus maintenance was 

assumed to be 14% of total capital per 

year. Table VII.A.2–1 shows the 

production cost allocation for the soy 

oil-to-biodiesel facility as modeled in 

the 2022 policy case. 

TABLE VII.A.2–1—PRODUCTION COST

ALLOCATION FOR SOY BIODIESEL

FOR POLICY CASE IN 2022 

Cost category 

Contribution to 

cost 

(percent) 

Soy Oil ................................ 85 

Other Materials a ................. 6 

Capital & Facility ................. 6 

Labor ................................... 2 

Utilities ................................ 2 

a Includes acids, bases, methanol, catalyst. 

Soy oil costs were generated by the 

FASOM agricultural model (described 

in more detail in Section VIII.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 (rendered or 

reclaimed oil that is not suitable for use 

in food products). This material has 

historically sold for about 70% of the 

value of virgin soy oil. However, 

conversion of yellow grease into 

biodiesel requires an additional acid 

pre-treatment step, and therefore the 

processing costs are higher than for 

virgin soy oil (40–50 cents/gal if 

feedstock costs are equal), reducing the 

attractiveness of the cheaper feedstock 

to some extent. Another feedstock we 

expect to be used in significant 

quantities in the future is distressed 

corn oil extracted from process streams 

that make up distillers’ grains. This 

material will also require processing in 

acid pre-treatment facilities, and is 

projected by the FASOM model to have 

about one half the value of soy oil. 

Finally, we project a small amount of 

algae-derived oil (or similarly advanced 

feedstock) will be used by 2022. As algal 

biofuel technology is still in a relatively 

early stage of development, there are 

many possible configurations for the 

production of this material and thus 

there is considerable uncertainty 

regarding process performance and cost. 

Based on work done by NREL at the 

time of this rulemaking, we assumed a 

production cost of $0.68/lb for this 

feedstock.319 More details on how this 

estimate was made can be found in 

Chapter 4.1 of the RIA. 

A co-product of transesterification is 

crude glycerin. With the upswing in 

worldwide biodiesel production in 

recent years, its price has been 

depressed in most markets. Closure of 

remaining petrochemical glycerin 

plants, along with development of 

processes to make new use of it as a 

feedstock for other commodity 

chemicals has provided some support 

for a price recovery. Some companies 

are experimenting with using glycerin 

as a fuel for process or facility heat. We 

expect new uses for this coproduct to 

continue growing to reach an 

equilibrium with supply at or near its 

heating value, which we estimate to be 

$0.15/lb. As a result, the sale of this 

material as a co-product reduces 

biodiesel production cost by about 

$0.13/gal in our control case. 

b. Renewable Diesel 

Renewable diesel production can 

occur in a few different configurations: 

within the boundaries of an existing 

refinery where it may or may not be 

coprocessed with petroleum, or at a 

stand-alone plant that may or may not 

be co-located with other facilities that 

provide utilities or hydrogen. Given 

changes in the tax incentives as well as 

current project announcements, we have 

chosen to project that all renewable 

diesel will be produced in stand-alone 

facilities, not coprocessing with 

petroleum. The 75 MMgal/yr 

Syntroleum facility scheduled to come 

online in Geismar, Louisiana, in 2010 is 

an example of such a plant. 

Our production cost estimates used 

hydrogen requirements made available 

publicly by UOP, Inc. and overall 

project cost of $150MM taken from 

Syntroleum, Corp. materials.320 321 The 

feedstock was assumed to be yellow 

grease or similar rendered material. 

Hydrogen and co-product prices were 

taken from refinery modeling done for 

this rule, while an aggregate figure of 

$0.069/gal, derived from the UOP 

publication, was used to cover other 

variable operating costs besides 

hydrogen (includes labor, catalyst, and 

utilities). Cost contributions of various 

process aspects are shown in Table 

VII.A.2–2. More details are available in 

Chapter 4.1 of the RIA. 

TABLE VII.A.2–2—PRODUCTION COST

ALLOCATION FOR RENEWABLE DIESEL FOR POLICY CASE IN 2022 

Cost category 

Contribution to 

cost 

(percent) 

Feedstock ........................... 78 

Capital & Facility ................. 11 

Hydrogen ............................ 7 

Other variable costs ........... 3 

Table VII.A.2–3 summarizes the 

production costs for biodiesel and 

renewable diesel as estimated for this 

rule, as well as their projected volume 

contribution in 2022. Biodiesel made 

from yellow grease is projected to be 

about 10% cheaper to produce despite 

its higher production cost due to the 

large influence of the feedstock cost, 

which is about 30% lower. Biodiesel 

from extracted corn oil is expected to be 

significantly cheaper to produce than 

this, again due to the projected 

feedstock cost being about half that of 

soy oil. Finally, renewable diesel from 

stand-alone production is estimated in 

this analysis to have total production 

cost similar to biodiesel from yellow 

grease. However, given the business 

partnership between the fuel production 

and animal processing companies who 

have announced or are constructing the 

U.S. plants to date, we expect the 

feedstock being used there may be made 

available at a lower cost than we are 

projecting here for yellow grease. 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14827 

322The anticipated ways that the renewable fuels 

projected to be used in response to the EISA will 

be distributed is discussed in Section IV.C. of 

today’s preamble. 

323Please refer to Section 4.2 of the RIA for 

additional discussion of how these estimates were 

derived. 

324See Section IV.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. The 

derivation of these estimates is discussed in Section 

4.2 of the RIA. 

325These capital costs will be incurred 

incrementally through 2022 as ethanol volumes 

increase. Capital costs for tank trucks were 

amortized over 10 years with a 7% cost of capital. 

Other capital costs were amortized over 15 years 

with a 7% return on capital. 

TABLE VII.A.2–3—SUMMARY OF COST FOR BIODIESEL AND RENEWABLE DIESEL FOR POLICY CASE IN 2022 

[2007$] 

Fuel/feedstock 

Feedstock 

price 

($/lb) 

Fuel production cost 

($/gal) 

Biodiesel/soy oil ....................................................................................................................................................... 0.33 a 2.73 

Biodiesel/corn oil extraction at ethanol plants ......................................................................................................... 0.17 a 1.90 

Biodiesel/yellow grease or other rendered fats ....................................................................................................... 0.23 b 2.43 

Biodiesel/algae or other advanced virgin oil feedstock ........................................................................................... 0.58 c 4.52 d

Renewable diesel/yellow grease or other rendered fats ......................................................................................... 0.23 b 2.42 

aTaken from outputs of FASOM model. 

b Derived from outputs of FASOM model, assuming 70% value of soy oil. 

c Derived from figures in a Technical Memo by Ryan Davis of NREL entitled ‘‘Techno-economic analysis of microalgae-derived biofuel production’’ (available in docket). dThis production cost assumes this advanced feedstock has very low free fatty acid content. 

B. Biofuel Distribution Costs 

Our analysis of the costs associated 

with distributing the volume of biofuels 

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.322 The following sections outline 

our estimates of the distribution costs 

for the additional volumes of ethanol, 

cellulosic distillate fuel, renewable 

diesel fuel, and biodiesel that we project 

would be used in response to the RFS2 

standards under the three control 

scenarios that we analyzed relative to 

the two reference cases.323

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 IV.C. of today’s 

preamble and 1.6 of the RIA. 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 small 

fraction of the total anticipated increase 

in freight tonnage (approximately 3% of 

rail traffic by 2022, see Section IV.C.1), 

and (2) we do not believe there is an 

adequate way to estimate such nondirect costs. 

1. Ethanol Distribution Costs 

The capital costs to upgrade the 

distribution system to handle the 

increased volumes of ethanol vary 

substantially under the three control 

scenarios that we analyzed. Table 

VII.B.1–1 contains our estimates of the 

fuel distribution infrastructure capital 

costs to support the use of the 

additional ethanol that we project will 

be used under the three use scenarios by 

2022 relative to the RFS1 reference case 

forecast of 7.05 BGY.324 The total 

estimated capital costs under our 

primary case are estimated at $7.90 

billion which when amortized equates 

to approximately 6 cents per gallon of 

the additional ethanol volume that 

would be used in 2022 in response to 

the RFS2 standards relative to the RFS1 

reference case.325 Capital costs under 

the low-ethanol and high-ethanol 

scenarios are estimated at $5.47 billion 

and $11.92 billion respectively. This 

equates to 6 and 5 cents per gallon 

respectively relative to the RFS1 

reference case. 

TABLE VII.B.1–1—ESTIMATED ETHANOL DISTRIBUTION INFRASTRUCTURE CAPITAL COSTS UNDER THE RFS1 REFERENCE

CASE

Million $ 

Low-ethanol 

scenario 

Primary 

scenario 

High-ethanol 

scenario 

Fixed Facilities: 

Marine Import Facilities ........................................................................................................ 49 53 63 

Marine Facilities for Shipment Inside U.S. ........................................................................... 98 130 186

Unit Train Receipt Facilities ................................................................................................. 444 586 838 

Manifest Rail Receipt Facilities ............................................................................................ 15 20 28 

Petroleum Terminals: 

Terminal Storage Tanks ....................................................................................................... 859 1,243 2,073 

Blending & Misc. Equipment ................................................................................................ 1,006 1,064 1,144 

E85 Retail ............................................................................................................................. 1,957 3,293 4,973 

Mobile Facilities: 

Rail Cars ............................................................................................................................... 884 1,279 2,218 

Barges .................................................................................................................................. 53 77 133 

Tank Trucks .......................................................................................................................... 107 154 268 

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14828 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

326 ‘‘Analysis of Fuel Ethanol Transportation 

Activity and Potential Distribution Constraints’’, 

prepared for EPA by Oak Ridge National 

Laboratory, March 2009. The ORNL analysis 

indicates that ethanol freight costs decrease 

somewhat with increasing ethanol volume. See 

Section 4.2 of the RIA for additional discussion of 

the estimation of ethanol freight costs. 

327 If this is the case, EPA would need to 

reconsider its policies regarding what blendstocks 

TABLE VII.B.1–1—ESTIMATED ETHANOL DISTRIBUTION INFRASTRUCTURE CAPITAL COSTS UNDER THE RFS1 REFERENCE

CASE—Continued 

Million $ 

Low-ethanol 

scenario 

Primary 

scenario 

High-ethanol 

scenario 

Total Capital Costs (Million $) ....................................................................................... 5,471 7,898 11,922 

Total Capital Costs (cents per gallon ethanol) ............................................................. 6 6 5 

Table VII.B.1–2 contains our estimates 

of the fuel distribution infrastructure 

costs to support the use of the 

additional ethanol that we project will 

be used under the three use scenarios by 

2022 relative to the AEO reference case 

forecast of 13.18 BGY. The total 

estimated capital costs under our 

primary case are estimated at $5.50 

billion which when amortized equates 

to approximately 7 cents per gallon of 

the additional ethanol volume that 

would be used in 2022 in response to 

the RFS2 standards relative to the AEO 

reference case. Capital costs under the 

low-ethanol and high-ethanol scenarios 

are estimated at $3.02 billion and $9.93 

billion respectively. This equates to 8 

and 6 cents per gallon respectively 

relative to the AEO reference case. 

TABLE VII.B.1–2—ESTIMATED ETHANOL DISTRIBUTION INFRASTRUCTURE CAPITAL COSTS UNDER THE AEO REFERENCE

CASE

Million $ 

Low-ethanol 

scenario 

Primary 

scenario 

High-ethanol 

scenario 

Fixed Facilities: 

Marine Import Facilities ........................................................................................................ 49 53 63 

Marine Facilities for Shipment Inside U.S. ........................................................................... 76 100 144

Unit Train Receipt Facilities ................................................................................................. 238 434 748 

Manifest Rail Receipt Facilities ............................................................................................ 7 12 21 

Petroleum Terminals: 

Terminal Storage Tanks ....................................................................................................... 355 739 1,568 

Blending & Misc. Equipment ................................................................................................ 345 411 503 

E85 Retail ............................................................................................................................. 1,526 2,863 4,893 

Mobile Facilities: 

Rail Cars ............................................................................................................................... 309 522 1,133 

Barges .................................................................................................................................. 16 38 63 

Tank Trucks .......................................................................................................................... 68 103 194 

Total Capital Costs (Million $) ....................................................................................... 3,025 5,505 9,935 

Total Capital Costs (cents per gallon ethanol) ............................................................. 8 7 6 

We estimate that ethanol freight costs 

under the primary and high-ethanol 

scenarios would be 13 cents per gallon 

on a national average basis. Ethanol 

freight costs under the high-ethanol 

scenario are estimated at 12 cents per 

gallon. These estimates are based on an 

analysis conducted for EPA by Oak 

Ridge National Laboratory (ORNL) 

which were modified to reflect 

projected higher transportation fuel 

costs in the future, the likely installation 

of fewer unit train receipt facilities than 

that projected by ORNL based on 

industry comments, and to conform to 

the ethanol volumes under the three 

control scenarios analyzed in today’s 

rule.326 The ORNL analysis contains 

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. 

Summing the freight and capital costs 

estimates results in an estimate of 19 

cents per gallon for ethanol distribution 

costs for our primary and low-ethanol 

scenarios under the RFS1 reference 

case. Total ethanol distribution costs 

under the RFS1 reference case for the 

high-ethanol scenario are estimated at 

17 cents per gallon. Under the AEO 

reference case, total ethanol distribution 

costs are estimated at 21, 20, and 18 

cents per gallon respectively for the 

low-ethanol, primary, and high-ethanol 

scenarios. 

As discussed in Section IV.C. of 

today’s preamble, ASTM International is 

considering a change to specification on 

the minimum ethanol content in E85 to 

facilitate the manufacture of E85 at 

terminals which meets minimum 

volatility specifications using 

commonly-available finished gasoline. If 

the current difficulties in blending E85 

to meet minimum volatility 

specifications can not be resolved by 

lowering the minimum ethanol 

concentration of E85, high vapor 

pressure blendstocks will need to be 

supplied to approximately two thirds of 

petroleum terminals for blending with 

E85.327 This would necessitate the 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14829 

can be used at petroleum terminals in the 

manufacture of E85. 

328 ‘‘Analysis of Fuel Ethanol Transportation 

Activity and Potential Distribution Constraints’’, 

prepared for EPA by Oak Ridge National Laboratory 

(ORNL), March 2009. 

329This is a sensitivity case that was evaluated in 

the NPRM. 

330See Section IV.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. The 

derivation of these estimates is discussed in Section 

1.6 of the RIA. 

331These 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. 

installation of new blending/storage 

equipment at petroleum terminals and 

additional butane tank cars and tank 

trucks. The capital costs for such 

facilities would be $2.2 billion, $1.4 

billion, and $0.6 billion under the highethanol, primary, and low-ethanol 

scenarios respectively under both 

reference cases. By amortizing these 

capital costs and adding in butane 

freight costs, we estimate that the need 

to supply special blendstocks at 

terminals for E85 blending would add 

approximately 1 cent per gallon to 

ethanol distribution costs for all three 

analysis scenarios relative to the RFS1 

reference case. Relative to the AEO 

reference case, the additional cost 

would be approximately 2 cents per 

gallon under the primary and lowethanol scenarios, and approximately 1 

cent per gallon under the high-ethanol 

scenario. 

In the NPRM, we 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. Based on input from 

industry and a study conducted for us 

by ORNL, we now believe that all unit 

train receipt facilities will be installed at 

new dedicated locations.328 This change 

results in the need for additional tank 

truck receipt equipment at terminals 

and additional tank trucks to carry 

ethanol from rail to petroleum terminals 

compared to the NPRM. However, we 

also received additional input from 

industry on the cost of unit train 

facilities which indicates that such 

facilities are not as costly as we 

projected in the NPRM. We also 

increased the average E85 facility cost 

relative to the NPRM to reflect the likely 

need for additional E85 dispensers and 

a larger underground storage tank to 

maintain sufficient throughput per 

facility.329

2. Cellulosic Distillate and Renewable 

Diesel Distribution Costs 

We chose to evaluate the distribution 

costs for cellulosic distillate and 

renewable diesel together because the 

same considerations apply to their 

handling in the fuel distribution system 

and because the projected volume of 

renewable diesel fuel is relatively small. 

Table VII.B.2–1 contains our estimates 

of the fuel distribution infrastructure 

capital costs to support the use of the 

cellulosic distillate and renewable 

diesel fuel that we project will be used 

under the three use scenarios by 2022 

under the RFS1 reference case.330 The 

total estimated capital costs by 2022 

under our primary and low-ethanol 

scenarios are estimated at $1.38 billion 

and $2.00 billion respectively under the 

RFS1 reference case. 

TABLE VII.B.2–1—ESTIMATED CELLULOSIC DISTILLATE FUEL DISTRIBUTION INFRASTRUCTURE CAPITAL COSTS UNDER THE

RFS1 REFERENCE CASE

Million $ 

Low-ethanol 

scenario 

Primary 

scenario 

High-ethanol 

case 

Fixed Facilities: 

Marine Facilities for Shipment Inside US ............................................................................. 87 56 - 

Unit Train Receipt Facilities ................................................................................................. 394 253 ........................

Manifest Rail Receipt Facilities ............................................................................................ 13 8 ........................

Petroleum Terminals: 

Terminal Storage Tanks ....................................................................................................... 218 154 ........................

Blending & Misc. Equipment ................................................................................................ 361 252 ........................

Mobile Facilities: 

Rail Cars ............................................................................................................................... 784 552 ........................

Barges .................................................................................................................................. 47 33 ........................

Tank Trucks .......................................................................................................................... 95 ........................ ........................

Total Capital Costs (Million $) ....................................................................................... 1,999 1,375 NA

Total Capital Costs (cents per gallon of cellulosic distillate fuel) ................................. 2 2 NA

Table VII.B.2–2 contains our estimates 

of the infrastructure changes and 

associated capital costs to support the 

use of the cellulosic distillate and 

renewable diesel fuel that we project 

will be used under the three use 

scenarios by 2022 under the AEO 

reference case. Total capital costs are 

estimated at $1.02 and $1.46 billion for 

the primary and low-ethanol scenarios 

respectively under the AEO reference 

case. The difference in estimated capital 

costs for the two control scenarios under 

the two reference scenarios is obscured 

by rounding when translating these 

costs to a cents-per-gallon basis. When 

amortized, these capital costs equate to 

approximately 2 cents per gallon for 

both control scenarios under both 

reference cases.331

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14830 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

332 ‘‘Analysis of Fuel Ethanol Transportation 

Activity and Potential Distribution Constraints’’, 

prepared for EPA by Oak Ridge National 

Laboratory, March 2009. See Section 4.2 of the RIA 

for additional discussion of the estimation of 

cellulosic distillate freight costs. 

333The same unit train and manifest rail receipt 

facilities would be used to handle shipments of 

both fuels. 

334We project that by 2022 300 MGY of biodiesel 

would be used under the RFS1 reference case, 380 

MGY of biodiesel would be used under the RFS 

reference case and that a total of 1.67 BGY of 

biodiesel would be used under the EISA. Biodiesel 

use is projected to be the same under all three of 

analysis scenarios. 

335These capital costs will be incurred 

incrementally through 2022 as biodiesel volumes 

increase. Capital costs for tank trucks were 

amortized over 10 years with a 7% cost of capital. 

Other capital costs were amortized over 15 years 

with a 7% return on capital. 

TABLE VII.B.2–2—ESTIMATED CELLULOSIC DISTILLATE FUEL DISTRIBUTION INFRASTRUCTURE CAPITAL COSTS UNDER THE

AEO REFERENCE CASE

Million $ 

Low-ethanol 

scenario 

Primary 

scenario 

High-ethanol 

case 

Fixed Facilities: 

Marine Facilities for Shipment Inside US ............................................................................. 67 43 ........................

Unit Train Receipt Facilities ................................................................................................. 511 315 ........................

Manifest Rail Receipt Facilities ............................................................................................ 15 9 ........................

Petroleum Terminals: 

Terminal Storage Tanks ....................................................................................................... 218 154 ........................

Blending & Misc. Equipment ................................................................................................ 304 223 ........................

Mobile Facilities: 

Rail Cars ............................................................................................................................... 784 552 ........................

Barges .................................................................................................................................. 47 33 ........................

Tank Trucks .......................................................................................................................... 90 63 ........................

Total Capital Costs (Million $) ....................................................................................... 2,036 1,392 NA 

Total Capital Costs (cents per gallon of cellulosic distillate fuel) ................................................ 2 2 NA 

We estimate that cellulosic distillate 

freight costs would be 13 cents per 

gallon on a national average basis under 

both the primary and low-ethanol 

scenarios. This estimate is based on the 

application to cellulosic distillate 

freight costs of an analysis conducted 

for EPA by Oak Ridge National 

Laboratory (ORNL) of ethanol freight 

costs.332 The underlying premise is that 

both ethanol and cellulosic distillate 

fuel would be handled by the same 

types of distribution facilities on the 

journey to petroleum terminals.333

Summing the freight and capital costs 

results in an estimated 15 cents per 

gallon in total distribution costs for both 

the primary and low-ethanol scenarios 

under both reference cases. 

The ethanol and cellulosic distillate 

distribution cost estimates are based on 

the projections of the location of biofuel 

production facilities and end use areas 

contained in the NPRM. The extent to 

which new biofuel production facilities 

are more dispersed than projected in the 

NPRM, distribution costs for ethanol 

from new production facilities and for 

all cellulosic distillate facilities may 

tend be lower than those projected by 

this analysis as the fuel has more 

opportunity to be used locally. This 

would potentially be a greater benefit in 

lowering cellulosic distillate 

distribution costs than overall ethanol 

distribution costs given the large 

number of ethanol production facilities 

currently located in the Midwest. 

Cellulosic distillate costs should also 

tend to be lower than those for ethanol 

because cellulosic distillate fuel blends 

are compatible with existing petroleum 

distribution equipment, whereas there 

are special considerations associated 

with the distribution of ethanol. The 

most notable of these considerations is 

the need for special fuel retail 

equipment for E85 (as evidenced in 

Table VII.B.1–1). Thus, the cellulosic 

distillate distribution costs estimated 

here are likely to be conservative. 

3. Biodiesel Distribution Costs 

Table VII.B.3–1 contains our estimates 

of the infrastructure changes and 

associated capital costs to support the 

use of the additional biodiesel that we 

project will be used under RFS2 by 2022 

relative to the RFS reference case of 300 

MGY by 2022.334 The total capital costs 

are estimated at $1.2 billion which 

equates to approximately 10 cents per 

gallon of additional biodiesel 

volume.335

TABLE VII.B.3–1—ESTIMATED BIODIESEL DISTRIBUTION INFRASTRUCTURE CAPITAL COSTS UNDER THE

RFS1 REFERENCE CASE

Million $ 

Fixed Facilities: 

Petroleum Terminals: 

Storage Tanks ......................... 411 

Blending & Misc. Equipment ... 612 

Mobile Facilities: 

Rail Cars ................................. 111 

Barges ..................................... 53 

Tank Trucks ............................ 25 

Total Capital Costs (Million 

$) ...................................... 1,212 

Total Capital Costs (cents per 

gallon of biodiesel) .................. 10 

Table VII.B.3–2 contains our estimates 

of the infrastructure changes and 

associated capital costs to support the 

use of the additional biodiesel that we 

project will be used under RFS2 by 2022 

relative to the AEO reference case of 380 

MGY. The total capital costs are 

estimated at $1.1 billion which equates 

to approximately 10 cents per gallon of 

additional biodiesel volume. 

TABLE VII.B.3–2—ESTIMATED BIODIESEL DISTRIBUTION INFRASTRUCTURE CAPITAL COSTS UNDER THE

AEO REFERENCE CASE

Million $ 

Fixed Facilities: 

Petroleum Terminals: 

Storage Tanks ......................... 387 

Blending & Misc. Equipment ... 576 

Mobile Facilities: 

Rail Cars ................................. 105 

Barges ..................................... 50 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14831 

336See Section 4.2 of the RIA for a discussion of 

our derivation of biodiesel distribution costs. 

TABLE VII.B.3–2—ESTIMATED BIODIESEL DISTRIBUTION INFRASTRUCTURE CAPITAL COSTS UNDER THE

AEO REFERENCE CASE—Continued 

Million $ 

Tank Trucks ............................ 24 

Total Capital Costs (Million 

$) ...................................... 1,141 

Total Capital Costs (cents per 

gallon of biodiesel) .................. 10 

We estimate that biodiesel freight 

costs would be 10 cents per gallon on 

a national average basis. State biodiesel 

use requirements and biodiesel 

production locations were taken into 

account in formulating this estimate.336

The biodiesel blend ratio was estimated 

to vary between 2 and 5%. Adding the 

estimated freight costs to the amortized 

capital costs results in an estimate of 

total biodiesel distribution costs of 20 

cents per gallon under both the RFS1 

and AEO reference cases. 

C. Reduced U.S. Refining Demand 

As renewable and alternative fuel use 

increases, the volume of petroleumbased products, such has gasoline and 

diesel fuel, would decrease. This 

reduction in finished refinery petroleum 

products results in 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 as investment 

in new refinery capacity is displaced by 

investments in renewable and 

alternative fuels capacity. 

Although we conducted refinery 

modeling for estimating the cost of 

blending ethanol (see Section VII.B), we 

did not rely on the refinery model 

results for estimating the volume of 

displaced petroleum as other economic 

factors also come into play. 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 

VIII.B of this preamble. 

As part of this petroleum 

displacement 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 the 

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 by the RFS2 standard. 

We assumed that a portion of the 

gasoline displaced by ethanol would 

have been produced from domestic 

refineries causing reduced demand from 

U.S. refineries, while the rest of the 

additional ethanol displaces imported 

gasoline or gasoline blendstocks which 

does not affect domestic refining sector 

costs. To estimate the portion of new 

ethanol which displaces U.S. refinery 

production we relied on some Markal 

refinery modeling conducted for us by 

DOE. The Markal refinery model models 

all the refinery sectors of the world and 

thus can do a fair job estimating how 

renewable fuels would impact imports 

of finished gasoline and gasoline 

blendstocks. The Markal refinery model 

estimated that 2⁄3rds of a reduction in 

petroleum gasoline demand would be 

met by a reduction in imported gasoline 

or gasoline blendstocks, while the other 

1⁄3rd would be met by reduced refining 

production by the U.S. refining sector. 

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 VIII.B. 

For estimating the U.S. refinery 

industry cost reductions, we multiplied 

the estimated volume of domestic 

gasoline and diesel fuel displaced by the 

projected wholesale price for each of 

these fuels in 2022, which are $3.42 per 

gallon for gasoline, and $3.83 per gallon 

for diesel fuel. For the volume of 

petroleum displaced upstream, we 

valued it using the wholesale diesel fuel 

price. Table VII.C–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 VII.C–1—CHANGES IN U.S. REFINERY INDUSTRY VOLUMES AND COSTS FOR INCREASED RENEWABLE FUEL

VOLUMES IN 2022 RELATIVE TO THE AEO 2007 REFERENCE CASE

[2007 dollars] 

Low ethanol case Primary case 

(mid-ethanol case) 

High ethanol case 

Bil gals Bil $ Bil gals Bil $ Bil gals Bil $ 

Upstream: 

Petroleum ...................................................................................... 0.34 1.3 0.34 1.3 0.33 1.3 

End Use: 

Gasoline ........................................................................................ ¥0.9 ¥3.1 ¥2.0 ¥6.8 ¥4.4 ¥15.0 

Diesel Fuel .................................................................................... ¥10.1 ¥38.7 ¥7.5 ¥28.7 ¥1.3 ¥5.0 

Total ....................................................................................... ¥10.7 ¥40.5 ¥9.2 ¥34.2 ¥5.4 ¥18.7 

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For the primary control case relative 

to the AEO 2007 reference case, this 

analysis estimates that the increased 

volumes of renewable fuel would 

reduce the gasoline and diesel fuel 

production volume of US refineries by 

9.2 billion gallons in 2022, which would 

reduce their raw material purchases and 

production costs by $34 billion dollars. 

Accounting for all the petroleum 

displaced (domestic and foreign), the 

increased volumes of renewable fuel 

caused by the RFS 2 fuels program are 

estimated to reduce gasoline and diesel 

fuel demand by 13.2 billion gallons. 

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, cellulosic 

diesel fuel, 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 

fuel program. A detailed discussion of 

how the renewable fuel volumes affect 

refinery gasoline production volumes 

and cost is contained in Chapter 4 of the 

RIA. 

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 

two year 2022 future year reference 

cases which based their energy demand 

off of the 2009 Annual Energy Outlook 

(AEO). One of the reference cases 

assumes business-as-usual demand 

growth from the AEO 2007 reference 

case discussed in Section IV.A.1. The 

other utilized the RFS1 reference case. 

The refinery modeling results are based 

on $116 per barrel crude oil prices 

which are the 2022 projected prices by 

EIA in its 2009 AEO. 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 also 

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. 

The third step, or the control cases, 

involved the modeling of three different 

possible renewable fuels volumes. The 

three different volumes were designed 

to capture the additional use of corn 

ethanol and biodiesel and a range of 

cellulosic ethanol and cellulosic diesel 

fuel volumes. The volumes that we 

assessed in our analysis are summarized 

in Section IV.A above. 

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. For the 

control case, E85 was assumed to be 

priced lower than gasoline to reflect its 

lower energy content, longer refueling 

time and lower availability (see Chapter 

4 of the RIA for a detailed discussion for 

how we projected E85 prices). For the 

refinery modeling, E85 was assumed to 

be blended with gasoline blendstock 

designed for blending with E10, and 

with butane to bring the RVP of E85 up 

to that allowed by ASTM International 

standards for E85. 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. As E85 

specifications are still under 

consideration by ASTM, this 

assumption may differ from future 

procedures. 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. 

Our costs also include the incremental 

costs of producing flexible fuel vehicles 

(FFVs) over that of conventionally 

fueled vehicles. 

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. 

2. Overall Impact on Fuel Cost 

Utilizing the refinery modeling output 

conducted for today’s final rule, we 

calculated the costs for each control 

case, which represented the three 

different renewable fuels scenarios in 

2022, relative to the AEO 2007 and 

RFS1 reference cases. The costs are 

reported separately for blending ethanol 

into gasoline, as E10 and E85, and for 

blending cellulosic diesel fuel, biodiesel 

and renewable diesel into petroleumbased diesel fuel. These costs do not 

include the biofuel consumption tax 

subsidies. The costs are based on 2007 

dollars and the capital costs are 

amortized at seven percent return on 

investment (ROI) before taxes. 

Tables VII.D.2–1 and VII.D.2–2 

summarize the costs for each of the 

three control cases, including the 

aggregated total for all the fuel changes 

and the per-gallon costs, relative to the 

AEO 2007 and RFS1 reference cases, 

respectively. 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. These cost estimates do not 

account for the various tax subsidies. 

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. These costs are only 

for the incremental renewable fuel 

volumes beyond the volumes modeled 

in the two reference cases. 

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TABLE VII.D.2–1—ESTIMATED FUEL COSTS OF INCREASED VOLUMES OF RENEWABLE FUEL IN 2022 INCREMENTAL TO THE

AEO 2007 REFERENCE CASE

[2007 dollars, 7% ROI before taxes] 

Low ethanol 

case 

Primary case 

(mid-ethanol 

case) 

High ethanol 

case 

Gasoline Impacts: 

$billion/yr ....................................................................................................................... ¥0 .67 ¥3 .31 ¥5.90 

c/gal .............................................................................................................................. ¥0 .48 ¥2 .35 ¥4.08 

Diesel Fuel Impacts: 

$billion/yr ....................................................................................................................... ¥11 .7 ¥8 .5 ¥1.27 

c/gal .............................................................................................................................. ¥16 .4 ¥12 .1 ¥1.79 

Total Impact: 

$billion/yr ....................................................................................................................... ¥12 .4 ¥11 .8 ¥7.17 

Incremental to the AEO 2007 

reference case, our analysis shows that 

for the low ethanol case which models 

mostly cellulosic diesel instead of 

cellulosic ethanol, the gasoline and 

diesel fuel costs are projected to 

decrease by $0.7 billion and $11.70 

billion, respectively, for a total savings 

of $12.4 billion. Expressed as per-gallon 

costs, these fuel changes would decrease 

the cost of producing gasoline and 

diesel fuel by 0.5 and 16.4 cents per 

gallon, respectively. 

For our primary case which models a 

mix of cellulosic diesel fuel and 

cellulosic ethanol, the gasoline and 

diesel fuel costs are projected to 

decrease by $3.3 billion and $8.5 

billion, respectively, for a total savings 

of $11.8 billion. Expressed as per-gallon 

costs, these fuel changes would decrease 

the cost of producing gasoline and 

diesel fuel by 2.4 and 12.1 cents per 

gallon, respectively. 

For the high ethanol case where the 

cellulosic biofuel is cellulosic ethanol 

(as in the proposal), the gasoline and 

diesel fuel costs are projected to 

decrease by $5.9 billion and $1.3 

billion, respectively, for a total savings 

of $7.2 billion. Expressed as per-gallon 

costs, these fuel changes would decrease 

the cost of producing gasoline and 

diesel fuel by 4.1 and 1.8 cents per 

gallon, respectively. 

Crude oil prices have been very 

volatile over the last several years which 

raises uncertainty about future crude oil 

prices. Because our cost model was 

created to be able to assess the cost of 

the program at a higher crude oil price, 

we can also assess the cost at other 

crude oil prices. As a sensitivity, we 

varied crude oil prices in our model to 

find the break-even (no cost) point of 

the RFS2 program. Using our cost model 

we estimate that, for the primary control 

case relative to the AEO 2007 reference 

case, the RFS2 program (total of gasoline 

and diesel fuel costs) would break-even 

at a 2022 crude oil price of $88 per 

barrel. Thus, in 2022 if crude oil is 

priced lower than $88 per barrel, the 

RFS2 program would cost money; if 

crude oil is priced higher than $88 per 

barrel, the RFS2 program would result 

in a cost savings. 

TABLE VII.D.2–2—ESTIMATED FUEL COSTS OF INCREASED VOLUMES OF RENEWABLE FUEL IN 2022 INCREMENTAL TO THE

RFS1 REFERENCE CASE

[2007 dollars, 7% ROI before taxes] 

Low ethanol 

case 

Primary case 

(mid-ethanol 

case) 

High ethanol 

case 

Gasoline Impacts: 

$billion/yr ....................................................................................................................... ¥3 .12 ¥5 .63 ¥7.79 

c/gal .............................................................................................................................. ¥2 .24 ¥4 .00 ¥5.38 

Diesel Fuel Impacts: 

$billion/yr ....................................................................................................................... ¥11 .7 ¥8 .6 ¥1.35 

c/gal .............................................................................................................................. ¥16 .5 ¥12 .1 ¥1.90 

Total Impact: 

$billion/yr ....................................................................................................................... ¥14 .8 ¥14 .2 ¥9.14 

Incremental to the RFS1 reference 

case, our analysis shows that for the low 

ethanol case which models mostly 

cellulosic diesel instead of cellulosic 

ethanol, the gasoline and diesel fuel 

costs are projected to decrease by $3.1 

billion and $11.70 billion, respectively, 

for a total savings of $14.8 billion. 

Expressed as per-gallon costs, these fuel 

changes would decrease the cost of 

producing gasoline and diesel fuel by 

2.4 and 16.5 cents per gallon, 

respectively. 

For our primary case which models a 

mix of cellulosic diesel fuel and 

cellulosic ethanol, the gasoline and 

diesel fuel costs are projected to 

decrease by $5.6 billion and $8.6 

billion, respectively, for a total savings 

of $14.2.billion. Expressed as per-gallon 

costs, these fuel changes would decrease 

the cost of producing gasoline and 

diesel fuel by 4.0 and 12.1 cents per 

gallon, respectively. 

For the high ethanol case where the 

cellulosic biofuel is cellulosic ethanol 

(as in the proposal), the gasoline and 

diesel fuel costs are projected to 

decrease by $7.8 billion and $1.4 

billion, respectively, for a total savings 

of $9.1 billion. Expressed as per-gallon 

costs, these fuel changes would decrease 

the cost of producing gasoline and 

diesel fuel by 5.4 and 1.9 cents per 

gallon, respectively. 

Both the gasoline and diesel fuel costs 

are negative because of the relatively 

high crude oil prices estimated by EIA 

for the year 2022. Given the higher 

projected crude oil prices and these 

savings, it is difficult to quantify how 

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much of the increase in renewable fuels 

and the associated savings is due to the 

RFS 2 program versus what would have 

happened regardless in the marketplace. 

However, even with the high crude oil 

prices as projected by EIA, some or 

perhaps even most of the investments in 

these emerging renewable fuels 

technologies may not occur without the 

RFS 2 program in place. The reason for 

this is that investors are hesitant to 

invest in emerging technologies when 

the threat remains for a drop in the price 

of crude oil leaving their investment 

dollars stranded. The RFS2 program 

provides certainty for investors to invest 

in renewable fuel technologies. 

There are two important reasons why 

the diesel fuel costs are more negative 

than the gasoline costs when comparing 

the low ethanol case (high cellulosic 

diesel case) to the high ethanol case: (1) 

Cellulosic ethanol costs include the 

costs for fuel flexible vehicles, while 

vehicles using cellulosic diesel fuel are 

not expected to require any vehicle 

modifications, hence there is no 

additional estimated cost, (2) the crude 

oil price adjustment based on crude oil 

and finished gasoline and diesel fuel 

price data from 2002 to 2008 increases 

the estimated production cost for 

petroleum diesel fuel more so than for 

gasoline—therefore cellulosic diesel 

shows a greater cost savings. If the 

diesel fuel prices do not increase more 

than gasoline prices with higher crude 

oil prices, then the significantly higher 

savings for renewable diesel fuel over 

that for renewable ethanol would be less 

than that modeled here. 

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 

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 VII.D.2–3, 

we list the total incremental capital 

investments that we project would be 

made for this RFS2 rulemaking 

incremental to the RFS1 reference case 

(refer to Chapter 4 of the RIA for more 

detail). 

TABLE VII.D.2–3—TOTAL PROJECTED U.S. CAPITAL INVESTMENTS TO MEET THE INCREASED VOLUMES OF RENEWABLE

FUEL

[Incremental to the AEO 2007 reference case, billion dollars] 

Cost type Plant type Low ethanol 

case 

Primary case 

(mid-ethanol 

case) 

High ethanol 

case 

Production Costs .............................. Corn Ethanol ................................................................. 3.9 3.9 3.9 

Cellulosic Ethanol ......................................................... 0 14.3 48.3 

Cellulosic Diesel a ......................................................... 96.5 68.0 0 

Renewable Diesel and Algae ....................................... 1.1 1.1 1.1 

Distribution Costs ............................. All Ethanol ..................................................................... 5.6 8.2 11.9 

Cellulosic and Renewable Diesel Fuel ......................... 2.0 1.4 ........................

Biodiesel ........................................................................ 1.2 1.2 1.2 

FFV Costs ..................................................................... 0.8 1.8 6.1 

Refining ......................................................................... ¥10.7 ¥9.4 ¥4.1 

Total Capital Investments ......... ....................................................................................... 110.4 90.5 68.4 

a Cellulosic diesel fuel is assumed to be produced by BTL plants which is a very capital intensive technology. If some or even most of this volume comes from other cellulosic diesel fuel technologies which are less capital intensive, the capital costs attributed to cellulosic diesel would be 

much lower. 

Table VII.D.2–3 shows that the total 

U.S. capital investments attributed to 

this program ranges from $71 to $111 

billion in 2022 for the high ethanol to 

low ethanol cases. The capital 

investments made for renewable fuels 

technologies are much more than the 

decrease in refining industry capital 

investments because (1) a large part of 

the decrease in petroleum gasoline 

supply was from reduced imports, (2) 

renewable fuels technologies are more 

capital intensive per gallon of fuel 

produced than incremental increases in 

gasoline and diesel fuel production at 

refineries, and (3) ethanol and biodiesel 

require considerable distribution and 

retail infrastructure investments. 

VIII. Economic Impacts and Benefits 

A. Agricultural and Forestry 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 the 

domestic agricultural and forestry 

sectors, as well as 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. EPA worked 

directly with the Center for Agriculture 

and Rural Development (CARD) at Iowa 

State University to implement the 

FAPRI model to analyze the impacts of 

the RFS2 on the global agriculture 

sector. Thus, this model will henceforth 

be referred to as the FAPRI–CARD 

model. 

FASOM is a long-term economic 

model of the U.S. agriculture and 

forestry sectors that attempts to 

maximize total revenues for producers 

while meeting the demands of 

consumers. FASOM can be utilized to 

estimate which crops, livestock, forest 

stands, and processed agricultural and 

forestry 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 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 

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337Thomson, A.M., R.C. Izarrualde, T.O. West, 

D.J. Parrish, D.D. Tyler, and J.R. Williams. 2009. 

Simulating Potential Switchgrass Production in the 

United States. PNNL–19072. College Park, MD: 

Pacific Northwest National Laboratory. 

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). 

There are a few notable changes that 

have been made to both the FASOM and 

FAPRI–CARD models, as well as to 

some of the underlying assumptions 

used in the agro-economic analysis 

since the release of the proposed 

rulemaking analysis. These changes 

were made as a result of further research 

and consultation with experts, as well 

as in response to comments received 

during the public comment period 

following the release of the proposed 

rulemaking. In regards to the FASOM 

model, the first major change made to 

the model is the inclusion of the full 

interaction between the forestry and 

agriculture sectors, as discussed in the 

NPRM and supported by comments 

received. For the proposed rulemaking, 

the FASOM model was only capable of 

modeling the changes in the agriculture 

sector alone. In terms of land use, the 

only land use that could be examined 

was cropland and pasture use. With the 

incorporation of a forestry sector that 

dynamically interacts with the 

agriculture, we are able to examine how 

crop and forest acres compete for land 

in response to changes in policy. Also, 

similar to the agriculture sector, the 

forestry sector has its own set of forestry 

products, including logging and milling 

residues that are available for the 

production of cellulosic ethanol. 

The second major change to the 

FASOM model is the addition of a full 

accounting of major land types in the 

U.S., including cropland, cropland 

pasture, forestland, forest pasture, 

rangeland, acres enrolled in the 

Conservation Reserve Program (CRP), 

and developed land. These changes 

address comments raised by peer 

reviewers and the general public that we 

should more explicitly link the 

interaction between livestock, pasture 

land, cropland, and forest land, as well 

as have a detailed accounting of acres in 

the U.S. across different land uses. 

Cropland is actively managed cropland, 

used for both traditional crops (e.g., 

corn and soybeans) and dedicated 

energy crops (e.g., switchgrass). 

Cropland pasture is managed pasture 

land used for livestock production, but 

which can also be converted to cropland 

production. Forestland contains a 

number of sub-categories, tracking the 

number of acres both newly and 

continually harvested (reforested), the 

number of acres harvested and 

converted to other land uses 

(afforested), as well as the amount of 

forest acres on public land. Forest 

pasture is unmanaged pasture land with 

varying amounts of tree cover that can 

be used for livestock production. A 

portion of this land may be used for 

timber harvest. Rangeland is unmanaged 

land that can be used for livestock 

grazing production. While the amount 

of rangeland idled or used for 

production may vary, rangeland may 

not be used for any other purpose than 

for cattle grazing. 

A third major change in the FASOM 

model is the adoption of updated 

cellulosic ethanol conversion rates. We 

updated the cellulosic ethanol 

conversion rates based on new data 

provided by the National Renewable 

Energy Laboratory (NREL). The new 

analysis by NREL simplified and 

updated the conversion yields of the 

different types of feedstocks. As a result 

of these changes, the gallons per ton 

yields for switchgrass and several other 

feedstocks increased from the values 

used in the proposal, while the yields 

for corn residue and several other 

feedstocks decreased slightly from the 

NPRM values. In addition, we also 

updated our feedstock production yields 

based on new work conducted by the 

Pacific Northwest National Laboratory 

(PNNL).337 This analysis increased the 

tons per acre yields for several 

dedicated energy crops. These changes 

increased the amount of cellulosic 

ethanol projected to come from energy 

crops. Additional details on the FASOM 

model changes can be found in Chapter 

5 of the RIA. 

The FAPRI–CARD 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. 

As one of the largest and fastest 

developing countries in the world, a 

major producer and exporter of sugar 

ethanol, and in possession of one of the 

world’s largest carbon sinks, the 

Amazon, Brazil is acknowledged to be 

an important part of our analysis in 

terms of indirect land use change. For 

the proposal’s analysis, the FAPRI– 

CARD model analyzed Brazil at a 

national level as any other non-US 

nation in the model, covering only crop 

area and commodity prices. Comments 

and feedback received indicated the 

importance of analyzing Brazil at a 

regional level, given its diverse natural 

lands across the country, and to also 

closely examine livestock production in 

terms of land use. 

In response to these comments, the 

FAPRI–CARD model now includes an 

integrated Brazil module that provides 

additional detail on agricultural land 

use in Brazil for six geographic regions. 

The new Brazil module explicitly 

models the competition between 

cropland and pastureland used for 

livestock production in each region. In 

addition, the Brazil module allows for 

region-specific agriculture practices 

such as double cropping and livestock 

intensification in response to higher 

commodity prices. The addition of the 

Brazil module allows for a more refined 

analysis of land use change and 

economic impacts in Brazil than what 

was able to be done for the proposal’s 

analysis. 

Another topic that we received 

comments on was in regards to priceinduced yields. Namely that with an 

increase in price for a particular crop, 

seed producers and/or farmers have a 

greater incentive to increase yields for 

that particular crop in order to 

maximize revenue. In the analysis for 

proposal, the FAPRI–CARD model did 

not include impacts of commodity price 

changes on yields. For the final 

rulemaking, the FAPRI–CARD model 

now includes feedback from changes in 

commodity prices on yields. The 

elasticities for these responses are based 

on an econometric analysis of historical 

data on yield and price changes for 

various commodities. Additional details 

on the FAPRI–CARD modeling updates 

can be found in Chapter 5 of the RIA. 

In the NPRM, we specifically 

requested comments on our 

assumptions regarding distiller grain 

with solubles (DGS) replacement rates. 

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14836 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

338Salil 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. 

For the proposal, we assumed that one 

pound of DGS replaced one pound of 

total of corn and soybean meal for all 

fed animals. We received numerous 

comments on this assumption. Many 

commenters suggested that we adopt the 

replacement rates included in the recent 

research by Argonne National 

Laboratory (ANL) and others.338 The 

ANL study found that one pound of 

DGS can be used to replace 1.196 

pounds total of corn and soybean meal 

for various fed animals due to the higher 

nutritional content of DGS per pound 

compared to corn and soybean meal. For 

the final rulemaking analysis, these 

replacement rates are incorporated in 

both the FASOM and FAPRI–CARD 

models, and are treated as a maximum 

replacement rate possibility that is fully 

phased in by 2015. In addition, the 

maximum inclusion rates for DGS in an 

animal’s diet have also been 

incorporated into the models. Given 

these parameters, each agriculture sector 

model determines the total quantity of 

DGS used in feed based on relative 

prices for competing feed sources. 

In addition, both FASOM and FAPRI– 

CARD now explicitly model corn oil 

from the dry mill ethanol extraction 

process as a new source of biodiesel. 

Based on engineering research (refer to 

Section VII.A) regarding expected 

technological adoption, it is estimated 

that 70% of dry mill ethanol plants will 

withdraw corn oil via extraction (from 

DGS), resulting in corn oil that is nonfood grade and can only be used as a 

biodiesel source; 20% will withdraw 

corn oil via fractionation (prior to the 

creation of DGS), resulting in corn oil 

that is food-grade; and 10% will do 

neither extraction or fractionation. 

Based on this research, both the FASOM 

and FAPRI–CARD models are 

estimating that approximately 681 

million gallons of biodiesel can be 

produced from non-food grade corn oil 

from extraction by 2022 in the Control 

Case. Additional information regarding 

these changes to the FASOM and 

FAPRI–CARD models can be found in 

RIA Chapter 5. 

1. Biofuel Volumes Modeled 

For the agricultural sector analysis 

using the FASOM and FAPRI–CARD 

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 1.7 Bgal of 

biodiesel use as fuel in 2022, an 

increase of 1.3 Bgal from the Reference 

Case. In addition, we modeled an 

increase of 16 Bgal of cellulosic ethanol 

in 2022. In FASOM, this volume 

consists of 4.9 billion gallons of 

cellulosic ethanol coming from corn 

residue in 2022, 7.9 billion gallons from 

switchgrass, 0.6 billion gallons from 

sugarcane bagasse, and 0.1 billion 

gallons from forestry residues. 

Given the nature of the models, there 

are some limitations on what each 

model may explicitly model as a biofuel 

feedstock source. For example, since 

FASOM is a domestic agricultural sector 

model it cannot be utilized to examine 

the impacts of the wider use of biofuel 

imports into the U.S. Similarly, the 

FAPRI–CARD model does not explicitly 

model the forestry sector in the U.S. and 

therefore does not include biofuels 

produced from the U.S. forestry sector. 

Also, neither of the two models used for 

this analysis—FASOM or FAPRI– 

CARD—include biofuels derived from 

domestic municipal solid waste. Thus, 

for the RFS2 agricultural sector analysis, 

these biofuel sources are analyzed 

outside of the agricultural sector 

models. 

All of 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–CARD. 

The detailed FASOM results, detailed 

FAPRI–CARD results, and additional 

sensitivity analyses are described in 

more detail in the RIA. 

TABLE VIII.A.1–1—ETHANOL SOURCE VOLUMES MODELED IN 2022 

[Billions of gallons] 

Ethanol source 

AEO 2007 

reference 

case 

Control 

case Change 

Corn Ethanol ............................................................................................................................................ 12.3 15.0 2.7 

Corn Residue Cellulosic Ethanol * ........................................................................................................... 0 4.9 4.9 

Sugarcane Bagasse Cellulosic Ethanol * ................................................................................................ 0.2 0.6 0.4 

Switchgrass Cellulosic Ethanol * .............................................................................................................. 0 7.9 7.9 

Forestry Residue Cellulosic Ethanol * ..................................................................................................... 0 0.1 0.1 

Net Imports of Sugarcane Ethanol ** ....................................................................................................... 0.6 2.2 1.6 

Other Ethano *** ....................................................................................................................................... 0.1 2.6 2.5 

* Cellulosic Ethanol feedstocks are not explicitly modeled in FAPRI–CARD. 

** Net Imports of Sugarcane Ethanol is not explicitly modeled in FASOM. 

*** Includes MSW, which is not explicitly modeled by either FASOM or FAPRI–CARD. 

TABLE VIII.A.1–2—BIODIESEL SOURCE VOLUMES MODELED IN 2022 

[Millions of gallons] 

Biodiesel source 

AEO 2007 

reference 

case 

Control 

case Change 

Soybean Oil ............................................................................................................................................. 119.9 659.4 539.5 

Corn Oil (Dry Mill Extraction) ................................................................................................................... 0.4 681.3 680.8 

Animal Fats .............................................................................................................................................. 93.9 126.9 33.0 

Yellow Grease ......................................................................................................................................... 170.9 253.1 82.3 

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2. Commodity Price Changes 

For the scenario modeled, FASOM 

predicts that in 2022 U.S. corn prices 

would increase by $0.27 per bushel 

(8.2%) above the Reference Case price of 

$3.32 per bushel. By 2022, U.S. soybean 

prices would increase by $1.02 per 

bushel (10.3%) above the Reference 

Case price of $9.85 per bushel. In 2022, 

U.S. soybean oil prices would increase 

$183.32 per ton (37.9%) above the 

Reference Case price of $483.10 per ton. 

Hardwood lumber prices are unaffected 

by the increase in biofuel demand, 

however softwood lumber prices 

increase by $0.46 per board foot (0.1%) 

in 2022 to $386 per board foot. 

Additional price impacts are included 

in Section 5 of the RIA. 

TABLE VIII.A.2–1—CHANGE IN U.S. COMMODITY PRICES FROM THE AEO 2007 REFERENCE CASE

[2007$] 

Commodity Change % Change 

Corn ............................................................................................... 0.27/bushel .................................................................................. 8.2 

Soybeans ...................................................................................... 1.02/bushel .................................................................................. 10.3 

Soybean Oil ................................................................................... 183.32/ton .................................................................................... 37.9 

Hardwood Lumber ......................................................................... 0.00/board foot ............................................................................. 0 

Softwood Lumber .......................................................................... 0.46/board foot ............................................................................. 0.1 

By 2022, the price of switchgrass 

would increase by $20.12 per wet ton to 

the Control Case price of $40.85 per wet 

ton. Additionally, the farm gate 

feedstock price of corn residue would 

increase by $29.48 per wet ton to the 

Control Case price of $34.49 per wet 

ton. The price of sugarcane bagasse 

would increase $23.27 to the Control 

Case price of $29.70 per wet ton by 

2022. Softwood logging residue prices 

would increase $8.99 per wet ton to 

$18.37 per wet ton in the Control Case 

in 2022. Similarly, the price of 

hardwood logging residues would 

increase by $17.85 per wet ton to the 

Control Case price of $23.22 per wet ton 

in 2022. 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. 

TABLE VIII.A.2–2—CHANGE IN U.S. CELLULOSIC FEEDSTOCK PRICES FROM THE AEO 2007 REFERENCE CASE

[2007$] 

Commodity Control case price Change 

Switchgrass ....................................................... $40.85/wet ton .................................................. $20.12/wet ton. 

Corn Residue ..................................................... 34.49/wet ton .................................................... 29.48/wet ton. 

Sugarcane Bagasse .......................................... 29.70/wet ton .................................................... 23.27/wet ton. 

Softwood Logging Residue ............................... 18.37/wet ton .................................................... 8.99/wet ton. 

Hardwood Logging Residue .............................. 23.22 ................................................................. 17.85/wet ton. 

3. 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 

$13 billion dollars in 2022 (36%), 

relative to the AEO 2007 Reference 

Case. 

4. 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 

40.5%, relative to the 33.2% 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 188 million bushels 

(¥8.2%) to 2.1 billion bushels by 2022. 

In value terms, U.S. exports of corn 

would fall by $57 million (¥0.8%) to 

$7.5 billion in 2022. U.S. exports of 

soybeans would also decrease due to the 

increased use of renewable fuels. 

FASOM estimates that U.S. exports of 

soybeans would decrease 135 million 

bushels (¥13.6%) to 858 million 

bushels by 2022. In value terms, U.S. 

exports of soybeans would decrease by 

$453 million (¥4.6%) to $9.3 billion in 

2022. 

TABLE VIII.A.4–1—CHANGE IN U.S. 

EXPORTS FROM THE AEO 2007 

REFERENCE CASE IN 2022 

Change 

(millions) % Change 

Exports 

Corn in Bushels .... ¥188 ¥8.2 

Soybeans in Bushels ...................... ¥135 ¥13.6 

TABLE VIII.A.4–1—CHANGE IN U.S. 

EXPORTS FROM THE AEO 2007 

REFERENCE CASE IN 2022—Continued 

Change 

(millions) % Change 

Total Value of Exports 

Corn (2007$) ........ ¥ $57 ¥0.8 

Soybeans (2007$) ¥ $453 ¥4.6 

Lumber production in the U.S. is 

affected as well, as forestry acres 

decrease as a result of expanding crop 

acres (see below). In 2022, hardwood 

lumber production increases by 0.2%, 

and softwood production decreases by 

¥0.2%. 

TABLE VIII.A.4–2—PERCENT CHANGE

IN U.S. LUMBER PRODUCTION FROM

THE AEO 2007 REFERENCE CASE IN

2022 

Commodity % Change 

Hardwood Lumber ...................... 0.2 

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14838 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

339Total U.S. planted corn acres increases to 87.1 

million acres from the Reference Case level of 83.5 

million acres in 2022. 

TABLE VIII.A.4–2—PERCENT CHANGE

IN U.S. LUMBER PRODUCTION FROM

THE AEO 2007 REFERENCE CASE IN

2022—Continued 

Commodity % Change 

Softwood Lumber ....................... ¥0.2 

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. One of the major byproducts of 

the ethanol production process that can 

be used as a feed source, and as a 

substitute for corn and soybean meal, is 

distiller grains with solubles (DGS). 

DGS are a by-product of the dry mill 

ethanol production process. As 

discussed above, the replacement rates 

of DGs for corn and soybean meal in the 

diets of fed animals is higher than what 

was used in the proposal based on the 

latest scientific research regarding 

nutritional content of feed sources. In 

addition, as discussed above and in 

Chapter VI, there are new processes for 

withdrawing corn oil from the dry mill 

ethanol production process. Therefore, 

we are now modeling two types of DGS: 

Those that are created during the 

extraction/fractionation process 

(fractionated DGS), and those created in 

plants that do not conduct fractionation 

or extraction (traditional DGS). In 

addition, other byproducts that can be 

used as feed substitutes include gluten 

meal and gluten feed, which are 

byproducts of wet milling ethanol 

production. In 2022, traditional DGS 

used in feed decreases by 27.5 million 

tons from the Reference Case to 6.5 

million tons in the Control Case. 

However, the use of fractionated DGS 

increases by 32.7 million tons from 20 

thousand tons used in the Reference 

Case in 2022. Gluten meal used in feed 

decreases by 0.1 million tons (¥4.5%) 

to 2.1 million tons in the Control Case. 

Gluten feed use increases by 0.3 million 

tons (6.4%) in 2022 to 4.8 million tons 

in the Control Case. By 2022, FASOM 

predicts total ethanol byproducts used 

in feed would increase by 5.4 million 

tons (13.2%) to 46.1 million tons, 

compared to 40.8 million tons under the 

Reference Case. 

TABLE VIII.A.4–3—CHANGE IN ETHANOL BYPRODUCTS USE IN FEED

RELATIVE TO THE AEO 2007 REFERENCE CASE

[Millions of tons] 

Category Control 

case Change 

DGS (Traditional) .. 6.5 ¥27.5 

DGS (Fractionated) 32.7 32.7 

Gluten Meal .......... 2.1 ¥0.1 

Gluten Feed .......... 4.8 0.3 

Total Ethanol 

Byproducts ..... 46.1 5.4 

The EISA cellulosic ethanol 

requirements result in the production of 

residual agriculture and forestry 

products, as well as dedicated energy 

crops. By 2022, FASOM predicts 

production of 97.4 million tons of 

switchgrass and 59.9 million tons of 

corn residue. Sugarcane bagasse for 

cellulosic ethanol production increases 

by 6 million tons to 9.6 million tons in 

2022 relative to the Reference Case. In 

addition, FASOM predicts production 

of 1.7 million tons of forestry residues 

for cellulosic ethanol production. 

5. 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 

amount of land devoted to cropland 

production would increase. FASOM 

estimates an increase of 3.6 million 

acres (4.6%) in harvested corn acres, 

relative to 77.9 million acres harvested 

under the Reference Case by 2022.339

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. According to 

the model, harvested soybean acres 

would decrease by approximately 1.4 

million acres (¥2.1%), relative to the 

Reference Case acreage of 68.1 million 

acres in 2022. Despite the decrease in 

soybean acres in 2022, soybean oil 

production would increase by 0.5 

million tons (4.7%) by 2022 over the 

Reference Case. This occurs due to the 

decrease in soybean exports mentioned 

above. Additionally, FASOM predicts 

that soybean oil exports would decrease 

1.2 million tons by 2022 (¥51%) 

relative to the Reference Case. 

As the demand for cellulosic ethanol 

increases, most of the production is 

derived from switchgrass. By 2022, 

switchgrass acres from nearly zero acres 

in the Reference Case, to 12.5 million 

acres in the Control Case as demand for 

cellulosic ethanol increases between 

cases. Similarly, as demand for 

cellulosic ethanol from bagasse 

increases, sugarcane acres increase by 

0.1 million acres (20%) to 0.9 million 

acres by 2022. Although we received 

comments suggesting that acres enrolled 

in the Conservation Reserve Program 

(CRP) may decrease below the 32 

million acres assumed in the NPRM, we 

did not revise this assumption for 

several reasons. First, the commodity 

price changes predicted by FASOM are 

relatively modest and would therefore 

have a limited impact on the decision to 

re-enroll in the program. Second, the 

CRP program is designed to allow for 

increased payment if land rental rates 

increase. Therefore, for the reasons 

outlined in the NPRM, we believe the 

assumption that CRP acres will not drop 

below 32 million acres is a plausible 

future projection. 

TABLE VIII.A.5–1—CHANGE IN U.S. 

CROP ACRES RELATIVE TO THE

AEO 2007 REFERENCE CASE IN

2022 

[Millions of acres] 

Crop Change % Change 

Corn ...................... 3.6 4.6 

Soybeans .............. ¥1.4 ¥2.1 

Sugarcane ............ 0.1 20 

Switchgrass .......... 12.5 20,000 

With the increase in biofuel demand 

that results from the implementation of 

the RFS2 policy, there is an increase of 

3.1 million acres are dedicated towards 

crop production. This increase in crop 

acres results in a decrease of ¥1.9 

million pasture acres, an increase of 1.1 

million acres of forest pasture, and a 

decrease of 1.2 million forestry acres. 

TABLE VIII.A.5–2—CHANGE IN U.S. 

CROP ACRES RELATIVE TO THE

AEO 2007 REFERENCE CASE IN

2022 

[Millions of acres] 

Land type Change % Change 

Cropland ............... 3.1 1.0 

Cropland Pasture .. ¥1.9 ¥5.8 

Forest Pasture ...... 1.1 0.7 

Forestry ................. ¥1.2 ¥0.3 

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 1.5 billion pounds (5.7%) over 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14839 

340FASOM 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. 

341These estimates are based on U.S. Census 

population projections of 331 million people in 

2017 and 348 million people in 2022. See http:// 

www.census.gov/population/www/projections/

summarytables.html. 

342Farm Gate food prices refer to the prices that 

farmers are paid for their commodities. 

343See www.ers.usda.gov/Briefing/

CPIFoodAndExpenditures/Data/table15.htm. 

344The food commodities included in the FAPRI 

model include corn, wheat, sorghum, barley, 

soybeans, sugar, peanuts, oils, beef, pork, poultry, 

and dairy products. 

345Source: U.S. Bureau of Economic Analysis, 

U.S. International Transactions Accounts Data, as 

shown on June 24, 2009. 

346Source: U.S. Department of Energy, Annual 

Energy Review 2008, Report No. DOE/EIA– 

0384(2008), Tables 5.1 and 5.13c, June 26, 2009. 

the Reference Case nitrogen fertilizer 

use of 26.2 billion pounds. In 2022, U.S. 

phosphorous fertilizer use would 

increase by 714 million pounds (12.7%) 

relative to the Reference Case level of 

5.6 billion pounds. 

TABLE VIII.A.5–3—CHANGE IN U.S. 

FERTILIZER USE RELATIVE TO THE

AEO 2007 REFERENCE CASE

[Millions of pounds] 

Fertilizer Change % Change 

Nitrogen ................ 1,501 5.7 

Phosphorous ......... 714 12.7 

6. Impact on U.S. Food Prices 

Due to higher commodity prices, 

FASOM estimates that U.S. food 

costs 340 would increase by roughly $10 

per person per year by 2022, relative to 

the Reference Case.341 Total effective 

farm gate food costs would increase by 

$3.6 billion (0.2%) in 2022.342 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.343

7. International Impacts 

Changes in the U.S. agriculture 

economy are likely to have affects 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–CARD model to 

assess the impacts of the increased use 

of renewable fuels in the U.S. on world 

agricultural markets. 

The FAPRI–CARD modeling shows 

that world corn prices would increase 

by $0.12 per bushel (3.1%) to $3.88 per 

bushel in 2022, relative to the Reference 

Case. The impact on world soybean 

prices is somewhat smaller, increasing 

$0.08 per bushel (0.8%) to $9.63 per 

bushel in 2022. 

This increase in international 

commodity prices has a direct impact 

on world food consumption.344 The 

FAPRI–CARD model indicates that 

world consumption of corn for food 

would decrease by 0.6 million metric 

tons in 2022 relative to the Reference 

Case. Similarly, the FAPRI–CARD 

model estimates that world 

consumption of oil for food (e.g., 

vegetable oils) decreases by 1.7 million 

metric tons by 2022. Wheat 

consumption is not estimated to change 

substantially in 2022. The model also 

estimates a small change in world meat 

consumption, decreasing by -0.1 million 

metric tons in 2022. When considering 

all the food uses included in the model, 

world food consumption decreases by 

2.4 million metric tons by 2022 

(¥0.11%). While FAPRI–CARD 

provides estimates of changes in world 

food consumption, estimating effects on 

global nutrition is beyond the scope of 

this analysis. 

TABLE VIII.A.7–1—CHANGE IN WORLD

FOOD CONSUMPTION RELATIVE TO

THE AEO 2007 REFERENCE CASE

[Millions of metric tons] 

Category 2022 

Corn .................................................. ¥0.6 

Wheat ............................................... 0.0 

Vegetable Oils .................................. ¥1.7 

Meat .................................................. ¥0.1 

Total Food ..................................... ¥2.4 

Additional information on the U.S. 

agricultural and forestry sectors, as well 

as international trade impacts are 

described in more detail in the RIA 

(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 detail an updated 

methodology for estimating the energy 

security benefits of reduced U.S. oil 

imports which explicitly includes 

biofuels and, based upon this updated 

approach, we estimate the monetary 

value of the energy security benefits of 

the RFS2 required renewable fuel 

volumes. 

1. Implications of Reduced Petroleum 

Use on U.S. Imports 

In 2008, U.S. petroleum import 

expenditures represented 21% of total 

U.S. imports of all goods and 

services.345 In 2008, the U.S. imported 

66% of the petroleum it consumed, and 

the transportation sector accounted for 

70% of total U.S. petroleum 

consumption. This compares to 

approximately 37% of petroleum from 

imports and 55% consumption of 

petroleum in the transportation sector in 

1975.346 It is clear that petroleum 

imports have a significant impact on the 

U.S. economy. Requiring the wider use 

of renewable fuels in the U.S. is 

expected to lower U.S. petroleum 

imports. 

For this final rule, EPA estimated the 

reductions in U.S. petroleum imports 

using a modified version of the National 

Energy Modeling System (EPA–NEMS). 

EPA–NEMS is an energy-economy 

modeling system of U.S. energy markets 

through the 2030 time period. EPA– 

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. For 

this analysis, the 2009 NEMS model was 

modified to use the 2007 (pre-EISA) 

Annual Energy Outlook (AEO) levels of 

biofuels in the Reference Case. These 

results were compared to our Control 

Case, which assumes the renewable fuel 

volumes required by EISA will be met 

by 2022. The reductions in U.S. oil 

imports projected by EPA–NEMS as a 

result of the RFS2 is approximately 0.9 

million barrels per day, which amounts 

to about $41.5 billion in lower crude oil 

and refined product import payments in 

2022. 

2. Energy Security Implications 

In order to understand the energy 

security implications of the increased 

use of renewable fuels, EPA used the Oil 

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14840 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

347The OSMM methods are consistent with the 

recommended methodologies of the National 

Resource Council’s (NRC’s) (2005) Committee on 

Prospective Benefits of DOE’s Energy Efficiency and 

Fossil Energy R&D Programs. The OSMM defines 

and implements a method that makes use of the 

NRC’s typology of prospective benefits and 

methodological framework, satisfies the NRC’s 

criteria for prospective benefits evaluation, and 

permits measurement of prospective energy security 

benefits for policies and technologies related to oil. 

It has been used to estimate the prospective oil 

security benefits of Department of Energy’s Energy 

Efficiency and Renewable Energy R&D programs, 

and is also applicable to other strategies and 

policies aimed at changing the level and 

composition of U.S. petroleum demand. To evaluate 

the RFS2, the OSMM was modified to include 

supplies and demand of biofuels (principally 

ethanol) as well as petroleum. 

348Leiby, P.N., Energy Security Impacts of 

Renewable Fuel Use Under the RFS2 Rule— 

Methodology, Oak Ridge National Laboratory, 

January 19, 2010. 

349Leiby, 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. 

350The 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. 

351Leiby, Paul N. ‘‘Estimating the Energy Security 

Benefits of Reduced U.S. Oil Imports,’’ Oak Ridge 

National Laboratory, ORNL/TM–2007/028, Final 

Report, 2008. 

Security Metrics Model 347 348 (OSMM), 

developed and maintained by Oak Ridge 

National Laboratory. This model 

examines the future economic costs of 

oil imports and oil supply disruptions 

to the U.S., grouping costs into (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 ‘‘import demand’’ or 

‘‘monopsony’’ costs); and (2) the 

expected cost 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). Beginning 

with Reference projections for the oil 

and liquid fuel markets from the EIA’s 

2009 AEO, the OSMM compares costs 

under those futures with selected cases 

under differing energy policies and 

technology mixes. It provides measures 

of expected costs and risk by 

probabilistic simulation through 2022. 

Uncertainty is inherent in energy 

security analysis, and it is explicitly 

represented for long-run future oil 

market conditions, disruption events, 

and key parameters. 

An important aspect of the OSMM is 

that it explicitly addresses the energy 

security implications of the wider use of 

biofuels as transportation fuels in the 

U.S. Increased use of biofuels not only 

results in changes in the levels of U.S. 

oil imports and consumption, but also 

can alter key supply and demand oil 

elasticities. The elasticities are 

significant for energy security since they 

measure the potential for substitution 

away from oil, in the long and short-run, 

depending on how oil prices evolve and 

whether oil supply disruptions occur. 

Also, the OSMM accounts for the 

potential of supply disruptions from 

biofuels. For example, there could be a 

drought in the U.S. that could cause a 

reduction in the supply of key 

agricultural feedstocks (i.e., corn) that 

are used to make ethanol. To the extent 

that supply disruptions in feedstocks 

used to make biofuels are correlated 

with oil supply disruptions, the energy 

security benefits of biofuels may be 

lessened, by substituting one fuel with 

supply disruptions for another. For this 

analysis, the energy security 

implications of the wider use of biofuels 

in the U.S. are broken down between 

biofuels produced domestically (e.g., 

ethanol made from corn/switchgrass, 

soy-based biodiesel) and imported 

biofuels (e.g., ethanol made from 

sugarcane). 

For the proposed RFS2 rule, EPA 

worked with Oak Ridge National 

Laboratory (ORNL), which has 

developed approaches for evaluating the 

social costs and energy security 

implications of oil use. In the study 

entitled ‘‘The Energy Security Benefits of 

Reduced Oil Use, 2006–2015,’’ 

completed in March, 2008, ORNL 

updated and applied the analytical 

approach used in the 1997 Report ‘‘Oil 

Imports: An Assessment of Benefits and 

Costs.’’ 349 350 This study is included as 

part of the record in this rulemaking.351

This study underwent a Peer Review, 

sponsored by the Agency. 

The prior approach that ORNL has 

developed estimates the incremental 

benefits to society, in dollars per barrel, 

of reducing U.S. oil imports, called the 

‘‘oil import premium’’. With OSMM, 

ORNL uses a consistent approach, 

estimating the incremental cost to the 

U.S. of the increased use of renewable 

fuels required by EISA, and reporting 

that cost in dollars per barrel of biofuel. 

In this case, these increased volumes 

alter both the U.S. oil import and 

consumption levels, while introducing a 

substitute fuel and altering demand 

responsiveness. As before, OSMM 

considers the economic cost of 

importing petroleum into the U.S. The 

economic cost of importing petroleum 

into the U.S. was defined as (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., ‘‘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 is also a measure 

of energy security, but has been 

excluded from this analysis because its 

attribution to particular military 

missions or activities is difficult. 

a. Effect of Oil Use on Long-Run Oil 

Price, U.S. Import Costs, and Economic 

Output 

The first component of the 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. 

In the case of the RFS2, increasing 

U.S. demand for biofuels partially 

offsets the U.S. oil market import cost 

reduction. The offset is because the 

RFS2 results in a modest increases in 

biofuels imported to the U.S. (1.6 billion 

gallons in 2022), and a modest increase 

in the world ethanol price (from $1.48/ 

gallon to $1.61/gallon, a $0.13/gallon 

increase in 2022). Thus, the biofuels 

that the U.S. had imported would be 

higher priced, partially offsetting the 

reduction in U.S. oil import costs. The 

ORNL estimates this monopsony 

component of the energy security 

benefit (oil market and biofuel market 

impacts combined) is $7.86/barrel of 

biofuel (2007$) for the year 2022, as 

shown in Table VIII.B.2–1. Based upon 

the 90 percent confidence interval, the 

monopsony portion of the energy 

security benefit ranges from $5.37 to 

$10.71/barrel of biofuel in the year 

2022. 

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 

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Reserve (SPR) to respond; and the 

sensitivity of the U.S. economy to 

sudden price increases. 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 oil consumption 

levels can change the sensitivity of the 

economy to oil price shocks, and 

variation in import levels or demand 

flexibility can affect the magnitude of 

potential increases in oil price due to 

supply disruptions 

A major strength of the OSMM is that 

it addresses risk-shifting that might 

occur as the U.S. reduces its 

dependency on petroleum and increases 

its use of biofuels, which the other ‘‘oil 

premium model’’ could not. The prior 

‘‘oil premium’’ analysis focused only on 

the potential for biofuels to reduce U.S. 

oil imports, and the resulting 

implications of lower U.S. oil imports 

for energy security. As the U.S. relies 

more heavily on biofuels, such as cornbased ethanol, there could be adverse 

consequences from a supply-disruption 

perspective associated with, for 

example, a long-term drought. 

Alternatively, a supply disruption of 

petroleum will more likely be caused by 

geopolitical factors rather than extreme 

weather conditions. Hence, the causal 

factors of a supply-disruption from 

imported petroleum and, alternatively, 

biofuels, are likely to be unrelated. 

Thus, diversifying the sources of U.S. 

transportation fuel is expected to 

provide energy security benefits. Biofuel 

supply disruptions are represented 

based on the historical volatility of 

yields for biofuel feedstocks or similar 

crops. The ORNL estimates this 

macroeconomic/disruption component 

of the energy security benefit (oil market 

and biofuel market impacts combined) 

is $6.56/barrel (2007$) for the year 2022, 

as shown in Table VIII.B.2–1. Based 

upon the 90 percent confidence interval, 

the macroeconomic/disruption 

component of the energy security 

benefit ranges from $0.94 to $12.23/ 

barrel of biofuel in the year 2022. 

TABLE VIII.B.2–1—ENERGY SECURITY

BENEFITS OF THE VOLUMES REQUIRED BY RFS2 IN 2022 

[2007$ per barrel of biofuel] 

Component Estimate 

Monopsony ....................... 7.86 

(5.37–10.71) 

Macroeconomic Disruption 6.56 

(0.94–12.23) 

Total .............................. 14.42 

(6.31–22.95) 

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 costs 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. In the 

peer review of the energy security 

analysis that the Agency commissioned, 

a majority of peer reviewers believed 

that U.S. military costs should be 

excluded absence a widely agreed 

methodology for estimating this 

component of U.S. energy security. 

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. 

Some commenters felt that the 

Agency should attempt to monetize U.S. 

military costs and include these costs in 

the energy security analysis, while other 

commenters agreed with the Agency 

that these costs should be excluded. The 

Agency did not receive any new 

analysis or methodological approach 

from commenters which could be used 

to monetize U.S. military costs in a 

meaningful or credible manner. Since 

U.S. military impacts are not factored 

into the energy security analysis, they 

are also excluded from the lifecycle 

GHG analysis. 

3. Combining Energy Security and Other 

Benefits 

The literature on the energy security 

for the last two decades has routinely 

combined the monopsony and the 

macroeconomic disruption components 

when calculating the total value of the 

energy security premium. However, in 

the context of using a global value for 

the Social Cost of Carbon (SCC) the 

question arises: how should the energy 

security premium be used when some 

benefits from the increased use of 

renewable fuels, such as the benefits of 

reducing greenhouse gas emissions, are 

calculated at a global level? Monopsony 

benefits represent avoided payments by 

the U.S. to oil producers in foreign 

countries that result from a decrease in 

the world oil price as the U.S. decreases 

its consumption of imported oil (net of 

increased imported biofuel payments by 

the U.S.). Although there is clearly a 

benefit to the U.S. when considered 

from the domestic perspective, the 

decrease in price due to decreased 

demand in the U.S. also represents a 

loss to other countries. Given the 

redistributive nature of this effect, do 

the negative effects on other countries 

‘‘net out’’ the positive impacts to the 

U.S.? If this is the case, then, the 

monopsony portion of the energy 

security premium should be excluded 

from the net benefits calculation. Based 

on this reasoning, EPA’s estimates of net 

benefits for the increased use of 

renewable fuels required by EISA 

exclude the portion of energy security 

benefits stemming from the U.S. 

exercising its monopsony power in oil 

markets. Thus, EPA only includes the 

macroeconomic disruption/adjustment 

cost portion of the energy security 

premium. 

However, even when the global value 

for greenhouse gas reduction benefits is 

used, a strong argument can be made 

that the monopsony benefits should be 

included in net benefits calculation. 

Maintaining the earth’s climate is a 

global public good and as such requires 

that a global perspective be taken on the 

benefits of GHG mitigation by all 

nations, including the U.S. The global 

SCC is used in these calculations, not 

because the global net benefits of the 

increased use of renewable fuels are 

being computed (they are not), but 

rather because in the context of a global 

public good, the global marginal benefit 

is the correct benefit against which 

domestic costs are to be compared. In 

other words, using the global SCC does 

not transform the calculation from a 

domestic (i.e., U.S.) to a global one. 

Rather, the domestic perspective is 

maintained while recognizing that the 

impacts from domestic GHG emissions 

are truly global in nature. 

Energy security, on the other hand, is 

broadly defined as protecting the U.S. 

economy against circumstances that 

threaten significant short- and long-term 

increases in energy costs. Energy 

security is inherently a domestic 

benefit. However, the use of the 

domestic monopsony benefit is not 

necessarily in conflict with the use of 

the global SCC, because the global SCC 

represents the benefits against which 

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352See Federal Register/Vol. 74, No. 2398/ 

Wednesday, December 16, 2009/Rules and 

Regulations at http://frwebgate4.access.gpo.gov/cgibin/PDFgate.cgi?WAISdocID=969788398047

+0+2+0&WAISaction=retrieve or http://epa.gov/

climatechange/endangerment.html. 

353For the purposes of this discussion, we 

present all values of the SCC as the cost per metric 

tonne of CO2 emissions. Some discussions of the 

SCC in the literature use an alternative presentation 

of a dollar per metric ton of carbon. The standard 

adjustment factor is 3.67, which means, for 

example, that a SCC of $10 per ton of CO2 would 

be equivalent to a cost of $36.70 for a ton of carbon 

emitted. Unless otherwise indicated, a ‘‘ton’’ refers 

to a metric ton. 

the costs associated with our (i.e., the 

U.S.’s) domestic mitigation efforts 

should be judged. In addition, the U.S. 

values both maintaining the earth’s 

climate and providing for its own 

energy security. If this reasoning holds, 

the two benefits—the global benefits of 

reducing greenhouse gas emissions and 

the full energy security premium, 

including the monopsony benefits— 

should be counted in the net benefits 

estimates. In the final analysis, the 

Agency determined that the first 

argument is more compelling and 

therefore has determined that using only 

the macroeconomic disruption 

component of the energy security 

benefit is the appropriate metric for this 

rule. 

4. Total Energy Security Benefits 

In 2022, total annual energy security 

benefits are estimated for the difference 

between the renewable fuel volumes in 

the Primary Control Case (30.50 billion 

gallons) and the AEO2007 Reference 

Case (13.56 billion gallons). Total 

annual energy security benefits are 

calculated by multiplying the change in 

renewable fuel volumes (16.94 billion 

gallons or 403 million barrels) and the 

macroeconomic disruption/adjustment 

portion of the energy security premium 

($6.56/barrel of renewable fuels). The 

estimated total energy security benefit is 

$2.6 billion (2007$) for the year 2022. 

The estimated total energy security 

benefit using the macroeconomic 

disruption/adjustment portion of the 

energy security benefit in 2022 ranges 

from $379 million to $4.9 billion based 

upon the 90 percent confidence 

intervals. 

C. Benefits of Reducing GHG Emissions 

1. Introduction 

This section presents estimates of the 

economic benefits that could be 

monetized for the reductions in GHG 

emissions projected to occur through 

the increased use of renewable fuels 

required by EISA. The total benefit 

estimates were calculated by 

multiplying a marginal dollar value (i.e., 

cost per ton) of carbon emissions, also 

referred to as ‘‘social cost of carbon’’ 

(SCC), by the anticipated level of 

emissions reductions in tons. 

The SCC values underlying the 

benefits estimates for this rule represent 

U.S. government-wide interim values 

for SCC. As discussed below, federal 

agencies will use these interim values to 

assess some of the economic benefits of 

GHG reductions while an interagency 

workgroup develops SCC values for use 

in the long-term. The interim values 

should not be viewed as an expectation 

about the results of the longer-term 

process. Although these values were not 

used in the NPRM, some commenters 

raised issues with these values and the 

methodology used to develop them in 

response to their publication elsewhere. 

Many of these issues are being 

examined by the interagency 

workgroup. 

The rest of this Preamble section will 

provide the basis for the interim SCC 

values, and the estimates of the total 

climate-related benefits of the increased 

use of renewable fuels that follow from 

these interim values. As discussed 

below, the interim dollar estimates of 

the SCC represent a partial accounting 

of climate change impacts. 

In addition to the quantitative account 

presented in this section, a qualitative 

appraisal of climate-related impacts is 

published in Section V of today’s rule 

and in other recent climate change 

analyses. For example, EPA’s 

Endangerment and Cause or Contribute 

Findings for Greenhouse Gases under 

Section 202(a) of the Clean Air Act and 

the accompanying Technical Support 

Document (TSD) presents a summary of 

impacts and risks of climate change 

projected in the absence of actions to 

mitigate GHG emissions.352 The TSD 

synthesizes major findings from the best 

available scientific assessments of the 

scientific literature that have gone 

through rigorous and transparent peer 

review, including the major assessment 

reports of both the Intergovernmental 

Panel on Climate Change (IPCC) and the 

U.S. Climate Change Science Program 

(CCSP). 

2. Derivation of Interim Social Cost of 

Carbon Values 

The ‘‘social cost of carbon’’ (SCC) is 

intended to be a monetary measure of 

the incremental damage resulting from 

carbon dioxide (CO2) emissions, 

including (but not limited to) net 

agricultural productivity loss, human 

health effects, property damages from 

sea level rise, and changes in ecosystem 

services. Any effort to quantify and to 

monetize the consequences associated 

with climate change will raise serious 

questions of science, economics, and 

ethics. But with full regard for the limits 

of both quantification and monetization 

of impacts, the SCC can be used to 

provide an estimate of the social 

benefits of reductions in GHG 

emissions. 

For at least three reasons, any 

particular figure will be contestable. 

First, scientific and economic 

knowledge about the impacts of climate 

change continues to grow. With new 

and better information about relevant 

questions, including the cost, burdens, 

and possibility of adaptation, current 

estimates will inevitably change over 

time. Second, some of the likely and 

potential damages from climate 

change—for example, the loss of 

endangered species—are generally not 

included in current SCC estimates. 

These omissions may turn out to be 

significant in the sense that they may 

mean that the best current estimates are 

too low. As noted by the IPCC Fourth 

Assessment Report, ‘‘It is very likely that 

globally aggregated figures 

underestimate the damage costs because 

they cannot include many nonquantifiable impacts.’’ Third, when 

economic efficiency criteria, under 

specific assumptions, are juxtaposed 

with ethical considerations, the 

outcome may be controversial. These 

ethical considerations, including those 

involving the treatment of future 

generations, should and will also play a 

role in judgments about the SCC (see in 

particular the discussion of the discount 

rate, below). 

To date, SCC estimates presented in 

recent regulatory documents have 

varied within and among agencies, 

including DOT, DOE, and EPA. For 

example, a regulation proposed by DOT 

in 2008 assumed a value of $7 per 

metric tonne CO2 353 (2006$) for 2011 

emission reductions (with a range of $0– 

14 for sensitivity analysis). One of the 

regulations proposed by DOE in 2009 

used a range of $0–$20 (2007$). Both of 

these ranges were designed to reflect the 

value of damages to the United States 

resulting from carbon emissions, or the 

‘‘domestic’’ SCC. In the final MY2011 

CAFE EIS, DOT used both a domestic 

SCC value of $2/t-CO2 and a global SCC 

value of $33/t-CO2 (with sensitivity 

analysis at $80/t-CO2) (in 2006 dollars 

for 2007 emissions), increasing at 2.4% 

per year thereafter. The final MY2011 

CAFE rule also presented a range from 

$2 to $80/t-CO2. 

In the May 2009 proposal leading to 

today’s final rule, EPA identified 

preliminary SCC estimates that spanned 

three orders of magnitude. EPA’s May 

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354 74 FR 25094 (May 26, 2009). 

355Federal Register 40 CFR Parts 86 and 600, 

September 28, 2009 ‘‘Proposed Rulemaking To 

Establish Light-Duty Vehicle Greenhouse Gas 

Emission Standards and Corporate Average Fuel 

Economy Standards; Proposed Rule’’. 

356The Supreme Court recognized in 

Massachusetts v. EPA that a single action will not 

on its own achieve all needed GHG reductions, 

noting that ‘‘[a]gencies, like legislatures, do not 

generally resolve massive problems in one fell 

regulatory swoop.’’ See Massachusetts v. EPA, 549 

U.S. at 524 (2007). 

2009 proposal also presented 

preliminary global SCC estimates 

developed from a survey analysis of the 

peer reviewed literature (i.e., meta 

analysis). The global mean values from 

the meta analysis were $68 and $40/tCO2 for discount rates of 2% and 3% 

respectively (in 2006 real dollars for 

2007 emissions).354

Since publication of the May 2009 

proposal, a federal interagency working 

group has established a methodology for 

selecting a range of interim SCC 

estimates for use in regulatory analyses. 

Today’s final rule uses the five values 

for the SCC that are the outcome of this 

process. A complete description of the 

methodology used to generate this 

interim set of SCC estimates can be 

found in the RIA for this rule and in 

multiple other published rules, 

including a proposal to limit vehicle 

greenhouse gas emissions that requests 

public comment on the estimates and 

underlying methodology.355

It should be emphasized that the 

analysis here is preliminary. These 

interim estimates are being used for the 

short-term while an interagency group 

develops a more comprehensive 

characterization of the distribution of 

SCC values for future economic and 

regulatory analyses. The interim values 

should not be viewed as an expectation 

about the results of the longer-term 

process. 

This process will allow the 

workgroup to explore questions raised 

in the May 2009 proposal as they are 

relevant to the development of SCC 

values for use in the long-term. The 

workgroup may evaluate factors not 

currently captured in today’s estimates 

due to time constraints, such as the 

quantification of additional impact 

categories where possible and an 

uncertainty analysis. The 

Administration will seek comment on 

all of the scientific, economic, and 

ethical issues before establishing 

improved estimates for use in future 

rulemakings. 

The outcomes of the Administration’s 

process to develop interim values are 

judgments in favor of a) global rather 

than domestic values, b) an annual 

growth rate of 3%, and c) interim global 

SCC estimates for 2007 (in 2007 dollars) 

of $56, $34, $20, $10, and $5 per metric 

ton of CO2. As noted, this is an 

emphatically interim SCC value. The 

judgments herein will be subject to 

further scrutiny and exploration. 

3. Application of Interim SCC Estimates 

to GHG Emissions Reductions 

While no single rule or action can 

independently achieve the deep 

worldwide emissions reductions 

necessary to halt and reverse the growth 

of GHGs, the combined effects of 

multiple strategies to reduce GHG 

emissions domestically and abroad 

could make a major difference in the 

climate change impacts experienced by 

future generations.356 The projected net 

GHG emissions reductions associated 

with the increased use of renewable 

fuels reflect an incremental change to 

projected total global emissions. Given 

that the climate response is projected to 

be a marginal change relative to the 

baseline climate, we estimate the 

marginal value of changes in climate 

change impacts over time and use this 

value to measure the monetized 

marginal benefits of the GHG emissions 

reductions projected for the increased 

renewable fuel volumes required by 

EISA. 

Accordingly, EPA has used the set of 

interim, global SCC values described 

above to estimate the benefits of the 

increased use of renewable fuels. The 

interim SCC values for emissions in 

2007, which reflect the Administration’s 

interim interpretation of the current 

literature, are $5, $10, $20, $34, and 

$56, in 2007 dollars, and are based on 

a CO2 emissions change of 1 metric ton 

in 2007. Table VIII.C.3–1 presents the 

interim SCC values for both the years 

2007 and 2022 in 2007 dollars. 

TABLE VIII.C.3–1—INTERIM SCC SCHEDULE (2007$ PER METRIC TONNE OF CO2) 

Year 5% 5% 

(Newell-Pizer)* 

Average SCC 

from 3% and 5% 3% 3% (Newell-Pizer)* 

2007 ....................................................... $5 $10 $20 $34 $56 

2022 ....................................................... 8 16 30 53 88 

Note: The SCC values are dollar-year and emissions-year specific. These values are presented in 2007$, for individual year of emissions. To 

determine values for other years not presented in the table, use a 3% per year growth rate. SCC values represent only a partial accounting for 

climate impacts. 

* SCC values are adjusted based on Newell and Pizer (2003) to account to future uncertainty in discount rates. 

Table VIII.C.3–2 provides, for the low, 

base, and high cases, the average annual 

GHG emissions reductions in 2022. The 

annualized emissions reductions are 

multiplied by the SCC estimates for 

2022 from Table VIII.C.3–1 to produce 

the average annual monetized benefit 

from the emissions reductions for CO2- 

equivalent GHGs. This is equivalent to 

taking the time stream of emissions from 

the increase in renewable fuel volumes, 

multiplying them by the SCC (which is 

increasing at a rate of 3 percent per 

year), and then discounting the stream 

of benefits by 3 percent. 

TABLE VIII.C.3–2—AVERAGE ANNUAL EMISSIONS REDUCTION (MILLION METRIC TONNES CO2-e) AND MONETIZED

BENEFITS (MILLION 2007$) IN 2022 

Low case Base case High case 

Emissions Reductions ................................................................................................................. 136.104 138.411 140.291 

5% ................................................................................................................................................ $1,089 $1,107 $1,122 

5% (Newell-Pizer) ........................................................................................................................ $2,178 $2,215 $2,245 

Average SCC from 3% and 5% .................................................................................................. $4,138 $4,208 $4,265 

3% ................................................................................................................................................ $7,186 $7,308 $7,407 

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357The 2022 modeled scenarios assume the 

following: RFS1 reference case assumes 6.7 Bgal/yr 

ethanol and 0.38 Bgal/yr biodiesel; AEO2007 

reference case assumes 13.18 Bgal/yr ethanol and 

0.38 Bgal/yr biodiesel; RFS2 control case assumes 

34.14 Bgal/yr ethanol, 0.81 Bgal/yr biodiesel, and 

0.38 Bgal/yr renewable diesel. Please refer to 

Chapter 3.3 and Table 3.3–1 for more information 

about the renewable fuel volumes assumed in the 

modeled analyses and the corresponding emissions 

inventories. 

TABLE VIII.C.3–2—AVERAGE ANNUAL EMISSIONS REDUCTION (MILLION METRIC TONNES CO2-e) AND MONETIZED

BENEFITS (MILLION 2007$) IN 2022—Continued 

Low case Base case High case 

3% (Newell-Pizer) ........................................................................................................................ $11,976 $12,179 $12,344 

Table VIII.C.3–3 provides, for the 

high, base, and low cases, the monetized 

benefits from the emissions reductions 

from the increase in renewable fuel 

volumes for CO2-equivalent GHGs in 

2022. The SCC estimates for 2022 

increase at a rate of 3 percent per year, 

and are then multiplied by the stream of 

emissions for each respective year for 30 

years. The monetized benefits in table 

VIII.C.3–3 represent the net present 

value of these emissions for 30 years 

using a discount rate of 7 percent. 

TABLE VIII.C.3–3—MONETIZED BENEFITS (MILLION 2007$) OF RFS–2 VOLUMES IN 2022 USING A 7% DISCOUNT RATE

High Base Low 

5% ................................................................................................................................................ $606 $620 $631 

5% (Newell-Pizer) ........................................................................................................................ 1,212 1,239 1,262 

Average SCC from 3% and 5% .................................................................................................. 2,302 2,355 2,397 

3% ................................................................................................................................................ 3,999 4,089 4,163 

3% (Newell-Pizer) ........................................................................................................................ 6,665 6,816 6,939 

D. Criteria Pollutant Health and 

Environmental Impacts 

1. Overview 

This section describes EPA’s analysis 

of the co-pollutant health and 

environmental impacts that can be 

expected to occur as a result of the 

increase in renewable fuel use 

throughout the period from initial 

implementation of the RFS2 rule 

through 2022. Although the purpose of 

this final rule is to implement the 

renewable fuel requirements established 

by the Energy Independence and 

Security Act (EISA) of 2007, the 

increased use of renewable fuels will 

also impact emissions of criteria and air 

toxic pollutants and their resultant 

ambient concentrations. The fuels 

changes detailed in Section 3.1 of the 

RIA will influence emissions of VOCs, 

PM, NOX, and SOX and air toxics and 

affect exhaust and evaporative 

emissions of these pollutants from 

vehicles and equipment. They will also 

affect emissions from upstream sources 

such as fuel production, storage, 

distribution and agricultural emissions. 

Any decrease or increase in ambient 

ozone, PM2.5, and air toxics associated 

with the increased use of renewable 

fuels will impact human health in the 

form of a decrease or increase in the risk 

of incurring premature death and other 

serious human health effects, as well as 

other important public health and 

welfare effects. 

This analysis reflects the impact of 

the 2022 mandated renewable fuel 

volumes (the ‘‘RFS2 control case’’) 

compared with two different reference 

scenarios that include the use of 

renewable fuels: a 2022 baseline 

projection based on the RFS1-mandated 

volume of 7.1 billion gallons of 

renewable fuels, and a 2022 baseline 

projection based on the AEO 2007 

volume of roughly 13.6 billion gallons 

of renewable fuels.357 Thus, the results 

represent the impact of an incremental 

increase in ethanol and other renewable 

fuels. We note that the air quality 

modeling results presented in this final 

rule do not constitute the ‘‘antibacksliding’’ analysis required by Clean 

Air Act section 211(v). EPA will be 

analyzing air quality and health impacts 

of increased renewable fuel use through 

that study and will promulgate 

appropriate mitigation measures under 

section 211(v), separate from this final 

action. 

As can be seen in Section VI.D of this 

preamble, as well as in Section 3.4 of 

the RIA that accompanies this preamble, 

there are both increased and decreased 

concentrations of ambient criteria 

pollutants and air toxics. Overall, we 

estimate that the required renewable 

fuel volumes will lead to a net increase 

in criteria pollutant-related health 

impacts. By 2022, the final RFS2 

volumes relative to both reference case 

scenarios (RFS1 and AEO2007), are 

projected to adversely impact PM2.5 air 

quality over parts of the U.S., while 

some areas will experience decreases in 

ambient PM2.5. As described in Section 

VI, ambient PM2.5 is likely to increase as 

a result of emissions at biofuel 

production plants and from biofuel 

transport, both of which are more 

prevalent in the Midwest. PM 

concentrations are also likely to 

decrease in some areas. While the PMrelated air quality impacts are relatively 

small, the increase in populationweighted national average PM2.5

exposure results in a net increase in 

adverse PM-related human health 

impacts. (the increase in national 

population weighted annual average 

PM2.5 is 0.006 μg/m3 and 0.002 μg/m3 

relative to the RFS1 and AEO2007 

reference cases, respectively). 

The required renewable fuel volumes, 

relative to both reference scenarios, are 

also projected to adversely impact ozone 

air quality over much of the U.S., 

especially in the Midwest, Northeast 

and Southeast. These adverse impacts 

are likely due to increased upstream 

emissions of NOX in many areas that are 

NOX-limited (acting as a precursor to 

ozone formation). There are, however, 

ozone air quality improvements in some 

highly-populated areas that currently 

have poor air quality. This is likely due 

to VOC emission reductions at the 

tailpipe in urban areas that are VOClimited (reducing VOC’s role as a 

precursor to ozone formation). Relative 

to the RFS1 mandate reference case, the 

RFS2 volumes result in an increase in 

national ozone-related health impacts 

(population weighted maximum 8-hour 

average ozone increases by 0.177 ppb). 

Relative to the AEO2007 reference case, 

the RFS2 volumes result in an increase 

in national ozone-related health impacts 

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358U.S. Environmental Protection Agency. (2006). 

Final Regulatory Impact Analysis (RIA) for the 

Proposed National Ambient Air Quality Standards 

for Particulate Matter. Prepared by: Office of Air 

and Radiation. Retrieved March, 26, 2009 at 

http://www.epa.gov/ttn/ecas/ria.html. 

359U.S. Environmental Protection Agency. (2008). 

Final Ozone NAAQS Regulatory Impact Analysis. 

Prepared by: Office of Air and Radiation, Office of 

Air Quality Planning and Standards. Retrieved 

March, 26, 2009 at http://www.epa.gov/ttn/ecas/ 

ria.html. 

360U.S. Environmental Protection Agency (U.S. 

EPA). 2009a. Regulatory Impact Analysis: National 

Emission Standards for Hazardous Air Pollutants 

from the Portland Cement Manufacturing Industry. 

Office of Air Quality Planning and Standards, 

Research Triangle Park, NC. April. Available on the 

Internet at http://www.epa.gov/ttn/ecas/regdata/

RIAs/portlandcementria_4–20–09.pdf. 

361U.S. Environmental Protection Agency (U.S. 

EPA). 2009b. Proposed NO2 NAAQS Regulatory 

Impact Analysis (RIA). Office of Air Quality 

Planning and Standards, Research Triangle Park, 

NC. April. Available on the Internet at http:// 

www.epa.gov/ttn/ecas/regdata/RIAs/

proposedno2ria.pdf. Note: The revised NO2 

NAAQS may be final by the publication of this 

action. 

362U.S. Environmnetal Protection Agency (U.S. 

EPA). 2009c. Draft Regulatory Impact Analysis: 

Control of Emissions of Air Pollution from Category 

3 Marine Diesel Engines. Office of Transportation 

and Air Quality, June. Available on the Internet at 

http://www.epa.gov/otaq/regs/nonroad/

420d09002.htm. Note: The C3 rule may be final by 

the publication of this action. 

363 Information on BenMAP, including 

downloads of the software, can be found at 

http://www.epa.gov/ttn/ecas/benmodels.html. 

364Note that these impacts reflect the national 

total of PM-related benefits and disbenefits and 

ozone-related benefits and disbenefits. The sum of 

total of benefits and disbenefits yields a net 

negative benefit, or disbenefit. See Tables VIII.D.2– 

1 and VIII.D.2–2 for pollutant- and endpointspecific incidence estimates and Table VIII.D.3–1 

for pollutant- and endpoint specific monetized 

values. 

(population weighted maximum 8-hour 

average ozone increases by 0.116 ppb). 

The analysis of national-level PM2.5- 

and ozone-related health and 

environmental impacts associated with 

the required renewable fuel volumes is 

based on peer-reviewed studies of air 

quality and human health effects (see 

US EPA, 2006 and US EPA, 2008).358 359

We are also consistent with the benefits 

analysis methods that supported the 

recently proposed Portland Cement 

National Emissions Standards for 

Hazardous Air Pollutants (NESHAP) 

RIA (U.S. EPA, 2009a),360 the proposed 

NO2 primary NAAQS RIA (U.S. EPA, 

2009b),361 and the proposed Category 3 

Marine Diesel Engines RIA (U.S. EPA, 

2009c).362 These methods are described 

in more detail in the RIA that 

accompanies this preamble. To model 

the ozone and PM air quality impacts of 

the required renewable fuel volumes, 

we used the Community Multiscale Air 

Quality (CMAQ) model (see Section 

VI.D). The modeled ambient air quality 

data serves as an input to the 

Environmental Benefits Mapping and 

Analysis Program (BenMAP).363

BenMAP is a computer program 

developed by the U.S. EPA that 

integrates a number of the modeling 

elements used in previous analyses (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. 

The range of total national-level 

ozone- and PM-related monetized 

impacts associated with the required 

renewable fuel volumes is presented in 

Table VIII.D.1–1.364 We present total 

monetized impacts based on the PMand ozone-related premature mortality 

function used. Total monetized impacts 

therefore reflect the addition of each 

estimate of ozone-related premature 

mortality (each with its own row in 

Table VIII.D.1–1) to estimates of PMrelated premature mortality. These 

estimates represent EPA’s preferred 

approach to characterizing the best 

estimate of monetized impacts 

associated with the required renewable 

fuel volumes. 

Emissions and air quality modeling 

decisions were made early in the 

analytical process and as a result, there 

are a number of important limitations 

and uncertainties associated with the air 

quality modeling analysis that must be 

kept in mind when considering the 

results. A key limitation of the analysis 

is that it employed interim emission 

inventories, which were enhanced 

compared to what was described in the 

proposal, but did not include some of 

the later enhancements and corrections 

of the final emission inventories 

presented in this FRM (see Section VI.A 

through VI.C of this preamble). Most 

significantly, our modeling of the air 

quality impacts of RFS2 relied upon 

interim inventories that assumed that 

ethanol will make up 34 of the 36 

billion gallon renewable fuel mandate, 

that approximately 20 billion gallons of 

this ethanol will be in the form of E85, 

and that the use of E85 results in fewer 

emissions of direct PM2.5 from vehicles. 

The emission impacts, air quality results 

and benefits analysis would be different 

if, instead of E85, more non-ethanol 

biofuels are used or mid-level ethanol 

blends are approved and utilized. 

In fact, as explained earlier in this 

preamble, our more recent analyses 

indicate that ethanol and E85 volumes 

are likely to be significantly lower than 

what we assumed in the interim 

inventories. Furthermore, the final 

emission inventories do not include 

vehicle-related PM reductions 

associated with E85 use, as discussed in 

Section VI.A through VI.C. There are 

additional, important limitations and 

uncertainties associated with the 

interim inventories that must be kept in 

mind when considering the results, 

which are described in more detail in 

Section VI. While it is difficult to 

describe the overall impact of these 

limitations and uncertainties on the 

quantified and monetized health 

impacts of the increased renewable fuel 

volumes without updating the air 

quality modeling analysis, we believe 

the results are still useful for describing 

potential national-level health impacts. 

Additionally, after the air quality 

modeling was completed, we discovered 

an error in the way that PM2.5 emissions 

from locomotive engines were allocated 

to counties in the inventory. The 

mismatched allocations between the 

reference and control scenarios resulted 

in PM2.5 emission changes that were too 

high in some counties and too low in 

others, by varying degrees. As a result, 

we did not present the modeling results 

for specific localized PM2.5 impacts in 

Section VI.D. However, because the 

error was random and offsetting, there 

was very little impact on national-level 

PM2.5 emissions. An analysis of the 

error’s impact on the national emission 

inventories found that direct PM2.5

emissions were inflated by 8% relative 

to the AEO reference case and by 0.6% 

relative to the RFS1 reference case, 

leading to a small overestimation of 

national PM-related adverse health 

impacts. Note that this error did not 

impact other PM precursor inventories 

such as NOX and SO2. As a result, we 

have concluded that PM2.5 modeling 

results are still informative for nationallevel benefits assessment, particularly 

given that other uncertainties in the 

PM2.5 inventory (such as E85 usage, 

discussed below) have a more important 

(and offsetting) effect. 

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TABLE VIII.D.1–1—ESTIMATED 2022 MONETIZED PM- AND OZONE-RELATED HEALTH IMPACTS FROM THE MANDATED

RENEWABLE FUEL VOLUMES a

Premature ozone mortality 

function Reference 

Total benefits 

(billions, 2007$, 3% 

discount rate) b,c

Total benefits 

(billions, 2007$, 7% 

discount rate) b,c

2022 Total Ozone and PM Benefits, RFS2 Control Case Compared to RFS1 Reference Case a

Multi-city analyses ............... Bell et al., 2004 ................... Total: ¥$1.4 to ¥$2.8 ..................................................... Total: ¥$1.4 to ¥$2.6. 

PM: ¥$0.92 to ¥$2.3 ..................................................... PM: ¥$0.84 to ¥$2.0. 

Ozone: ¥$0.52 ................................................................ Ozone: ¥$0.52. 

Huang et al., 2005 .............. Total: ¥$1.8 to ¥$3.1 ..................................................... Total: ¥$1.7 to ¥$2.9. 

PM: ¥$0.92 to ¥$2.3 ..................................................... PM: ¥$0.84 to ¥$2.0. 

Ozone: ¥$0.83 ................................................................ Ozone: ¥$0.83. 

Schwartz, 2005 ................... Total: ¥$1.7 to ¥$3.0 ..................................................... Total: ¥$1.6 to ¥$2.8. 

PM: ¥$0.92 to ¥$2.3 ..................................................... PM: ¥$0.84 to ¥$2.0. 

Ozone: ¥$0.77 ................................................................ Ozone: ¥$0.77. 

Meta-analyses ..................... Bell et al., 2005 ................... Total: ¥$2.5 to ¥$3.8 ..................................................... Total: ¥$2.4 to ¥$3.6. 

PM: ¥$0.92 to ¥$2.3 ..................................................... PM: ¥$0.84 to ¥$2.0. 

Ozone: ¥$1.6 .................................................................. Ozone: ¥$1.6. 

Ito et al., 2005 ..................... Total: ¥$3.1 to ¥$4.5 ..................................................... Total: ¥$3.0 to ¥$4.2. 

PM: ¥$0.92 to ¥$2.3 ..................................................... PM: ¥$0.84 to ¥$2.0. 

Ozone: ¥$2.2 .................................................................. Ozone: ¥$2.2. 

Levy et al., 2005 ................. Total: ¥$3.1 to ¥$4.5 ..................................................... Total: ¥$3.1 to ¥$4.3. 

PM: ¥$0.92 to ¥$2.3 ..................................................... PM: ¥$0.84 to ¥$2.0. 

Ozone: ¥$2.2 .................................................................. Ozone: ¥$2.2. 

2022 Total Ozone and PM Benefits, RFS2 Control Case Compared to AEO Reference Case a

Multi-city analyses ............... Bell et al., 2004 ................... Total: ¥$0.63 to ¥$1.0 ................................................... Total: ¥$0.60 to 

¥$0.98. 

PM: ¥$0.29 to ¥$0.70 ................................................... PM: ¥$0.26 to ¥$0.63. 

Ozone: ¥$0.34 ................................................................ Ozone: ¥$0.34. 

Huang et al., 2005 .............. Total: ¥$0.84 to ¥$1.3 ................................................... Total: ¥$0.81 to ¥$1.2. 

PM: ¥$0.29 to ¥$0.70 ................................................... PM: ¥$0.26 to ¥$0.63. 

Ozone: ¥$0.55 ................................................................ Ozone: ¥$0.55. 

Schwartz, 2005 ................... Total: ¥$0.80 to ¥$1.2 ................................................... Total: ¥$0.77 to ¥$1.1. 

PM: ¥$0.29 to ¥$0.70 ................................................... PM: ¥$0.26 to ¥$0.63. 

Ozone: ¥$0.51 ................................................................ Ozone: ¥$0.51. 

Meta-analyses ..................... Bell et al., 2005 ................... Total: ¥$1.3 to ¥$1.8 ..................................................... Total: ¥$1.3 to ¥$1.7. 

PM: ¥$0.29 to ¥$0.70 ................................................... PM: ¥$0.26 to ¥$0.63. 

Ozone: ¥$1.0 .................................................................. Ozone: ¥$1.0. 

Ito et al., 2005 ..................... Total: ¥$1.7 to ¥$2.2 ..................................................... Total: ¥$1.7 to ¥$2.1. 

PM: ¥$0.29 to ¥$0.70 ................................................... PM: ¥$0.26 to ¥$0.63. 

Ozone: ¥$1.5 .................................................................. Ozone: ¥$1.5. 

Levy et al., 2005 ................. Total: ¥$1.8 to ¥$2.2 ..................................................... Total: ¥$1.7 to ¥$2.1. 

PM: ¥$0.29 to ¥$0.70 ................................................... PM: ¥$0.26 to ¥$0.63. 

Ozone: ¥$1.5 .................................................................. Ozone: ¥$1.5. 

Notes: 

aTotal includes premature mortality-related and morbidity-related ozone and PM 2.5 benefits. Range was developed by adding the estimate 

from the ozone premature mortality function to the estimate of PM 2.5- related premature mortality derived from either the ACS study (Pope et al., 

2002) or the Six-Cities study (Laden et al., 2006). b Note that total benefits presented here do not include a number of unquantified benefits categories. A detailed listing of unquantified health 

and welfare effects is provided in Table VIII.D.1–2. c Results reflect the use of both a 3 and 7 percent discount rate, as recommended by EPA’s Guidelines for Preparing Economic Analyses and 

OMB Circular A–4. Results are rounded to two significant digits for ease of presentation and computation. 

The monetized estimates in Table 

VIII.D.1–1 include all of the human 

health impacts we are able to quantify 

and monetize at this time. However, the 

full complement of human health and 

welfare effects associated with PM and 

ozone remain unquantified because of 

current limitations in methods or 

available data. 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 unable 

to quantify a number of known welfare 

effects, including acid and particulate 

deposition damage to cultural 

monuments and other materials, and 

environmental impacts of 

eutrophication in coastal areas. These 

are listed in Table VIII.D.1–2. 

TABLE VIII.D.1–2—UNQUANTIFIED AND NON-MONETIZED POTENTIAL EFFECTS FROM THE MANDATED RENEWABLE FUEL

VOLUMES

Pollutant/effects Effects not included in analysis—changes in: 

Ozone Healtha .......................................................................................... Chronic respiratory damageb. 

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TABLE VIII.D.1–2—UNQUANTIFIED AND NON-MONETIZED POTENTIAL EFFECTS FROM THE MANDATED RENEWABLE FUEL

VOLUMES—Continued 

Pollutant/effects Effects not included in analysis—changes in: 

Premature aging of the lungsb. 

Non-asthma respiratory emergency room visits. 

Exposure to UVb (+/¥)e. 

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 (+/¥)e. 

PM Healthc ............................................................................................... Premature mortality—short term exposuresd. 

Low birth weight. 

Pulmonary function. 

Chronic respiratory diseases other than chronic bronchitis. 

Non-asthma respiratory emergency room visits. 

Exposure to UVb (+/¥)e. 

PM Welfare ............................................................................................... Residential and recreational visibility in non-Class I areas. 

Soiling and materials damage. 

Damage to ecosystem functions. 

Exposure to UVb (+/¥)e. 

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. 

HC/Toxics Healthf ..................................................................................... Cancer (benzene, 1,3-butadiene, formaldehyde, acetaldehyde). 

Anemia (benzene). 

Disruption of production of blood components (benzene). 

Reduction in the number of blood platelets (benzene). 

Excessive bone marrow formation (benzene). 

Depression of lymphocyte counts (benzene). 

Reproductive and developmental effects (1,3-butadiene). 

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 .................................................................................... Direct toxic effects to animals. 

Bioaccumulation in the food chain. 

Damage to ecosystem function. 

Odor. 

Notes: 

aThe public health impact of biological responses such as increased airway responsiveness to stimuli, inflammation in the lung, acute inflammation and respiratory cell damage, and increased susceptibility to respiratory infection are likely partially represented by our quantified 

endpoints. bThe public health impact of effects such as chronic respiratory damage and premature aging of the lungs may be partially represented by 

quantified endpoints such as hospital admissions or premature mortality, but a number of other related health impacts, such as doctor visits and 

decreased athletic performance, remain unquantified. c 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. dWhile some of the effects of short-term exposures are likely to be captured in the estimates, there may be premature mortality due to shortterm 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. e May result in benefits or adverse health impacts. 

f Many of the key hydrocarbons related to this rule are also hazardous air pollutants listed in the Clean Air Act. 

While there will be impacts 

associated with air toxic pollutant 

emission changes that result from the 

increased use of renewable fuels, we do 

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 

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365Science 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. 

366 In April, 2009, EPA hosted a workshop on 

estimating the benefits or reducing hazardous air 

pollutants. This workshop built upon the work 

accomplished in the June 2000 Science Advisory 

Board/EPA Workshop on the Benefits of Reductions 

in Exposure to Hazardous Air Pollutants, which 

generated thoughtful discussion on approaches to 

estimating human health benefits from reductions 

in air toxics exposure, but no consensus was 

reached on methods that could be implemented in 

the near term for a broad selection of air toxics. 

Please visit http://epa.gov/air/toxicair/2009

workshop.html for more information about the 

workshop and its associated materials. 

367Woodruff, T.J., J. Grillo, and K.C. Schoendorf. 

1997. ‘‘The Relationship Between Selected Causes 

of Postneonatal Infant Mortality and Particulate Air 

Pollution in the United States.’’ Environmental 

Health Perspectives 105(6): 608–612. 

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.365 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 did not have the methods and tools 

available for national-scale application 

in time for the analysis of the final 

rule.366

2. Quantified Human Health Impacts 

Tables VIII.D.2–1 and VIII.D.2–2 

present the annual PM2.5 and ozone 

health impacts in the 48 contiguous U.S. 

states associated with the required 

renewable fuel volumes relative to both 

the RFS1 and AEO reference cases for 

2022. For each endpoint presented in 

Tables VIII.D.2–1 and VIII.D.2–2, we 

provide both the mean estimate and the 

90% confidence interval. 

Using EPA’s preferred estimates, 

based on the ACS and Six-Cities studies 

and no threshold assumption in the 

model of mortality, we estimate that the 

required renewable fuel volumes will 

result in between 110 and 270 cases of 

PM2.5-related premature deaths annually 

in 2022 when compared to the RFS1 

reference case. When compared to the 

AEO reference scenario, we estimate 

that the required renewable fuel 

volumes will result in between 33 and 

85 cases of PM2.5-related premature 

deaths annually in 2022. For ozonerelated premature mortality, we estimate 

that national changes in ambient ozone 

will contribute to between 54 to 250 

additional premature mortalities in 2022 

as a result of the required renewable 

fuel volumes relative to the RFS1 

scenario. When compared to the AEO 

reference scenario, we estimate that the 

required renewable fuel volumes will 

contribute to between 36 to 160 

additional ozone-related premature 

mortalities in 2022. 

TABLE VIII.D.2–1—ESTIMATED PM2.5-RELATED HEALTH IMPACTS ASSOCIATED WITH THE MANDATED RENEWABLE FUEL

VOLUMES a

Health effect 

2022 RFS2 Control case 

compared to RFS1 

reference case 

(5th%–95th%ile) 

2022 RFS2 Control case 

compared to AEO 

reference case 

(5th%–95th%ile) 

Premature Mortality—Derived from Epidemiology Literature b

Adult, age 30+, ACS Cohort Study (Pope et al., 2002) .......................................................... ¥110 

(¥42 –¥170) 

¥33 

(¥13 –¥53) 

Adult, age 25+, Six-Cities Study (Laden et al., 2006) ............................................................ ¥270 

(¥150 –¥400) 

¥85 

(¥46 –¥120) 

Infant, age <1 year (Woodruff et al., 1997) ............................................................................. 0 

(0 –¥1) 

0 

(0 –¥1) 

Chronic bronchitis (adult, age 26 and over) ............................................................................ ¥65 

(¥26 –¥110) 

¥19 

(¥4 –¥18) 

Non-fatal myocardial infarction (adult, age 18 and over) ........................................................ ¥180 

(¥65 –¥290) 

¥51 

(¥19 –¥84) 

Hospital admissions—respiratory (all ages) c .......................................................................... ¥26 

(¥25 –¥26) 

¥7 

(¥5 –¥8) 

Hospital admissions—cardiovascular (adults, age >18) d ....................................................... ¥55 

(¥44 –¥70) 

¥12 

(¥9 –¥16) 

Emergency room visits for asthma (age 18 years and younger) ............................................ ¥180 

(¥110 –¥260) 

¥99 

(¥58 –¥140) 

Acute bronchitis, (children, age 8–12) ..................................................................................... ¥160 

(¥0 –¥330) 

¥50 

(¥0 –¥100) 

Lower respiratory symptoms (children, age 7–14) .................................................................. ¥1,900 

(¥910 –¥2,900) 

¥600 

(¥290 –¥910) 

Upper respiratory symptoms (asthmatic children, age 9–18) ................................................. ¥1,400 

(¥450 –¥2,400) 

¥450 

(¥140 –¥750) 

Asthma exacerbation (asthmatic children, age 6–18) ............................................................. ¥1,700 

(¥190 –¥4,800) 

¥540 

(¥60 –¥1,500) 

Work loss days ........................................................................................................................ ¥11,000 

(¥10,000 –¥13,000) 

¥3,200 

(¥2,800 –¥3,700) 

Minor restricted activity days (adults age 18–65) ................................................................... ¥68,000 

(¥57,000 –¥78,000) 

¥19,000 

(¥16,000 –¥22.000) 

Notes: 

a Note that negative incidence expressed in this table reflects disbenefits; in other words, an increase in total aggregated national-level PM-related health impacts. Incidence is rounded to two significant digits. Estimates represent incidence within the 48 contiguous United States. bPM-related adult mortality based upon the American Cancer Society (ACS) Cohort Study (Pope et al., 2002) and the Six-Cities Study (Laden 

et al., 2006). Note that these are two alternative estimates of adult mortality and should not be summed. PM-related infant mortality based upon 

a study by Woodruff, Grillo, and Schoendorf, (1997).367

c Respiratory hospital admissions for PM include admissions for chronic obstructive pulmonary disease (COPD), pneumonia and asthma. d Cardiovascular hospital admissions for PM include total cardiovascular and subcategories for ischemic heart disease, dysrhythmias, and 

heart failure. 

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TABLE VIII.D.2–2—ESTIMATED OZONE-RELATED HEALTH IMPACTS ASSOCIATED WITH THE MANDATED RENEWABLE FUEL

VOLUMES a

Health effect 

2022 RFS2 Control case 

compared to RFS1 

reference case 

(5th%–95th%ile) 

2022 RFS2 Control case 

compared to AEO 

reference case 

(5th%–95th%ile) 

Premature Mortality, All ages b

Multi-City Analyses 

Bell et al. (2004)—Non-accidental ................................................................................... ¥54 

(¥17 –¥92) 

¥36 

(¥10 –¥62) 

Huang et al. (2005)—Cardiopulmonary ........................................................................... ¥90 

(¥31 –¥149) 

¥59 

(¥18 –¥100) 

Schwartz (2005)—Non-accidental .................................................................................... ¥83 

(¥24 –¥140) 

¥55 

(¥13 –¥97) 

Meta-analyses: 

Bell et al. (2005)—All cause ............................................................................................. ¥180 

(¥80 –¥270) 

¥120 

(¥49 –¥180) 

Ito et al. (2005)—Non-accidental ..................................................................................... ¥240 

(¥140 –¥350) 

¥160 

(¥90 –¥230) 

Levy et al. (2005)—All cause ........................................................................................... ¥250 

(¥170 –¥330) 

¥160 

(¥110 –¥220) 

Hospital admissions—respiratory causes (adult, 65 and older) c ............................................ ¥470 

(¥20 –¥860) 

¥310 

(¥5 –¥580) 

Hospital admissions—respiratory causes (children, under 2) ................................................. ¥83 

(¥24 –¥140) 

¥190 

(¥52 –¥330) 

Emergency room visit for asthma (all ages) ........................................................................... ¥260 

(0 –¥740) 

¥180 

(0 –¥510) 

Minor restricted activity days (adults, age 18–65) .................................................................. ¥300,000 

(¥110,000 –¥500,000) 

¥200,000 

(¥59,000 –¥340,000) 

School absence days .............................................................................................................. ¥110,000 

(¥35,000 –¥180,000) 

¥75,000 

(¥19,000 –¥120,000) 

Notes: 

a Note that negative incidence expressed in this table reflects disbenefits; in other words, an increase in total aggregated national-level ozonerelated health impacts. Incidence is rounded to two significant digits. Estimates represent incidence within the 48 contiguous United States. Note 

that negative incidence estimates represent additional cases of an endpoint related to pollution increases associated with the increased use of 

renewable fuels. bEstimates of ozone-related premature mortality are based upon incidence estimates derived from several alternative studies: Bell et al. 

(2004); Huang et al. (2005); Schwartz (2005) ; Bell et al. (2005); Ito et al. (2005); Levy et al. (2005). The estimates of ozone-related premature 

mortality should therefore not be summed. c Respiratory hospital admissions for ozone include admissions for all respiratory causes and subcategories for COPD and pneumonia. 

3. Monetized Impacts 

Table VIII.D.3–1 presents the 

estimated monetary value of the 

increase in ozone and PM2.5-related 

health effects incidence associated with 

the required renewable fuel volumes 

relative to both the RFS1 and AEO 

reference cases for 2022. All monetized 

estimates are stated in 2007$. These 

estimates account for growth in real 

gross domestic product (GDP) per capita 

between the present and the year 2022. 

As the table indicates, total adverse 

health impacts are driven primarily by 

the increase in PM2.5- and ozone-related 

premature fatalities. 

Our estimate of monetized adverse 

health impacts in 2022 for the required 

renewable fuel volumes relative to the 

RFS1 reference case, using the ACS and 

Six-Cities PM mortality studies and the 

range of ozone mortality assumptions, 

are between $1.4 billion and $4.5 

billion, assuming a 3 percent discount 

rate, or between $1.4 billion and $4.3 

billion, assuming a 7 percent discount 

rate. The total monetized adverse health 

impacts in 2022 for the required 

renewable fuel volumes relative to the 

AEO reference case are between $0.63 

billion and $2.2 billion assuming a 3 

percent discount rate, and between 

$0.60 billion and $2.1 billion assuming 

a 7 percent discount rate. We are unable 

to quantify a number of health and 

environmental impact categories (see 

Table VIII.D.1–2). These unquantified 

impacts may be substantial, although 

their magnitude is highly uncertain. 

TABLE VIII.D.3–1—ESTIMATED MONETARY VALUE OF HEALTH AND WELFARE EFFECT INCIDENCE

[In millions of 2007$] a b

2022 RFS2 Control 

case compared to 

RFS1 reference case 

2022 RFS2 Control 

case compared to AEO 

reference case 

PM2.5-Related Health Effect Estimated Mean Value of Reductions 

(5th and 95th %ile) 

Premature Mortality—Derived from Epidemiology Studies c d

Adult, age 30+ —ACS study (Pope et al., 2002): 

3% discount rate ........................................................................................................... ¥$860 

(¥$100–¥$2,300 ) 

¥$270 

(¥$32–¥$700 ) 

7% discount rate ........................................................................................................... ¥$770 

(¥$91–¥$2,000 ) 

¥$240 

(¥$28–¥$630 ) 

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TABLE VIII.D.3–1—ESTIMATED MONETARY VALUE OF HEALTH AND WELFARE EFFECT INCIDENCE—Continued 

[In millions of 2007$] a b

2022 RFS2 Control 

case compared to 

RFS1 reference case 

2022 RFS2 Control 

case compared to AEO 

reference case 

Adult, age 25+ —Six-cities study (Laden et al., 2006): 

3% discount rate ........................................................................................................... ¥$2,200 

(¥$29–¥$5,500 ) 

¥$680 

(¥$90–¥$1,700 ) 

7% discount rate ........................................................................................................... ¥$2,000 

(¥$26–¥$5,000 ) 

¥$620 

(¥$81–¥$1,600 ) 

Infant Mortality, <1 year—(Woodruff et al. 1997) ................................................................. ¥$4.0 

(¥$3.0–¥$15 ) 

¥$1.7 

(¥$1.3–¥$6.7 ) 

Chronic bronchitis (adults, 26 and over) ..................................................................................... ¥$32 

(¥$2.5–¥$110 ) 

¥$9.4 

(¥$0.72–¥$33 ) 

Non-fatal acute myocardial infarctions: 

3% discount rate ................................................................................................................... ¥$23 

(¥$4.1–¥$58 ) 

¥$6.6 

(¥$1.0–¥$17 ) 

7% discount rate ................................................................................................................... ¥$23 

(¥$3.8–¥$58 ) 

¥$6.4 

(¥$0.95–¥$16 ) 

Hospital admissions for respiratory causes ................................................................................. ¥$0.39 

(¥$0.19–¥$0.57 

¥$0.11 

(¥$0.06–¥$0.17 ) 

Hospital admissions for cardiovascular causes .......................................................................... ¥$1.5 

(¥$0.96–¥$2.1 ) 

¥$0.33 

(¥$0.20–¥$0.45 ) 

Emergency room visits for asthma .............................................................................................. ¥$0.07 

(¥$0.04–¥$0.10 ) 

¥$0.04 

(¥$0.02–¥$0.06 ) 

Acute bronchitis (children, age 8–12) .......................................................................................... ¥$0.01 

($0–¥$0.03 ) 

¥$0.004 

($0–¥$0.01 ) 

Lower respiratory symptoms (children, 7–14) ............................................................................. ¥$0.04 

(¥$0.01–¥$0.07 ) 

¥$0.01 

(¥$0.004–¥$0.02 ) 

Upper respiratory symptoms (asthma, 9–11) .............................................................................. ¥$0.04 

(¥$0.01–¥$0.10 ) 

¥$0.01 

(¥$0.004–¥$0.03 ) 

Asthma exacerbations ................................................................................................................. ¥$0.09 

(¥$0.009–¥$0.28 ) 

¥$0.03 

(¥$0.003–¥$0.09 ) 

Work loss days ............................................................................................................................ ¥$1.7 

(¥$1.5–¥$1.9 ) 

¥$0.49 

(¥$0.42–¥$0.55 ) 

Minor restricted¥activity days (MRADs) ..................................................................................... ¥$4.3 

(¥$2.5–¥$6.2 ) 

¥$1.2 

(¥$0.69–¥$1.7 ) 

Ozone-related Health Effect 

Premature Mortality, All ages—Derived from Multi-city analyses: 

Bell et al., 2004 .................................................................................................................... $480 

(¥$51–¥$1,300 ) 

¥$320 

(¥$32–¥$880 ) 

Huang et al., 2005 ................................................................................................................ ¥$800 

(¥$90–¥$2,200 ) 

¥$530 

(¥$56–¥$1,400 ) 

Schwartz, 2005 ..................................................................................................................... ¥$740 

(¥$76–¥$2,000 ) 

¥$490 

(¥$48–¥$1,300 ) 

Premature Mortality, All ages—Derived from Meta-analyses: 

Bell et al., 2005 .................................................................................................................... ¥$1,600 

(¥$200–¥$4,000 ) 

¥$1,000 

(¥$130–¥$,700 ) 

Ito et al., 2005 ...................................................................................................................... ¥$2,200 

(¥$290–¥$5,400 ) 

¥$1,400 

(¥$190–¥$3,600 ) 

Levy et al., 2005 ................................................................................................................... ¥$2,200 

(¥$300–¥$5,300 ) 

¥$1,400 

(¥$200–¥$3,500 ) 

Hospital admissions—respiratory causes (adult, 65 and older) .................................................. ¥$11 

(¥$0.49–¥$20 ) 

¥$7.4 

(¥$0.13–¥$14 ) 

Hospital admissions—respiratory causes (children, under 2) ..................................................... ¥$3.0 

(¥$1.0–¥$4,9 ) 

¥$1.9 

(¥$0.52–¥$3.3 ) 

Emergency room visit for asthma (all ages) ............................................................................... ¥$0.10 

(¥$0.009–¥$0.26 ) 

¥$0.07 

(¥$0.008–¥$0.18 ) 

Minor restricted activity days (adults, age 18–65) ...................................................................... ¥$19 

(¥$6.4–¥$35 ) 

¥$13 

(¥$3.6–¥$24 ) 

School absence days .................................................................................................................. ¥$10 

(¥$3.1–¥$16 ) 

¥$6.7 

(¥$1.7–¥$11 ) 

Notes: 

a Negatives indicate a disbenefit, or an increase in health effect incidence. Monetary impacts are rounded to two significant digits for ease of 

presentation and computation. PM and ozone impacts are nationwide. b Monetary impacts adjusted to account for growth in real GDP per capita between 1990 and the analysis year (2022). 

cValuation assumes discounting over the SAB recommended 20 year segmented lag structure. Results reflect the use of 3 percent and 7 percent discount rates consistent with EPA and OMB guidelines for preparing economic analyses. 

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368National Research Council (NRC), 2008. 

Estimating Mortality Risk Reduction and Economic 

Benefits from Controlling Ozone Air Pollution. The 

National Academies Press: Washington, DC. 

369National Research Council (NRC). 2002. 

Estimating the Public Health Benefits of Proposed 

Air Pollution Regulations. The National Academies 

Press: Washington, DC. 

370U.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. Available at 

http://www.epa.gov/ttn/ecas/ria.html. 

4. What Are the Limitations of the 

Health Impacts Analysis? 

Every benefit-cost analysis examining 

the potential effects of a change in 

environmental protection requirements 

is limited to some extent by data gaps, 

limitations in model capabilities (such 

as geographic coverage), and 

uncertainties in the underlying 

scientific and economic studies used to 

configure the benefit and cost models. 

Limitations of the scientific literature 

often result in the inability to estimate 

quantitative changes in health and 

environmental effects, such as 

premature mortality associated with 

exposure to carbon monoxide. 

Deficiencies in the economics literature 

often result in the inability to assign 

economic values even to those health 

and environmental outcomes which can 

be quantified. These general 

uncertainties in the underlying 

scientific and economics literature, 

which can lead to valuations that are 

higher or lower, are discussed in detail 

in the RIA and its supporting references. 

Key uncertainties that have a bearing on 

the results of the benefit-cost analysis of 

the coordinated strategy include the 

following: 

• The exclusion of potentially 

significant and unquantified benefit 

categories (such as health, odor, and 

ecological benefits of reduction in air 

toxics, ozone, and PM); 

• Errors in measurement and 

projection for variables such as 

population growth; 

• Uncertainties in the estimation of 

future year emissions inventories and 

air quality; 

• Uncertainty in the estimated 

relationships of health and welfare 

effects to changes in pollutant 

concentrations including the shape of 

the C–R function, the size of the effect 

estimates, and the relative toxicity of the 

many components of the PM mixture; 

• Uncertainties in exposure 

estimation; and 

• Uncertainties associated with the 

effect of potential future actions to limit 

emissions. 

As Table VIII.D.3–1 indicates, total 

impacts are driven primarily by the 

additional premature mortalities 

estimated to occur each year. Some key 

assumptions underlying the premature 

mortality estimates include the 

following, which may also contribute to 

uncertainty: 

• Inhalation of fine particles is 

causally associated with premature 

death at concentrations near those 

experienced by most Americans on a 

daily basis. Although biological 

mechanisms for this effect have not yet 

been completely established, the weight 

of the available epidemiological, 

toxicological, and experimental 

evidence supports an assumption of 

causality. The impacts of including a 

probabilistic representation of causality 

were explored in the expert elicitationbased results of the PM NAAQS RIA. 

• All fine particles, regardless of their 

chemical composition, are equally 

potent in causing premature mortality. 

This is an important assumption, 

because PM related to fuel use in mobile 

sources may differ significantly from 

PM precursors released from electric 

generating units and other industrial 

sources. However, no clear scientific 

grounds exist for supporting differential 

effects estimates by particle type. 

• The C–R function for fine particles 

is approximately linear within the range 

of ambient concentrations under 

consideration. Thus, the estimates 

include health benefits from reducing 

fine particles in areas with varied 

concentrations of PM, including both 

regions that may be in attainment with 

PM2.5 standards and those that are at 

risk of not meeting the standards. 

• There is uncertainty in the 

magnitude of the association between 

ozone and premature mortality. The 

range of ozone impacts associated with 

the increased use of renewable fuels is 

estimated based on the risk of several 

sources of ozone-related mortality effect 

estimates. In a recent report on the 

estimation of ozone-related premature 

mortality published by the National 

Research Council, 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 

impacts of reducing ozone exposure.368

EPA has requested advice from the 

National Academy of Sciences on how 

best to quantify uncertainty in the 

relationship between ozone exposure 

and premature mortality in the context 

of quantifying health impacts. 

Acknowledging the omission of a 

range of health and environmental 

impacts, and the uncertainties 

mentioned above, we present a best 

estimate of the total monetized impacts 

based on our interpretation of the best 

available scientific literature and 

methods supported by EPA’s technical 

peer review panel, the Science Advisory 

Board’s Health Effects Subcommittee 

(SAB–HES). The National Academies of 

Science (NRC, 2002) has also reviewed 

EPA’s methodology for analyzing air 

pollution-related health and 

environmental impacts. EPA addressed 

many of these comments in the analysis 

of the final PM NAAQS.369 370 This 

analysis incorporates this most recent 

work to the extent possible. 

E. Summary of Costs and Benefits 

Presented in this section are a 

summary of costs, benefits, and net 

benefits of the renewable fuel volumes 

required by final RFS2 program. Table 

VIII.E–1 shows the estimated annual 

societal costs and benefits of the 

increased use of renewable fuels in 

2022. The table also presents estimated 

annual net benefits for 2022. In this 

table, fuel savings are presented as 

negative costs associated with the 

increased use of renewable fuels (rather 

than positive savings). Note that all 

costs and benefits are presented in 

annual terms; we were unable to 

estimate a stream of costs and benefits 

for many of the cost-benefit categories 

and were therefore unable to estimate 

net present value. 

Table VIII.E–1 presents the benefits of 

reduced GHG emissions—and 

consequently the annual quantified 

benefits (i.e., total benefits) and 

quantified net benefits—for each of five 

interim SCC values considered by EPA. 

As discussed in Section VIII.C, there is 

a very high probability (very likely 

according to the IPCC) that the benefit 

estimates from GHG reductions are 

underestimates because, in part, models 

used to calculate SCC values do not 

include information about impacts that 

have not been quantified. 

TABLE VIII.E–1—QUANTIFIED COSTS

AND BENEFITS OF THE VOLUMES REQUIRED BY RFS2 RELATIVE TO THE

AEO REFERENCE CASE IN 2022 

[Billions of 2007 dollars] 371

2022 

Quantified Annual Costs 

Overall Fuel Cost a ............ ¥$11.8. 

Quantified Annual Benefits 

Reduced GHG Emissions 

(by SCC): 

SCC 5% ......................... $0.6 to $1.1. 

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14852 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

371 In this table, we have included only the 

estimates from the sector models as they provided 

a more detailed breakdown of costs and benefits. 

We have excluded estimates of the agricultural 

sector impacts of the RFS2 in Table VIII F–1 since 

these impacts are considered economic rents. 

372U.S. Department of Agriculture, National 

Agricultural Statistics Service, ‘‘Crop Production’’, 

August 12, 2009, available online at: http:// 

usda.mannlib.cornell.edu/usda/current/CropProd/ 

CropProd-08-12-2009.pdf. 373Committee 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 pp. 

374U.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/EPASAB-08-003complete.unsigned.pdf. 

TABLE VIII.E–1—QUANTIFIED COSTS

AND BENEFITS OF THE VOLUMES REQUIRED BY RFS2 RELATIVE TO THE

AEO REFERENCE CASE IN 2022— 

Continued 

[Billions of 2007 dollars] 371

2022 

SCC 5% Newell-Pizer .... $1.2 to $2.2. 

SCC from 3% and 5% ... $2.4 to $4.2. 

SCC 3% ......................... $4.1 to $7.3. 

SCC 3% Newell-Pizer .... $6.8 to $12.2. 

PM2.5- and Ozone-Related 

Benefits b, c.

¥$0.63 to 

¥$2.2. 

Energy Security Impacts ... $2.6. 

Total Benefits (by SCC): 

SCC 5% ......................... $1 to $3.1. 

SCC 5% Newell-Pizer .... $1.6 to $4.2. 

SCC from 3% and 5% ... $2.8 to $6.2. 

SCC 3% ......................... $4.5 to $9.3. 

SCC 3% Newell-Pizer .... $7.2 to $14.2. 

Quantified Net Benefits 

Net Benefits (by SCC): 

SCC 5% ......................... $13 to $15. 

SCC 5% Newell-Pizer .... $13 to $16. 

SCC from 3% and 5% ... $15 to $18. 

SCC 3% ......................... $16 to $21. 

SCC 3% Newell-Pizer .... $19 to $26. 

a Negative costs represent fuel savings from 

decreased gasoline and diesel consumption. b Negative benefits indicate a disbenefit, or 

an increase in monetized health impacts. Total 

includes premature mortality-related and morbidity-related ozone and PM2.5 impacts. Range 

was developed by adding the estimate from 

the ozone premature mortality function to the 

estimate of PM2.5-related premature mortality 

derived from either the ACS study (Pope et 

al., 2002) or the Six-Cities study (Laden et al., 

2006). cThe PM2.5-related impacts presented in 

this table assume a 3% discount rate in the 

valuation of premature mortality to account for 

a twenty-year segmented cessation lag. If a 

7% discount rate had been used, the values 

would be approximately 9% lower. 

IX. Impacts on Water 

A. Background 

As the production of biofuels 

increases as required by this rule, there 

may be adverse impacts on both water 

quality and water quantity affecting 

drinking water sources and ecological 

habitats. The impacts could come from 

several different pathways: Growing 

crops for the biofuel feedstock as well 

as production, storage, and distribution 

of the biofuels. Increased production of 

biofuel crops may lead to changes in the 

management of cropland and the use of 

fertilizer and pesticides that could lead 

to greater loadings of nutrients, 

pesticides, and sediment to our water 

resources. While there are methods to 

minimize and mitigate the effects on 

water resources, there is still a potential 

to impact both human health and the 

environment. Since both the irrigation 

of corn and ethanol production use large 

quantities of water, the supply of water 

could also be significantly affected in 

some locations. 

1. Agriculture and Water Quality 

There are three major pathways for 

contaminants to reach water from 

agricultural lands: Run off from the 

land’s surface, man-made ditches or 

subsurface tile drains, and leaching to 

ground water. Many factors influence 

the potential for contaminants such as 

fertilizers, sediment, and pesticides to 

reach water from agricultural lands, 

including: Soil type, slope, climate, crop 

type, and management. Management of 

agricultural lands can take many forms, 

but key factors include nutrient and 

pesticide application rates and 

application methods, tillage, use of 

conservation practices and crop 

rotations by farmers, and acreage and 

intensity of artificially drained lands. 

To examine the potential waterrelated impacts of growing crops for 

biofuels, EPA focused its analysis on 

corn production for several reasons. 

First, corn acres have increased 

dramatically, 20% from 2006 to 2007. 

Although corn acres have since declined 

somewhat, total corn acres in 2009 

remained the second highest since 

1946.372 Second, corn kernels are 

currently the predominant and most 

economically viable feedstock for 

significant ethanol production. In 

addition, corn stover (stalks, leaves) will 

likely be the predominant feedstock for 

cellulosic ethanol production in the 

Upper Mississippi River Basin where 

we modeled water quality impacts. And 

third, corn production can contribute 

significantly to water pollution. Corn 

has the highest fertilizer and pesticide 

use per acre and accounts for the largest 

share of nitrogen fertilizer use among all 

crops.373 Corn generally utilizes only 40 

to 60 percent of the applied nitrogen 

fertilizer or the residual organic nitrogen 

from sources such as manure or 

soybeans. The remaining nitrogen is 

available to leave the field and run off 

to surface waters, leach into ground 

water, or volatilize to the air where it 

can return to water through depositional 

processes. 

Over the past 20 years, corn has been 

increasingly grown in rotation with 

other crops, especially soybeans. As 

corn prices increase relative to prices for 

other crops, more farmers choose 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 the 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 crop production such 

as hay land or pasture. Typically, 

agricultural producers apply far less 

fertilizers and pesticides on pasture 

land than land in row crops. Corn yield 

on these marginal lands will be lower 

and may require higher fertilizer rates. 

Disturbances of these soils can release 

nitrogen that has been stored in the soil. 

Since nitrogen fertilizer prices are tied 

to oil prices, fertilizer costs have 

fluctuated. How agricultural producers 

have responded to these changes in both 

corn and fertilizer prices is unclear. 

Artificial drainage is another 

important factor in determining the 

losses of nutrients from cropland. 

Artificial drainage consists either of 

subsurface tiles/pipes or man-made 

ditches that move water from wet soils 

to surface waters so crops can be 

planted. In a few areas, drains move 

water to wells and then groundwater 

instead of to surface water. Artificial 

drainage has transformed large expanses 

of historic wetland soils into productive 

agriculture lands. However, the artificial 

drains or ditches also move nutrients 

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 in areas of 

intensive corn production.374 Manmade 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14853 

375Committee on the Mississippi River and the 

Clean Water Act, National Research Council, 2008, 

Mississippi River Water Quality and the Clean 

Water Act: Progress, Challenges, and Opportunities, 

The National Academies Press, Washington, DC, 

252 pp. 

376Louisiana Universities Marine Consortium, 

2009, ‘Gulf of Mexico Dead Zone Surprising Small, 

but Severe, available online at: http:// 

www.gulfhypoxia.net/Research/ 

Shelfwide%20Cruises/2009/Files/ 

Press_Release.pdf. 

377Mississippi 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. 

378Alexander, 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. 

ditches predominate in areas like the 

Eastern Shore of the Chesapeake Bay. 

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). Conservation 

programs provide important funding to 

help agricultural producers implement 

practices to protect water quality and 

other resources. 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, 

the cost of farmland in Iowa increased 

an 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 crop production to 

plant grasses or trees. Generally farmers 

put land into CRP because it is less 

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 

implemented through these 

conservation programs 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. If 

producers believe that participation in 

conservation programs may reduce their 

profits, they may be less willing to 

participate and/or require higher 

payments to offset perceived losses. 

The water quality impacts of 

agricultural cellulosic feedstocks such 

as corn stover and switchgrass are 

unknown, since cellulosic ethanol is not 

currently produced commercially. Corn 

stover appears to be one of the most 

viable feedstock for cellulosic ethanol, 

especially in the Corn Belt states. When 

left in the field, corn stover maintains 

the soil organic carbon which has many 

benefits as a source of nutrients, 

preventing erosion by wind and water, 

and increasing soil aeration and water 

infiltration. If corn stover is 

overharvested, there may be impacts to 

both soil quality and water quality. 

Unlike corn, switchgrass is a native, 

perennial crop that does not require 

high inputs of fertilizers or pesticides. 

As a perennial crop, there is limited 

sediment runoff compared to annual 

crops. There is very minimal acreage of 

switchgrass grown at the present time, 

so it is difficult to predict what inputs 

farmers will use to cultivate it as a 

commercial crop. Some concern has 

been expressed about farmers increasing 

fertilizer application rates and irrigation 

on switchgrass to increase yields. 

2. 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 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 die 

if either oxygen is depleted or pH 

increases are severe. Both of these 

conditions are symptoms 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. 

Although the most widely known 

examples of significant nutrient impacts 

are in the Gulf of Mexico and the 

Chesapeake Bay, there are 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. 

3. Impacts to the Gulf of Mexico 

According to the National Research 

Council, nutrients and sediment are the 

two primary water quality problems in 

the Mississippi River Basin and the Gulf 

of Mexico.375 Production of corn for 

ethanol may exacerbate these existing 

serious water quality problems. 

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, 

shrimp, and other aquatic species 

cannot live in the low oxygen waters. 

The 2008 hypoxic zone was measured 

at 8,000 square miles, the second largest 

since measurements began in 1985.376

In 2009 models predicted an even larger 

hypoxic zone, but it was measured at 

only 3,000 square miles. A combination 

of below average high flows on the 

Mississippi River and winds that mixed 

Gulf waters are the likely causes of the 

reduced size of the 2009 zone. 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.377 The Action Plan 

states that an additional reduction in 

nitrogen and phosphorus beyond the 

45% would be necessary to account for 

increased corn production for ethanol 

and climate change impacts. 

Alexander, et al.378 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 delivery. 

Several recent scientific reports have 

estimated the impact of increasing 

ethanol feedstock acres in the Gulf of 

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379 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. 

380Costello, C.; Griffin, W.M.; Landis, A.E.; 

Matthew, H.S., 2009, Impact of biofuel crop 

production on the formation of hypoxia in the Gulf 

of Mexico, Environmental Science and Technology, 

43 (20), pp. 7985–7991. 

381 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. 

382U. S. Department of Energy, Energy 

Information Administration, Annual Energy 

Outlook 2007 With Projections to 2030, February 

2007, available on-line at: http://tonto.eia.doe.gov/ 

ftproot/forecasting/0383(2007).pdf. 

383U.S. Department of Agriculture, USDA 

Agricultural Projections to 2018, February 2009, 

available on-line at: http://www.ers.usda.gov/ 

Publications/OCE091/. 

Mexico watershed. Donner and 

Kucharik’s 379 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. The 

results of a study by Costello, et al. 

indicate that moving from corn to 

switchgrass and corn stover to produce 

ethanol will result in a 20% decrease in 

the nitrate outputs from the MississippiAtchafalaya River Basin. This decrease 

is not enough to meet the EPA target for 

reduction of the hypoxic zone 

reduction.380

B. Upper Mississippi River Basin 

Analysis 

To provide a quantitative estimate of 

the impact of the increased use of 

renewable fuels 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 also lie 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 concerns such as 

Gulf of Mexico hypoxia, large corn 

production, and numerous ethanol 

production plants. 

On average the UMRB contributes 

about 39% of the total nitrogen loads 

and 26% of the total phosphorus loads 

to the Gulf of Mexico. 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 artificially drained by 

tiles. Since the mid 1990s, the annual 

nitrate-nitrogen flux has steadily 

decreased. 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 and sediment 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.381

2. AEO 2007 Reference Case 

In order to assess alternative potential 

future conditions within the UMRB, 

EPA developed a SWAT model of a 

reference case scenario of current 

conditions against which to analyze the 

future impact of increased corn 

production. For the NPRM, we used a 

2005 baseline. For the final rule, we 

revised the baseline to correspond with 

the agricultural analysis described in 

Section VIII.A. Therefore we used the 

corn ethanol production baseline from 

the Annual Energy Outlook (AEO) 2007 

report382 as our reference case. We 

assumed that 33% of the corn produced 

in the UMRB was converted to corn 

ethanol, based on estimates from 

USDA.383 This baseline does not 

include corn ethanol produced at the 

volumes required by this rulemaking. 

The analysis assumes that no cellulosic 

ethanol, including ethanol produced 

from corn stover, would be produced in 

the reference case since the AEO report 

did not include cellulosic ethanol 

production in its estimates. 

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 

main stem 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 Reference Scenario model 

values to which the future alternatives 

are compared. 

Physical structures that disconnect 

fertile floodplains with seasonal 

fluctuation of stream and river levels 

also affect water quantity and quality by 

altering the ability of these soils to serve 

as a sink for nutrient rich waters. In lieu 

of data on where these structures are or 

may be constructed, these effects were 

not modeled. 

3. Reference Cases and RFS2 Control 

Case 

To assess the impacts of the increased 

use of corn ethanol, we modeled an 

RFS2 Control Case and compared it to 

both the AEO 2007 Reference Case and 

the RFS1 Mandate Reference Case for 

the years 2010, 2015, 2020, and 2022. 

The RFS2 national corn ethanol 

volumes of 11.24 billion gallons a year 

(BGY) for 2010, and 15 BGY for 2016 to 

2022 were adjusted for the UMRB. 

Annual increases in corn yield of 1.23% 

were built into the future scenarios. 

National average corn yields have been 

increasing primarily due to favorable 

weather conditions and improvement in 

practices to reduce stress on the corn 

plants from excess water, drought, and 

pests. Fewer corn acres were needed to 

meet ethanol production goals in the 

Control Case scenario after 2015 due to 

those yield increases. Corn acres 

increased 9% in 2022 between the AEO 

2007 Reference Case and the RFS2 (No 

Stover) Control Case. We were not able 

to model the impacts of corn stover 

removal at this time, so the analysis 

only reflects the impacts of increased 

use of corn grain for renewable fuel use. 

Tables IX.B.3–1 through IX.B.3–3 

compare the model outputs for nitrogen, 

phosphorus, and sediment between the 

AEO 2007 Reference Case and the RFS2 

(No Stover) Control Case scenarios for 

the years 2010, 2015, 2020, and 2022. 

Land load is the total amount of 

nitrogen or phosphorus that reaches a 

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stream within the UMRB. The total 

outflow is the nitrogen, phosphorus, or 

sediment measured at the outlet of the 

UMRB at Grafton, Illinois after 

accounting for in-stream loses due to 

uptake or assimilation. 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. The decreasing nutrient load 

over time is likely attributable to the 

increased average corn yield per acre, 

resulting in greater plant uptake of 

nitrogen and fewer corn acres planted to 

reach the ethanol production 

requirements of this rule. 

TABLE IX.B.3–1—AVERAGE ANNUAL NITROGEN LOADS: COMPARISON OF AEO 2007 REFERENCE CASE TO THE 2022 

RFS2 (NO STOVER) CONTROL CASE

[% difference in parentheses] 

Model run 

AEO 2007 reference case 2022 RFS2 (No Stover) Control case 

Total land load, 

million lbs 

Total outflow, 

million lbs 

Total land load, 

million lbs 

Total outflow, 

million lbs 

2010 ......................................................................................... 1948 1470 1944 (¥0.21) 1467 (¥0.20) 

2015 ......................................................................................... 1911 1441 1946 (1.83) 1469 (1.94) 

2020 ......................................................................................... 1887 1421 1912 (1.32) 1442 (1.48) 

2022 ......................................................................................... 1877 1413 1897 (1.07) 1430 (1.20) 

About 24 to 26% of the nitrogen and 

phosphorus leaving agricultural fields 

was assimilated (taken by aquatic plants 

or volatilized) before reaching the outlet 

of the UMRB. The assimilated nitrogen 

is not necessarily eliminated as an 

environmental concern. Five percent or 

more of the nitrogen can be converted 

to nitrous gas, a powerful greenhouse 

gas that has 300 times the climate 

warming potential of carbon dioxide, 

the major greenhouse. Thus, a water 

pollutant becomes an air pollutant until 

it is either captured through biological 

sequestration or converted fully to 

elemental nitrogen. 

TABLE IX.B.3–2—AVERAGE ANNUAL PHOSPHORUS LOADS: COMPARISON OF AEO 2007 REFERENCE CASE TO THE 2022 

RFS2 (NO STOVER) CONTROL CASE

[% difference in parentheses] 

Model run 

AEO 2007 Reference case 2022 RFS2 (No Stover) control case 

Total land load, 

million lbs 

Total outflow, 

million lbs 

Total land load, 

million lbs 

Total outflow, 

million lbs 

2010 ......................................................................................... 180.0 133.8 179.9 (¥0.06) 133.7 (¥0.07) 

2015 ......................................................................................... 178.2 132.3 179.6 (0.79) 133.6 (0.98) 

2020 ......................................................................................... 177.0 131.3 178.2 (0.68) 132.4 (0.84) 

2022 ......................................................................................... 176.5 130.9 177.6 (0.62) 131.8 (0.69) 

Total sediment outflow showed very 

little change over all scenarios. This 

result is primarily due to corn stover 

remaining on the field following harvest 

and therefore reducing sediment 

transport to water. 

TABLE IX.B.3–3—AVERAGE ANNUAL

SEDIMENT LOADS: COMPARISON OF

AEO 2007 REFERENCE CASE TO

THE 2022 RFS2 CONTROL CASE

[% difference in parentheses] 

Model run 

2007 AEO 2022 Control 

volume case 

Total outflow, 

million tons Total outflow, 

million tons 

2010 .......... 6.231 6.232 (0.02) 

2015 .......... 6.221 6.233 (0.19) 

2020 .......... 6.214 6.224 (0.16) 

2022 .......... 6.211 6.220 (0.14) 

The relationship between the number 

of acres of corn needed to produce 

ethanol and the crop yield is a complex 

relationship. Increased demand for corn 

based ethanol will not always result in 

increases in corn acres. Our modeling 

demonstrated that in less than a decade, 

increasing corn yields may counter the 

need for increased corn production 

resulting in the number of acres of corn 

stabilizing and additional nutrient and 

sediment loadings decreasing from the 

earlier peaks. 

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. For more details on the 

analysis, including comparisons with 

the RFS1, see Chapter 6 in the RIA. 

4. Case Study 

To evaluate local water quality 

impacts that are impossible to ascertain 

at the scale of the UMRB, we also 

modeled the Raccoon River watershed 

in central Iowa. The criteria for 

choosing this watershed included: 

Percentage of corn area representative of 

the UMRB, stream segments included in 

EPA’s 303(d) list of impaired waters due 

to high nutrient levels, biorefinery 

plants, drinking water intakes, and 

observed streamflow and water quality 

data. Nearly 88% of the watershed is in 

agriculture. 75% of the watershed 

produces corn and soybeans, mostly in 

rotation. Hay and other row crops are 

produced on the remaining agriculture 

land. The city of Des Moines makes up 

about 8% of the watershed. The state of 

Iowa has listed numerous stream 

segments of the Raccoon River as 

impaired. 

The case study used the same 

assumptions and scenarios as those 

used for the UMRB analysis. SWATsimulated streamflow and water quality 

(total nitrogen and phosphorus, and 

sediment loadings) were calibrated 

against observed data at both monthly 

and yearly time steps. 

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384Federal Leadership Committee for the 

Chesapeake Bay, November 9, 2009, Executive 

Order 13508: Draft Strategy for Protecting and 

Restoring the Chesapeake Bay, available on-line at: 

http://executiveorder.chesapeakebay.net/. 

As in the UMRB study, nitrogen loads 

to water increased for the future 

scenarios, though at a greater rate. 

Future phosphorus loads decreased in 

the Raccoon River model, where they 

had shown minor increases in the 

UMRB model. For the Raccoon River, 

there was a greater decrease in sediment 

load, which is the likely cause for the 

decrease in phosphorus loadings. 

5. Sensitivity Analysis 

Using the existing UMRB SWAT 

model, a sensitivity analysis was 

conducted on a number of important 

meteorological and management related 

factors. The goal was to further 

understand the model characteristics 

and sensitivities to parameters and 

input forcing functions that control the 

model response for the key 

environmental indicators of concern. 

Scenarios were constructed using four 

factors: fertilization application 

threshold, corn residue removal, daily 

air temperature, and daily precipitation. 

The results of the analysis showed that 

rainfall and temperature are the most 

influential factors for all model outputs: 

water yield, total nitrogen and 

phosphorus loadings, and sediment 

loadings. These results underscored the 

importance of representing these two 

driving factors accurately in hydrologic 

modeling. Corn residue removal 

noticeably reduced nutrient loading into 

streams while increasing sediment 

loads. However, since corn residue is 

the main source of organic nitrogen and 

phosphorus, the removal of the residue 

leads to the need for higher nutrient 

inputs in the growing season. The 

fertilization application threshold 

scenario did not tangibly impact water 

yield and sediment loading. The 

findings from this study indicated that 

future climate change could greatly 

influence water availability and 

pollution from corn cropland. 

C. Additional Water Issues 

The full water quality and water 

quantity impacts resulting from corn 

ethanol production go beyond the 

ability of our model. For example, the 

model does not account for fresh water 

constraints in irrigated agriculture in 

corn producing areas or predict future 

increases in drainage of agricultural 

lands. The following issues are 

summarized to provide additional 

context about the broader range of 

potential impacts. See Chapter 6 in the 

RIA for more discussion of these issues. 

1. Chesapeake Bay Watershed 

In May 2009, President Obama issued 

Executive Order 13508 on Chesapeake 

Bay Restoration and Protection. The 

order established a Federal Leadership 

Committee, chaired by EPA, and with 

senior representatives from the 

departments of Agriculture, Commerce, 

Defense, Homeland Security, Interior, 

and Transportation. In November 2009, 

these federal agencies released a draft 

strategy which contains a range of 

approaches for accelerating cleanup of 

the nation’s largest estuary and its vast 

watershed.384 The draft strategy calls for 

increased accountability and 

performance from pollution control, 

habitat protection and land conservation 

programs at all levels of government, 

including an expanded use of regulatory 

authorities to address pollution control 

and additional voluntary and marketbased solutions—particularly when it 

comes to habitat protection and land 

conservation programs. The proposed 

actions are in response to overwhelming 

scientific evidence that the health of the 

Chesapeake Bay remains exceptionally 

poor, despite the concerted restoration 

efforts of the past 25 years. 

Agricultural lands contribute more 

nutrients to the Chesapeake Bay than 

any other land use. 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 and Distribution 

a. 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 in-stream 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. 

b. 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 

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385 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. 

386Mackay, D.M., de Sieyes, N. R., Einarson, 

M.D., Feris, K.P., Pappas, A.A., Wood, I.A., 

Jacobson, L., Justice, L.G., Noske, M.N., Scow, K.M., 

and Wilson, J.T., 2006, Impact of ethanol on the 

natural attenuation of benzene, toluene, and 

o-Xylene in a normally sulfate-reducing aquifer, 

Environmental Science & Technology, v. 40, p. 

6123–6130. 

387Ruiz-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. 

388Scribner, E.A., Thurman, E.M., Goolsby, D.A., 

Meyer, M.T., Battaglin, W.A., and Kolpin, D.W., 

2005, Summary of significant results from studies 

Continued 

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 

cannot use the nutrients, the nutrients 

can run off 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 

pathogen, E. coli O157, than cattle 

without DGS in their diets.385 More 

research is needed to confirm these 

studies and devise methods to eliminate 

the potential risks. 

c. Ethanol Leaks and Spills from Fueling 

Stations 

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 from aboveground tanks or 

distribution systems that contaminate 

surface drinking water supplies, or 

surface waters. Additionally, in surface 

waters, rapid biodegradation of ethanol 

can result in depletion of dissolved 

oxygen with potential mortality to 

aquatic life. 

Regarding leaks or spills and drinking 

water impacts, ethanol biodegrades 

quickly and is not necessarily the 

pollutant of greatest concern in these 

situations. Instead, ethanol’s high 

biodegradability shifts the subsurface 

geochemistry, which can cause the 

reduced biodegradation of benzene, 

toluene, and xylene (up to 50% for 

toluene and 95% for benzene).386 The 

plume of BTEX compounds from a fuel 

spill (benzene, toluene, ethylbenzene 

and xylenes) can extend as much as 

70% farther in ground water and can 

persist longer, thereby increasing 

potential exposures to these 

compounds.387

Ethanol leak and spills from the 

approximately 600,000 gas stations in 

the U.S, could have a significant impact 

on water quality and drinking water 

supplies. Urban areas, that rely on 

ground water for drinking water would 

be affected most, especially where are 

existing water shortages. 

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. Federal regulations 

require that underground storage tank 

(UST) systems be compatible with the 

fuel stored. Because much of the current 

underground storage tank equipment 

was designed and tested for use with 

petroleum fuels, there may be many 

UST systems currently in use that 

contain materials that are incompatible 

with ethanol blends greater than 10%. 

Combined with the fact that ethanol is 

more corrosive than petroleum, there is 

concern regarding the increased 

potential for leaks from existing 

distribution systems, terminals and gas 

stations and subsequent impacts on 

water supplies. Given the practical 

challenges of determining the age and 

materials of underground storage 

equipment at approximately 233,000 

federally regulated facilities, it may be 

difficult or impossible to confirm the 

compatibility of current underground 

storage tanks and other tank-related 

hardware with ethanol blends. Further 

discussion of challenges in retail 

distribution are discussed in Section 1.6 

of the RIA. 

In 2008, there were 7,400 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 levels of BOD 

(biological oxygen demand) in process 

wastewater from biodiesel plants is 

highly variable. Most production 

processes produce washwater that has 

very high BOD levels. The high BOD 

levels 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. 

Although there is a commercial market 

for glycerin, the rapid development of 

the biodiesel industry has caused a glut 

of glycerin production and many 

facilities dispose of their glycerin. Poor 

handling of crude glycerin has resulted 

in disruptions at 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. 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 will result 

in the increased use of fertilizers and 

herbicides which can drain to surface 

water or ground water sources used by 

public water systems and individual 

home owners on private wells. This may 

increase the occurrence of nitrate, 

nitrite, and the herbicide Atrazine in 

sources of drinking water. The U.S. 

Geological Survey evaluated the fate 

and transport of herbicides in surface 

water, ground water, and in 

precipitation in the Midwest during the 

1990s. The results of these studies 

showed the occurrence and temporal 

distribution of herbicides and their 

associated degradation products in 

reservoir outflows.388

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of triazine herbicides and their degradation 

products in surface water, ground water, and 

precipitation in the Midwestern United States 

during the 1990s: U.S. Geological Survey Scientific 

Investigations Report 2005–5094, 27 p. 

Under the Safe Drinking Water Act, 

EPA has established enforceable 

standards for these contaminants that 

apply to public water systems. Source 

water contamination by these chemicals 

may raise local water system costs for 

treatment or for increased energy to 

pump water where ethanol production 

is accelerating the long running 

depletion of aquifers e.g., pumping extra 

water to grow the additional corn in 

addition to pumping extra water to 

process the corn into ethanol. There is 

also an (often concurrent) risk of 

exhausting local drinking water 

supplies where aquifers have been 

severely depleted. 

X. Public Participation 

Many interested parties participated 

in the rulemaking process that 

culminates with this final rule. This 

process provided opportunity for 

submitting written public comments 

following the proposal that we 

published on May 26, 2009 (74 FR 

24904), and we considered these 

comments in developing the final rule. 

In addition, we held a public hearing on 

the proposed rulemaking on June 9, 

2009, and we have considered 

comments presented at the hearing. 

Throughout the rulemaking process, 

EPA met with stakeholders including 

representatives from the fuel and 

renewable fuels industries, the 

agricultural sector, and others. The 

program we are finalizing today was 

developed as a collaborative effort with 

these stakeholders. 

We have prepared a detailed 

Summary and Analysis of Comments 

document, which describes the 

comments we received on the proposal 

and our response to each of these 

comments. The Summary and Analysis 

of Comments is available in the docket 

for this rule at the Internet address 

listed under ADDRESSES, as well as on 

the Office of Transportation and Air 

Quality Web site (http://www.epa.gov/ 

otaq/renewablefuels/index.htm). In 

addition, comments and responses for 

key issues are included throughout this 

preamble. 

XI. 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 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 final 

rule. 

B. Paperwork Reduction Act 

The information collection 

requirements in this 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 

requirements are not enforceable until 

OMB approves them. 

Information to be collected under this 

rulemaking includes compliance reports 

and reports regarding the generation and 

assignment of, and transactions 

involving, RINs. This final rule involves 

registration requirements, recordkeeping 

and reporting. Affected parties include 

producers of renewable fuels, importers, 

domestic and foreign refiners, exporters, 

domestic and foreign parties who own 

RINs, and biofuel feedstock producers. 

Individual items of recordkeeping and 

reporting are discussed in great detail in 

this preamble and in the ‘‘Supporting 

Statement for the Renewable Fuels 

Standard (RFS2) Final Rule,’’ which has 

been placed in the public docket. 

We estimate the annual recordkeeping 

and reporting burden for this rule at 3.2 

hours per response. We estimate a total 

of 1,060,026 respondents; 4,781,126 

responses; 1,485,008 burden hours, and 

a total cost associated with responding 

of $112,872,105. Burden is defined at 5 

CFR 1320.3(b). 

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. In 

addition, EPA is amending the table in 

40 CFR part 9 of currently approved 

OMB control numbers for various 

regulations to list the regulatory 

citations for the information 

requirements contained in this final 

rule. 

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 the renewable fuel volume 

requirements of RFS2 on small entities, 

small entity is defined as: (1) A small 

business as defined by the Small 

Business Administration’s (SBA) 

regulations at 13 CFR 121.201 (see table 

below); (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

The following table provides an 

overview of the primary SBA small 

business categories potentially affected 

by this regulation: 

Industry a

Defined as 

small entity by 

SBA if: 

NAICSa

codes 

Gasoline and 

diesel fuel refiners.

≤1,500 employees.324110 

a North American Industrial Classification 

System. 

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 

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389EPAct 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. 390This Direct Final Rule corrects minor 

typographical errors and provides clarification on 

existing provisions in the RFS1 regulations. 

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 the RFS program 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. 

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. 

3. Summary of Potentially Affected 

Small Entities 

The small entities that will potentially 

be subject to the RFS program 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 17 refiners, 

owning 20 refineries, 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.389 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 rule could be 

different than this estimate. 

4. Reporting, Recordkeeping, and 

Compliance 

Registration, reporting, and 

recordkeeping are necessary to track 

compliance with the RFS standards and 

transactions involving RINs. As 

discussed above in Sections II.J and 

III.A, the compliance requirements 

under the RFS2 rule are in many ways 

similar to those required under the 

RFS1 rule, with some modifications 

(e.g., those to account for the new 

requirements of EISA). New provisions 

being finalized in today’s action include 

the new EPA Moderated Transaction 

System (EMTS) which allows for ‘‘realtime’’ reporting of RIN generation 

transactions, and the ability for small 

blenders to ‘‘delegate’’ their RINseparation responsibilities to the party 

directly upstream. Please see Sections II 

and III of this preamble for more 

detailed information on these and other 

registration, recordkeeping, reporting, 

and compliance requirements of this 

final rule. 

5. Related Federal Rules 

We are aware of a few other current 

or proposed Federal rules that are 

related to this rule. The primary related 

Federal rules are: the first Renewable 

Fuel Standard (RFS1) rule (72 FR 23900, 

May 1, 2007), the RFS1 Technical 

Amendment Direct Final Rulemaking 

(73 FR 57248, October 2, 2008),390 and 

Control of Emissions from New Marine 

Compression-Ignition Engines at or 

Above 30 Liters per Cylinder (proposed 

rule: 74 FR 44442, August 28, 2009; 

final rule: Signed December 22, 2009). 

6. Steps Taken To Minimize the 

Significant Economic Impact on Small 

Entities 

a. Significant Panel Findings 

We convened a Small Business 

Advocacy Review Panel (SBAR Panel, 

or the Panel), which considered many 

regulatory options and flexibilities that 

would help mitigate potential adverse 

effects on small businesses as a result of 

the increased volumes of renewable fuel 

required by RFS2. During the SBREFA 

Panel process, the Panel sought out and 

received comments on the regulatory 

options and flexibilities that were 

presented to Small Entity 

Representatives (SERs) and Panel 

members. The major flexibilities and 

hardship relief provisions that were 

recommended by the Panel were 

proposed and some are being finalized 

today (for more information regarding 

the Panel process, see the SBREFA Final 

Panel Report, which is available in the 

public docket for this rule). 

b. Outreach With Small Entities (and the 

Panel Process) 

As required by section 609(b) of the 

RFA as amended by SBREFA, EPA 

conducted outreach to small entities 

and convened a SBAR Panel prior to 

proposing the RFS2 rule to obtain 

advice and recommendations of 

representatives of the small entities that 

potentially would be subject to the 

rule’s requirements. 

As part of the SBAR Panel process, we 

conducted outreach with 

representatives from the various small 

entities that would be affected by the 

rule. We met with these SERs to discuss 

the potential rulemaking approaches 

and potential options to decrease the 

impact of the rulemaking on their 

industries. The Panel received written 

comments from the SERs, specifically 

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 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 any negative 

impacts on small businesses. 

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, and the Panel 

recommended that all be considered in 

the development of the rule. 

A summary of the Panel’s 

recommendations, what the Agency 

proposed, and what is being finalized 

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today is discussed below. A detailed 

discussion of the regulatory alternatives 

and hardship provisions discussed and 

recommended by the Panel can be 

found in the SBREFA Final Panel 

Report, and a discussion of the 

provisions being finalized today is 

located in Section III.E of this preamble. 

c. Panel Recommendations, Proposed 

Provisions, and Provisions Being 

Finalized 

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 RFS2 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 were a 

possible extension of the temporary 

exemption for an additional two years 

following a study of small refineries by 

the Department of Energy (DOE) and 

provisions for case-by-case economic 

hardship relief. 

We proposed and took comment on 

the recommendations of the Panel and 

SERs above. As discussed in section 

III.E of this preamble, based on our 

analysis and further review of the 

provisions and the DOE Small Refinery 

Study, we have decided to finalize 

continuing the small refinery and small 

refiner exemption finalized in RFS1 

through December 31, 2010 for all small 

refiners. 

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 

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. 

We took comment on this provision, 

however we are not finalizing this 

provision, as we continue to believe that 

a phase-in of the applicable standards 

would in fact result in different 

standards for small refiners. 

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. 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. We noted during the 

Panel process that 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. 

Further, we noted our belief that 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 also 

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. 

We proposed a change to the RIN 

rollover cap, and took comment on the 

concept of allowing RINs to be used 

interchangeably for small refiners only. 

As noted above in section III of this 

preamble, we are not finalizing RINrelated provisions in today’s action. As 

highlighted in the NPRM, we continue 

to believe that the concept of 

interchangeable RINs for small refiners 

only 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). Further, given the 

findings from the DOE study, if small 

refineries and small refiners do not face 

disproportionate economic hardship, 

then we do not believe that we have the 

basis for granting such additional relief 

beyond what Congress already 

provided. Thus, small refiners will be 

held to the same RIN rollover cap as 

other obligated parties. 

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 

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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. 

We did propose that in the annual 

notice of the RFS standards that EPA 

must publish in the Federal Register, 

we would also include information to 

help inform industry about the RIN 

system. We also proposed that 

information from the annual Production 

Outlook Reports that producers and 

importers must submit to EPA, as well 

as information required in EMTS 

reports, could be used in the annual 

Federal Register notice to update RIN 

system progress. However, during the 

development of the final rule, it became 

evident that there could be instances 

where we would want to report out RIN 

system information on a more frequent 

basis than just once a year. Thus we are 

finalizing that we will report out 

elements of RIN system progress; but 

such information will be reported via 

other means (e.g., the RFS Web site 

(www.epa.gov/otaq/renewablefuels/ 

index.htm), EMTS homepage, etc.). 

Additionally, we will also publish 

annual summaries of the Production 

Outlook Reports. 

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. 

We did not propose and are not 

finalizing this hardship provision given 

the outcome of the DOE small refinery 

study. 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 

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 

stated in regulation section 80.1441). 

As discussed in section III.E of this 

preamble, since the only small refinery 

study available for us to use as a basis 

for whether or not to grant small 

refineries an automatic two-year 

extension of the exemption is the study 

that was performed in 2008, we had to 

use this study to develop this final rule. 

EPAct directs EPA to consider the DOE 

small refinery study in assessing the 

impacts to small refineries, and we 

interpret this to mean that any extension 

past December 31, 2010 has to be tied 

to the DOE Study. Further, since that 

study found that there was no 

disproportionate economic impact on 

small refineries, we cannot grant an 

automatic additional extension for small 

refineries or small refiners (except on a 

case-by-case hardship basis). However, 

this does not preclude small refiners 

from applying for case-by-case 

extensions of the small refiner 

temporary exemption. 

Note that if the revised DOE study 

(see Section III.E.3 of this preamble) 

finds that there is a disproportionate 

economic impact, we will revisit the 

extension of the temporary exemption at 

that point. 

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 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 allow 

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 finalizing 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). We are also 

finalizing a case-by-case hardship 

provision for those small refiners that 

do not operate small refineries (section 

80.1442(h)) using our discretion under 

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

provision will 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 hardship provision 

EPA will take into consideration 

information gathered from annual 

reports and RIN system progress 

updates, as recommended by the SBAR 

Panel. 

7. Conclusions 

Pursuant to section 603 of the RFA, 

EPA prepared an initial regulatory 

flexibility analysis (IRFA) for the 

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proposed rule and convened a Small 

Business Advocacy Review Panel to 

obtain advice and recommendations of 

representatives of the regulated small 

entities (see 74 FR 24904, May 26, 

2009). A detailed discussion of the 

Panel’s advice and recommendations is 

found in the Panel Report, located in the 

rulemaking docket. A summary of the 

Panel’s recommendations is presented 

at 74 FR 25106 (May 26, 2009). 

As required by section 604 of the 

RFA, we also prepared a final regulatory 

flexibility analysis (FRFA) for today’s 

final rule. The FRFA addresses the 

issues raised by public comments on the 

IRFA, which was part of the proposal of 

this rule. The FRFA is available for 

review in the docket and is summarized 

above. 

Many aspects of the RFS2 rule, such 

as the required amounts of annual 

renewable fuel volumes, are specified in 

EPAct and EISA. As discussed above, 

small refiners and small refineries 

receive an exemption from the RFS 

standards until January 1, 2011 and are 

not required to make expensive capital 

improvements like those required under 

other EPA fuels programs. Further, the 

DOE small refinery study did not find 

that there was a disproportionate 

economic impact on small refineries as 

a whole as a result of this rule (and the 

majority of the refiners that meet the 

definition of a small refiner, also own 

refineries that meet the Congressional 

small refinery definition). 

A cost-to-sales ratio test, a ratio of the 

estimated annualized compliance costs 

to the value of sales per company, was 

performed for gasoline and/or diesel 

small refiners. From this cost-to-sales 

test, it was estimated that all small 

entities have compliance costs that are 

less than one percent of their sales (a 

complete discussion of the costs to 

refiners as a result of the increased 

volumes of renewable fuel required by 

EISA is located in Section VII of this 

preamble). 

As required by section 212 of 

SBREFA, EPA also is preparing a Small 

Entity Compliance Guide to help small 

entities comply with this rule. This 

guide will be available on the RFS Web 

site (www.epa.gov/otaq/renewablefuels/ 

index.htm), and will be available 60 

days after the rule is finalized. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), 2 U.S.C. 

1531–1538, requires Federal agencies, 

unless otherwise prohibited by law, 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. 

This rule is not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. EPA 

has determined that this rule contains a 

Federal mandate that may result in 

expenditures of $100 million or more 

for the private sector in any one year, 

but the rule imposes no enforceable 

duty on any State, local or tribal 

governments. Nonetheless, EPA believes 

that today’s action represents the least 

costly, most cost-effective approach to 

achieve the statutory requirements of 

the rule. The costs and benefits 

associated with the increased use of 

renewable fuels are discussed above and 

in the 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 final 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 solicited comment on the 

proposed rule from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). 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 action. EPA 

specifically solicited comment on the 

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 subject to Executive 

Order 13211 (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, the increased use of renewable 

fuels enhances energy supply. 

Therefore, we have concluded that this 

rule is not likely to have any adverse 

energy effects. Our energy effects 

analysis is discussed in Section VIII.B. 

I. National Technology Transfer 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

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 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14863 

available and applicable voluntary 

consensus standards. 

This rulemaking changes 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 rulemaking incorporates 

the most recent version of that standard 

(ASTM D–6751–08) and adds several 

more voluntary consensus standards: 

ASTM D–1250–08, ‘‘Standard Guide for 

Use of the Petroleum Measurement 

Tables’’; ASTM D–4442, ‘‘Standard Test 

Methods for Direct Moisture Content 

Measurement of Wood and Wood-Base 

Materials’’; ASTM D–4444, ‘‘Standard 

Test Method for Laboratory 

Standardization and Calibration of 

Hand-Held Moisture Meters’’; ASTM 

D–6866–08 ‘‘Standard Test Methods for 

Determining the Biobased Content of 

Solid, Liquid, and Gaseous Samples 

Using Radiocarbon Analysis’’; ASTM 

E–711, ‘‘Standard Test Method for Gross 

Calorific Value of Refuse-Derived Fuel 

by the Bomb Calorimeter’’; and ASTM 

E–870, ‘‘Standard Test Methods for 

Analysis of Wood Fuels’’. Information 

about these standards may be obtained 

through the ASTM Web site (http:// 

www.astm.org) or by calling ASTM at 

(610) 832–9585. 

This rulemaking does not change 

these voluntary consensus standards, 

and does not involve any other 

technical standards. Therefore, EPA is 

not considering the use of any voluntary 

consensus standards other than those 

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 

rulemaking since the Agency is 

implementing specific standards 

established by Congress in statutes. 

Although EPA lacks authority to modify 

today’s regulatory action on the basis of 

environmental justice considerations, 

EPA nevertheless determined that this 

rule does not have a disproportionately 

high and adverse human health or 

environmental impact on minority or 

low-income populations. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this rule and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the United 

States prior to publication of the rule in 

the Federal Register. A Major rule 

cannot take effect until 60 days after it 

is published in the Federal Register. 

This action is a ‘‘major rule’’ as defined 

by 5 U.S.C. 804(2). This rule will be 

effective July 1, 2010. 

XII. Statutory Provisions and Legal 

Authority 

Statutory authority for the rule 

finalized today can be found in section 

211 of the Clean Air Act, 42 U.S.C. 

7545. Additional support for the 

procedural and compliance related 

aspects of today’s rule, including the 

recordkeeping requirements, come from 

Sections 114, 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, 

Administrative practice and procedure, 

Agriculture, Air pollution control, 

Confidential business information, 

Diesel Fuel, Energy, Forest and Forest 

Products, Fuel additives, Gasoline, 

Imports, Incorporation by reference, 

Labeling, Motor vehicle pollution, 

Penalties, Petroleum, Reporting and 

recordkeeping requirements. 

Dated: February 3, 2010. 

Lisa P. Jackson, 

Administrator. 

■ For the reasons set forth in the 

preamble, 40 CFR part 80 is 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 Who is an obligated party under 

the RFS program? 

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 Petition process for evaluation of 

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 reporting 

requirements under the RFS program? 

80.1452 What are the requirements related 

to the EPA Moderated Transaction 

System (EMTS)? 

80.1453 What are the product transfer 

document (PTD) requirements for the 

RFS program? 

80.1454 What are the recordkeeping 

requirements under the RFS program? 

80.1455 What are the small volume 

provisions for renewable fuel production 

facilities and importers? 

80.1456 What are the provisions for 

cellulosic biofuel waiver credits? 

80.1457–80.1459 [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? 

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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 RINgenerating foreign producers and 

importers of renewable fuels for which 

RINs have been generated by the foreign 

producer? 

80.1467 What are the additional 

requirements under this subpart for a 

foreign RIN owner? 

80.1468 Incorporation by reference. 

Subpart M—Renewable Fuel Standard 

§ 80.1400 Applicability. 

The provisions of this Subpart M shall 

apply for all renewable fuel produced 

on or after July 1, 2010, for all RINs 

generated on or after July 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. The definitions follow: 

Advanced biofuel means renewable 

fuel, other than ethanol derived from 

cornstarch, has lifecycle greenhouse gas 

emissions that are at least 50 percent 

less than baseline lifecycle greenhouse 

gas emissions. 

Annual cover crop means an annual 

crop, planted as a rotation between 

primary planted crops, or between trees 

and vines in orchards and vineyards, 

typically to protect soil from erosion 

and to improve the soil between periods 

of regular crops. 

Areas at risk of wildfire are those 

areas in the ‘‘wildland-urban interface’’, 

where humans and their development 

meet or intermix with wildland fuel. 

Note that, for guidance, the SILVIS 

laboratory at the University of 

Wisconsin maintains a Web site that 

provides a detailed map of areas 

meeting this criteria at: http://www.

silvis.forest.wisc.edu/projects/US_WUI_

2000.asp. The SILVIS laboratory is 

located at 1630 Linden Drive, Madison, 

Wisconsin 53706 and can be contacted 

at (608) 263–4349. 

Baseline lifecycle greenhouse gas 

emissions means the average lifecycle 

greenhouse gas emissions for gasoline or 

diesel (whichever is being replaced by 

the renewable fuel) sold or distributed 

as transportation fuel in 2005. 

Biodiesel means a mono-alkyl ester 

that meets ASTM D 6751 (incorporated 

by reference, see § 80.1468). 

Biogas means a mixture of 

hydrocarbons that is a gas at 60 degrees 

Fahrenheit and 1 atmosphere of 

pressure that is produced through the 

conversion of organic matter. Biogas 

that is used to generate RINs must be 

renewable fuel. Biogas includes 

propane, and landfill gas, manure 

digester gas, and sewage waste 

treatment gas. 

Biomass-based diesel means a 

renewable fuel that has lifecycle 

greenhouse gas emissions that are at 

least 50 percent less than baseline 

lifecycle greenhouse gas emissions and 

meets all of the requirements of 

paragraph (1) of this definition: 

(1)(i) Is a transportation fuel, 

transportation fuel additive, heating oil, 

or jet fuel. 

(ii) Meets the definition of either 

biodiesel or non-ester renewable diesel. 

(iii) Is registered as a motor vehicle 

fuel or fuel additive under 40 CFR part 

79, if the fuel or fuel additive is 

intended for use in a motor vehicle. 

(2) Renewable fuel that is coprocessed with petroleum is not 

biomass-based diesel. 

Cellulosic biofuel means renewable 

fuel derived from any cellulose, hemicellulose, or lignin that has lifecycle 

greenhouse gas emissions that are at 

least 60 percent less than the baseline 

lifecycle greenhouse gas emissions. 

Cellulosic diesel is any renewable fuel 

which meets both the definitions of 

cellulosic biofuel and biomass-based 

diesel, as defined in this section 

80.1401. Cellulosic diesel includes 

heating oil and jet fuel made from 

cellulosic feedstocks. 

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. 

Co-processed means that renewable 

biomass was simultaneously processed 

with fossil fuels or other non-renewable 

feedstock in the same unit or units to 

produce a fuel that is partially derived 

from renewable biomass. 

Corn oil extraction means the 

recovery of corn oil from the thin 

stillage and/or the DGS produced by a 

dry mill corn ethanol plant, most often 

by mechanical separation. 

Crop residue is the biomass left over 

from the harvesting or processing of 

planted crops from existing agricultural 

land and any biomass removed from 

existing agricultural land that facilitates 

crop management (including biomass 

removed from such lands in relation to 

invasive species control or fire 

management), whether or not the 

biomass includes any portion of a crop 

or crop plant. 

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 or aquatic crops. 

Diesel, for the purposes of this 

subpart, refers to any and all of the 

products specified at § 80.1407(e). 

Ecologically sensitive forestland 

means forestland that meets either of the 

following criteria: 

(1) An ecological community with a 

global or state ranking of critically 

imperiled, imperiled or rare pursuant to 

a State Natural Heritage Program. For 

examples of such ecological 

communities, see ‘‘Listing of Forest 

Ecological Communities Pursuant to 40 

CFR 80.1401; S1–S3 communities,’’ 

which is number EPA–HQ–OAR–2005– 

0161–1034.1 in the public docket, and 

‘‘Listing of Forest Ecological 

Communities Pursuant to 40 CFR 

80.1401; G1–G2 communities,’’ which is 

number EPA–HQ–OAR–2005–0161– 

2906.1 in the public docket. This 

material is available for inspection at 

the EPA Docket Center, EPA/DC, EPA 

West, Room 3334, 1301 Constitution 

Ave., NW., Washington DC. The 

telephone number for the Air Docket is 

(202) 566–1742. 

(2) Old growth or late successional, 

characterized by trees at least 200 years 

in age. 

EPA Moderated Transaction System, 

or EMTS, means a closed, EPA 

moderated system that provides a 

mechanism for screening and tracking 

Renewable Identification Numbers 

(RINs) as per § 80.1452. 

Existing agricultural land is cropland, 

pastureland, and 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, on 

December 19, 2007, was: 

(1) Nonforested; and 

(2) Actively managed as agricultural 

land or fallow, as evidenced by records 

which must be traceable to the land in 

question, which must include one of the 

following: 

(i) Records of sales of planted crops, 

crop residue, or livestock, or records of 

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purchases for land treatments such as 

fertilizer, weed control, or seeding. 

(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. 

Exporter of renewable fuel means: 

(1) A person that transfers any 

renewable fuel to a location outside the 

contiguous 48 states and Hawaii; and 

(2) A person that transfers any 

renewable fuel from a location in the 

contiguous 48 states or Hawaii to Alaska 

or a United States territory, unless that 

state or territory has received an 

approval from the Administrator to optin 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 person (or persons 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 and tree plantations. 

Tree covered areas in intensive 

agricultural crop production settings, 

such as fruit orchards or tree-covered 

areas in urban settings such as city 

parks, are not considered forestland. 

Fractionation of feedstocks means a 

process whereby seeds are divided in 

various components and oils are 

removed prior to fermentation for the 

production of ethanol. 

Fuel for use in an ocean-going vessel 

means, for this subpart only: 

(1) Any marine residual fuel (whether 

burned in ocean waters, Great Lakes, or 

other internal waters); 

(2) Emission Control Area (ECA) 

marine fuel, pursuant to §§ 80.2(ttt) and 

80.510(k) (whether burned in ocean 

waters, Great Lakes, or other internal 

waters); and 

(3) Any other fuel intended for use 

only in ocean-going vessels. 

Gasoline, for the purposes of this 

subpart, refers to any and all of the 

products specified at § 80.1407(c). 

Heating oil has the meaning given in 

§ 80.2(ccc). 

Importers. For the purposes of this 

subpart, an importer of transportation 

fuel or renewable fuel is any U.S. 

domestic person who: 

(1) Brings transportation fuel or 

renewable fuel into the 48 contiguous 

states of the United States or 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; or 

(2) Brings transportation fuel or 

renewable fuel into an area that has 

opted in to the program requirements of 

this subpart pursuant to § 80.1443 from 

a foreign country or from an area that 

has not opted in to the program 

requirements of this subpart. 

Motor vehicle has the meaning given 

in Section 216(2) of the Clean Air Act 

(42 U.S.C. 7550(2)). 

Naphtha means a renewable fuel or 

fuel blending component falling within 

the boiling range of gasoline. 

Neat renewable fuel is a renewable 

fuel to which 1% or less of gasoline (as 

defined in this section) or diesel fuel 

has been added. 

Non-ester renewable diesel means 

renewable fuel which is all of the 

following: 

(1) Registered as a motor vehicle fuel 

or fuel additive under 40 CFR Part 79, 

if the fuel or fuel additive is intended 

for use in a motor vehicle. 

(2) Not a mono-alkyl ester. 

Nonforested land means land that is 

not forestland. 

Nonroad vehicle has the meaning 

given in Section 216(11) of the Clean 

Air Act (42 U.S.C. 7550(11)). 

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 from 

existing agricultural land that may be 

used as feedstocks for renewable fuel, 

such as grains, oilseeds, sugarcane, 

switchgrass, prairie grass, duckweed, 

and other species (but not including 

algae species or planted trees), 

providing that they were intentionally 

applied by humans to the ground, a 

growth medium, a pond or tank, either 

by direct application as seed or plant, or 

through intentional natural seeding or 

vegetative propagation by mature plants 

introduced or left undisturbed for that 

purpose. 

Planted trees are trees harvested from 

a tree plantation. 

Pre-commercial thinnings are trees, 

including unhealthy or diseased trees, 

primarily removed to reduce stocking to 

concentrate growth on more desirable, 

healthy trees, or other vegetative 

material that is removed to promote tree 

growth. 

Renewable biomass means each of the 

following (including any incidental, de 

minimis contaminants that are 

impractical to remove and are related to 

customary feedstock production and 

transport): 

(1) Planted crops and crop residue 

harvested from existing agricultural 

land cleared or cultivated prior to 

December 19, 2007 and that was 

nonforested and either actively managed 

or fallow on December 19, 2007. 

(2) Planted trees and tree residue 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 actively 

managed on December 19, 2007. 

(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 the immediate 

vicinity of buildings and other areas 

regularly occupied by people, or of 

public infrastructure, in an area at risk 

of wildfire. 

(6) Algae. 

(7) Separated yard waste or food 

waste, including recycled cooking and 

trap grease, and materials described in 

§ 80.1426(f)(5)(i). 

Renewable fuel means a fuel which 

meets all of the requirements of 

paragraph (1) of this definition: 

(1)(i) Fuel that is produced from 

renewable biomass. 

(ii) Fuel that is used to replace or 

reduce the quantity of fossil fuel present 

in a transportation fuel, heating oil, or 

jet fuel. 

(iii) Has lifecycle greenhouse gas 

emissions that are at least 20 percent 

less than baseline lifecycle greenhouse 

gas emissions, unless the fuel is exempt 

from this requirement pursuant to 

§ 80.1403. 

(2) Ethanol covered by this definition 

shall be denatured as required and 

defined in 27 CFR parts 19 through 21. 

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Any volume of denaturant added to the 

undenatured ethanol by a producer or 

importer in excess of 2 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, for this subpart only, 

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 less 

than 1 acre composed primarily of trees 

established by hand- or machineplanting of a seed or sapling, or by 

coppice growth from the stump or root 

of a tree that was hand- or machineplanted. Tree plantations must have 

been cleared prior to December 19, 2007 

and must have been actively managed 

on December 19, 2007, as evidenced by 

records which must be traceable to the 

land in question, which must include: 

(1) Sales records for planted trees or 

tree residue together with other written 

documentation connecting the land in 

question to these purchases; 

(2) Purchasing records for seeds, 

seedlings, or other nursery stock 

together with other written 

documentation connecting the land in 

question to these purchases; 

(3) A written management plan for 

silvicultural purposes; 

(4) Documentation of participation in 

a silvicultural program sponsored by a 

Federal, state or local government 

agency; 

(5) Documentation of land 

management in accordance with an 

agricultural or silvicultural product 

certification program; 

(6) An agreement for land 

management consultation with a 

professional forester that identifies the 

land in question; or 

(7) Evidence of the existence and 

ongoing maintenance of a road system 

or other physical infrastructure 

designed and maintained for logging 

use, together with one of the abovementioned documents. 

Tree residue is slash and any woody 

residue generated during the processing 

of planted trees from tree plantations for 

use in lumber, paper, furniture or other 

applications, provided that such woody 

residue is not mixed with similar 

residue from trees that do not originate 

in tree plantations. 

Yard waste is leaves, sticks, pine 

needles, grass and hedge clippings, and 

similar waste from residential, 

commercial, or industrial areas (but not 

from forestlands or tree plantations). 

§ 80.1402 [Reserved] 

§ 80.1403 Which fuels are not subject to 

the 20% GHG thresholds? 

(a) For purposes of this section, the 

following definitions apply: 

(1) Baseline volume means the 

permitted capacity or, if permitted 

capacity cannot be determined, the 

actual peak capacity of a specific 

renewable fuel production facility on a 

calendar year basis. 

(2) Permitted capacity means 105% of 

the maximum permissible volume 

output of renewable fuel that is allowed 

under operating conditions specified in 

the most restrictive of all applicable 

preconstruction, construction and 

operating permits issued by regulatory 

authorities (including local, regional, 

state or a foreign equivalent of a state, 

and federal permits, or permits issued 

by foreign governmental agencies) that 

govern the construction and/or 

operation of the renewable fuel facility, 

reported as: 

(i) Annual volume output on a 

calendar year basis; or 

(ii) If the permit specifies maximum 

rated volume output on an hourly basis, 

then multiplying the hourly output by 

8,322 hours per year to obtain the 

annual output. 

(3) Actual peak capacity means 105% 

of the maximum annual volume of 

renewable fuels produced from a 

specific renewable fuel production 

facility on a calendar year basis. 

(i) For facilities that commenced 

construction prior to December 19, 2007 

the actual peak capacity is based on the 

last five calendar years prior to 2008, 

unless no such production exists, in 

which case actual peak capacity is 

determined pursuant to paragraph 

(a)(3)(ii) of this section. 

(ii) For facilities that commenced 

construction after December 19, 2007, 

and are fired with natural gas, biomass, 

or a combination thereof, the actual 

peak capacity is based on any calendar 

year after startup during the first three 

years of operation. 

(4) Commence construction, as 

applied to facilities that produce 

renewable fuel, means that: 

(i) The owner or operator has all 

necessary preconstruction approvals or 

permits (as defined at 40 CFR 

52.21(b)(10)), and has satisfied either of 

the following: 

(A) Begun, or caused to begin, a 

continuous program of actual 

construction on-site (as defined in 40 

CFR 52.21(b)(11)). 

(B) 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. 

(ii) 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. 

(b) The lifecycle greenhouse gas 

emissions from renewable fuels must be 

at least 20 percent less than baseline 

lifecycle greenhouse gas emissions, with 

the exception of the baseline volumes of 

renewable fuel produced from facilities 

described in paragraphs (c) and (d) of 

this section. 

(c) The baseline volume of renewable 

fuel that is produced from facilities and 

any expansions, all of which 

commenced construction on or before 

December 19, 2007, shall not be subject 

to the requirement that lifecycle 

greenhouse gas emissions be at least 20 

percent less than baseline lifecycle 

greenhouse gas emissions if the owner 

or operator: 

(1) Did not discontinue construction 

for a period of 18 months after 

commencement of construction; and 

(2) Completed construction within 36 

months of commencement of 

construction. 

(d) The baseline volume of ethanol 

that is produced from facilities and any 

expansions all of which commenced 

construction after December 19, 2007 

and on or before December 31, 2009, 

shall not be subject to the requirement 

that lifecycle greenhouse gas emissions 

be at least 20 percent less than baseline 

lifecycle greenhouse gas emissions if 

such facilities are fired with natural gas, 

biomass, or a combination thereof at all 

times the facility operated between 

December 19, 2007 and December 31, 

2009 and if: 

(1) The owner or operator did not 

discontinue construction for a period of 

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18 months after commencement of 

construction; 

(2) The owner or operator completed 

construction within 36 months of 

commencement of construction; and 

(3) The baseline volume continues to 

be produced through processes fired 

with natural gas, biomass, or any 

combination thereof. 

(e) The annual volume of renewable 

fuel during a calendar year from 

facilities described in paragraphs (c) and 

(d) of this section that exceeds the 

baseline volume shall be subject to the 

requirement that lifecycle greenhouse 

gas emissions be at least 20 percent less 

than baseline lifecycle greenhouse gas 

emissions. 

(f) 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 (to 

the extent it is less than or equal to 

baseline volume) will not be subject to 

the requirement that lifecycle 

greenhouse gas emissions be at least 20 

percent less than baseline lifecycle 

greenhouse gas emissions. Any party 

that changes the fuel mix must update 

their registration as specified in 

§ 80.1450(d). 

§ 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 0.004 percent. 

(2) The value of the biomass-based 

diesel standard for 2010 shall be 1.10 

percent. 

(3) The value of the advanced biofuel 

standard for 2010 shall be 0.61 percent. 

(4) The value of the renewable fuel 

standard for 2010 shall be 8.25 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 calculate the annual 

renewable fuel percentage standards 

using the following equations: 

Std

RFV

CB i

CB i

,

, = ∗ % ( ) − + − ( ) − +− ( ) + −

100

G RG GS RGS GE D RD DS R i i i i ii i i DS DE

G RG GS RGS GE

i i

ii i i

( ) −

= ∗ ×

( ) − + − ( ) − Std

RFV

BBD i

BBD i

,

, % . 100

1 5

ii i i i i

ii i

D RD DS RDS DE

G RG GS

+ − ( ) + − ( ) −

= ∗ ( ) − +

Std

RFV

AB i

AB i

,

, 100% ( ) − − +− ( ) + − ( ) −

= ∗

RGS GE D RD DS RDS DE

G

i ii i i i i

i

Std

RFV

RF i

RF i

,

, 100% ( ) − RG GS RGS GE D RD DS RDS DE i i i ii i i 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). 

(d) The 2010 price for cellulosic 

biofuel waiver credits is $1.56 per 

waiver credit. 

§ 80.1406 Who is an obligated party under 

the RFS program? 

(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 during a 

compliance period. A party that simply 

blends renewable fuel into gasoline or 

diesel fuel, as defined in § 80.1407(c) or 

(e), 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. 


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(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). 

(c) Aggregation of facilities. 

(1) Except as provided in paragraph 

(c)(2) of this section, 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. 

(2) An obligated party that carries a 

deficit into year i+1 must use the same 

approach to aggregation of facilities in 

year i+1 as it did in year i. 

(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 domestic 

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 produces or imports, 

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. 

§ 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 (f) 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 non-renewable diesel volume, 

determined in accordance with 

paragraphs (d), (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 (f) 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 non-renewable diesel volume, 

determined in accordance with 

paragraphs (d), (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 (f) 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 non-renewable diesel volume, 

determined in accordance with 

paragraphs (d), (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 (f) 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 non-renewable diesel volume, 

determined in accordance with 

paragraphs (d), (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, GVi, for an obligated party for 

a given year as specified in paragraph 

(a) of this section is calculated as 

follows: 

GV G RBG ix y

y

m

x

n

= −

= =

∑ ∑

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) Except as specified in paragraph (f) 

of this section, 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 (f) 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)) 


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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 

produced or imported to comply with a 

state or local fuels program. 

(d) The diesel non-renewable volume, 

DVi, for an obligated party for a given 

year as specified in paragraph (a) of this 

section is calculated as follows: 

DV D RBD ix y

y

m

x

n

= −

= =

∑ ∑

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 (e) 

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. 

(e) Except as specified in paragraph (f) 

of this section, 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. 

(f) The following products are not 

included in the volume of gasoline or 

diesel fuel produced or imported used 

to calculate a party’s Renewable Volume 

Obligations according to paragraph (a) 

of this section: 

(1) Any renewable fuel as defined in 

§ 80.1401. 

(2) Blendstock that has not been 

combined with other blendstock, 

finished gasoline, or diesel to produce 

gasoline or diesel. 

(3) Gasoline or diesel fuel 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 or diesel fuel produced 

by a small refinery that has an 

exemption under § 80.1441 or an 

approved small refiner that has an 

exemption under § 80.1442. 

(5) Gasoline or diesel fuel exported for 

use outside the 48 United States and 

Hawaii, and gasoline or diesel fuel 

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, finished diesel fuel, 

RBOB, or CBOB to which a blender adds 

blendstocks. 

(7) The gasoline or diesel fuel portion 

of transmix produced by a transmix 

processor, or the transmix blended into 

gasoline or diesel fuel by a transmix 

blender, under § 80.84. 

(8) Any gasoline or diesel fuel that is 

not transportation fuel. 

§§ 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) Equivalence values shall be 

assigned for certain renewable fuels as 

follows: 

(1) Ethanol which is denatured shall 

have an equivalence value of 1.0. 

(2) Biodiesel (mono-alkyl ester) shall 

have an equivalence value of 1.5. 

(3) Butanol shall have an equivalence 

value of 1.3. 

(4) Non-ester renewable diesel with a 

lower heating value of at least 123,500 

Btu/gal shall have an equivalence value 

of 1.7. 

(5) A gallon of renewable fuel 

represents 77,000 Btu (lower heating 

value) of biogas, and biogas shall have 

an equivalence value of 1.0. 

(6) A gallon of renewable fuel 

represents 22.6 kW-hr of electricity, and 

electricity shall have an equivalence 

value of 1.0. 

(7) For all other renewable fuels, a 

producer or importer shall submit an 

application to the Agency for an 

equivalence value following the 

provisions of paragraph (c) of this 

section. A producer or importer may 

also submit an application for an 

alternative equivalence value pursuant 

to paragraph (c) if the renewable fuel is 

listed in this paragraph (b), but the 

producer or importer has reason to 

believe that a different equivalence 

value than that listed in this paragraph 

(b) is warranted. 

(c) Calculation of new equivalence 

values. 

(1) The equivalence value for 

renewable fuels described in paragraph 

(b)(7) of this section shall be calculated 

using the following formula: 

EV = (R/0.972) * (EC/77,000) 

Where: 

EV = Equivalence Value for the renewable 

fuel, rounded to the nearest tenth. 

R = Renewable content of the renewable fuel. 

This is a measure of the portion of a 

renewable fuel that came from a 

renewable source, expressed as a 

percent, on an energy basis. 

EC = Energy content of the renewable fuel, 

in Btu per gallon (lower heating value). 

(2) The application for an equivalence 

value shall include a technical 

justification that includes a description 

of the renewable fuel, feedstock(s) used 

to make it, and the production process. 

(3) The Agency will review the 

technical justification and assign an 

appropriate equivalence value to the 

renewable fuel based on the procedure 

in this paragraph (c). 

(4) Applications for equivalence 

values must be sent to one of the 

following addresses: 

(i) For U.S. Mail: U.S. EPA, Attn: 

RFS2 Program Equivalence Value 

Application, 6406J, 1200 Pennsylvania 

Avenue, NW., Washington, DC 20460. 

(ii) For overnight or courier services: 

U.S. EPA, Attn: RFS2 Program 

Equivalence Value Application, 6406J, 

1310 L Street, NW., 6th floor, 

Washington, DC 20005. (202) 343–9038. 

(5) All applications required under 

this section shall be submitted on forms 

and following procedures prescribed by 

the Administrator. 

§ 80.1416 Petition process for evaluation 

of new renewable fuels pathways. 

(a)(1) A party may petition EPA to 

assign a D code for a new renewable fuel 

pathway that has not been evaluated by 

EPA to determine if it qualifies for a D 

code as defined in § 80.1426(f), pursuant 

to this section. A D code must be 

approved prior to the generation of RINs 

for the fuel in question. 

(2) For renewable fuel pathways that 

have been determined by EPA not to 

qualify for a D code as defined in 

§ 80.1426(f), parties who can document 

significant differences between the fuel 

production processes considered in this 

rule and their fuel pathway production 

processes may petition EPA to use a D 

code pursuant to this section. 

(3) Parties may petition EPA to qualify 

their renewable fuel pathway for a 

different D code than the D code 

assigned to the fuel pathway as defined 

in § 80.1426(f) if the parties can 

document significant differences 


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between the fuel production processes 

considered in this rule and their fuel 

pathway production processes, pursuant 

to this section. 

(b)(1) Any petition under paragraph 

(a) of this section shall include all the 

following: 

(i) The information specified under 

§ 80.76. 

(ii) A technical justification that 

includes a description of the renewable 

fuel, feedstock(s) used to make it, and 

the production process. The justification 

must include process modeling flow 

charts. 

(iii) A mass balance for the pathway, 

including feedstocks, fuels produced, 

co-products, and waste materials 

production. 

(iv) Information on co-products, 

including their expected use and market 

value. 

(v) An energy balance for the 

pathway, including a list of any energy 

and process heat inputs and outputs 

used in the pathway, including such 

sources produced off site or by another 

entity. 

(vi) Any other relevant information, 

including information pertaining to 

energy saving technologies or other 

process improvements. 

(vii) The Administrator may ask for 

additional information to complete the 

lifecycle greenhouse gas assessment of 

the new fuel or pathway. 

(2) For those companies who use a 

feedstock not previously evaluated by 

EPA under this subpart, the petition 

must include all the following in 

addition to the requirements in 

paragraph (b)(1) of this section: 

(i) Type of feedstock and description 

of how it meets the definition of 

renewable biomass. 

(ii) Market value of the feedstock. 

(iii) List of other uses for the 

feedstock. 

(iv) List of chemical inputs needed to 

produce the renewable biomass source 

of the feedstock and prepare the 

renewable biomass for processing into 

feedstock. 

(v) Identify energy needed to obtain 

the feedstock and deliver it to the 

facility. If applicable, identify energy 

needed to plant and harvest the 

renewable biomass source of the 

feedstock and modify the source to 

create the feedstock. 

(vi) Current and projected yields of 

the feedstock that will be used to 

produce the fuels. 

(vii) The Administrator may ask for 

additional information to complete the 

lifecycle Greenhouse Gas assessment of 

the new fuel or pathway. 

(c)(1) A company may only submit 

one petition per pathway. If EPA 

determines the petition to be 

incomplete, then the company may 

resubmit. 

(2) The petition must be signed and 

certified as meeting all the applicable 

requirements of this subpart by the 

responsible corporate officer of the 

applicant organization. 

(3) If EPA determines that the petition 

is incomplete then EPA will notify the 

applicant in writing that the petition is 

incomplete and will not be reviewed 

further. However, an amended petition 

that corrects the omission may be resubmitted for EPA review. 

(4) If the fuel or pathway described in 

the petition does not meet the 

definitions in § 80.1401 of renewable 

fuel, advanced biofuel, cellulosic 

biofuel, or biomass-based diesel, then 

EPA will notify the applicant in writing 

that the petition is denied and will not 

be reviewed further. 

(d) The petition 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: 

KYYYYCCCCFFFFFBBBBBRRD

SSSSSSSSEEEEEEEE 

(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 RIN was 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(f) and identifying 

the type of renewable fuel, as follows: 

(1) D has the value of 3 to denote fuel 

categorized as cellulosic biofuel. 

(2) D has the value of 4 to denote fuel 

categorized as biomass-based diesel. 

(3) D has the value of 5 to denote fuel 

categorized as advanced biofuel. 

(4) D has the value of 6 to denote fuel 

categorized as renewable fuel. 

(5) D has the value of 7 to denote fuel 

categorized as cellulosic diesel. 

(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) General requirements. 

(1) To the extent permitted under 

paragraphs (b) and (c) of this section, 

producers and importers of renewable 

fuel must generate RINs to represent 

that fuel if the fuel: 

(i) Qualifies for a D code pursuant to 

§ 80.1426(f), or EPA has approved a 

petition for use of a D code pursuant to 

§ 80.1416; and 

(ii) Is demonstrated to be produced 

from renewable biomass pursuant to the 

reporting requirements of § 80.1451 and 

the recordkeeping requirements of 

§ 80.1454. 

(A) Feedstocks meeting the 

requirements of renewable biomass 

through the aggregate compliance 

provision at § 80.1454(g) are deemed to 

be renewable biomass. 

(B) [Reserved] 

(2) To generate RINs for imported 

renewable fuel, including any 

renewable fuel contained in imported 

transportation fuel, importers must 

obtain information from a foreign 

producer that is registered pursuant to 

§ 80.1450 sufficient to make the 

appropriate determination regarding the 

applicable D code and compliance with 

the renewable biomass definition for 

each imported batch for which RINs are 

generated. 

(3) 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 paragraph (f) of this 

section. 

(b) Regional applicability. 

(1) Except as provided in paragraph 

(c) of this section, a RIN must be 

generated by a renewable fuel producer 

or importer for a batch of renewable fuel 

that satisfies the requirements of 

paragraph (a)(1) of this section if it is 

produced or imported for use as 

transportation fuel, heating oil, or jet 

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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 (b)(1) of this section shall also 

apply to renewable fuel produced or 

imported for use as transportation fuel, 

heating oil, or jet fuel in that state or 

territory beginning in the next calendar 

year. 

(c) Cases in which RINs are not 

generated. 

(1) Fuel producers and importers may 

not generate RINs for fuel that is not 

designated or intended for use as 

transportation fuel, heating oil, or jet 

fuel. 

(2) Small producer/importer 

threshold. Pursuant to § 80.1455(a) and 

(b), renewable fuel producers that 

produce less than 10,000 gallons a year 

of renewable fuel, and importers that 

import less than 10,000 gallons a year of 

renewable fuel, are not required to 

generate and assign RINs to batches of 

renewable fuel that that satisfy the 

requirements of paragraph (a)(1) of this 

section that they produce or import. 

(3) Temporary new producer 

threshold. Pursuant to § 80.1455(c) and 

(d), renewable fuel producers that 

produce less than 125,000 gallons a year 

of renewable fuel are not required to 

generate and assign RINs to batches of 

renewable fuel that satisfy the 

requirements of paragraph (a)(1) of this 

section and that are produced from a 

new facility, for a maximum of three 

years beginning with the calendar year 

in which the production facility 

produces its first gallon of renewable 

fuel. 

(4) Importers shall not 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 registered foreign 

producer. 

(6) A party is prohibited from 

generating RINs for a volume of fuel that 

it produces if: 

(i) The fuel does not meet the 

requirements of paragraph (a)(1) of this 

section; or 

(ii) The fuel has been produced from 

a chemical conversion process that uses 

another renewable fuel as a feedstock, 

the renewable fuel used as a feedstock 

was produced by another party, and 

RINs with a K code of 1 were received 

with the renewable fuel. 

(A) Parties who produce renewable 

fuel made from a feedstock which itself 

was a renewable fuel received with 

RINs, shall assign the original RINs to 

the new renewable fuel. 

(B) [Reserved] 

(d)(1) 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 identifier within a calendar 

year by the producer or importer of the 

renewable fuel in accordance with the 

provisions of this section and § 80.1425. 

(i) The number of gallon-RINs 

generated for a batch of renewable fuel 

may not exceed 99,999,999. 

(ii) A batch of renewable fuel cannot 

represent renewable fuel produced or 

imported in excess of one calendar 

month. 

(2) 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 (f) of this section. 

(iii) Under § 80.1452, RIN volumes 

will be managed by EMTS. RIN codes 

SSSSSSSS and EEEEEEEE do not have 

a role in EMTS. 

(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. 

(f) Generation of RINs. 

(1) 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, or as approved 

by the Administrator. In choosing an 

appropriate D code, producers and 

importers may disregard any incidental, 

de minimis feedstock contaminants that 

are impractical to remove and are 

related to customary feedstock 

production and transport. 

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 ............................. Corn starch .............................................................. All of the following: ..................................................

Drymill process, using natural gas, biomass, or 

biogas for process energy and at least two advanced technologies from Table 2 to this section.

6 

Ethanol ............................. Corn starch .............................................................. All of the following: ..................................................

Dry mill process, using natural gas, biomass, or 

biogas for process energy and at least one of 

the advanced technologies from Table 2 to this 

section plus drying no more than 65% of the 

distillers grains with solubles it markets annually.

6 

Ethanol ............................. Corn starch .............................................................. All of the following: ..................................................

Dry mill process, using natural gas, biomass, or 

biogas for process energy and drying no more 

than 50% of the distillers grains with solubles it 

markets annually.

6 

Ethanol ............................. Corn starch .............................................................. Wet mill process using biomass or biogas for 

process energy.

6 

Ethanol ............................. Starches from agricultural residues and annual 

covercrops.

Fermentation using natural gas, biomass, or 

biogas for process energy.

6 

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TABLE 1 TO § 80.1426 APPLICABLE D CODES FOR EACH FUEL PATHWAY FOR USE IN GENERATING RINS—Continued 

Fuel type Feedstock Production process 

requirements D-Code 

Biodiesel, and renewable 

diesel.

Soy bean oil; 

Oil from annual covercrops; 

Algal oil; 

Biogenic waste oils/fats/greases; 

Non-food grade corn oil. 

One of the following: 

Trans-Esterification 

Hydrotreating 

Excluding processes that co-process renewable 

biomass and petroleum. 

4 

Biodiesel, and renewable 

diesel.

Soy bean oil; 

Oil from annual covercrops; 

Algal oil; 

Biogenic waste oils/fats/greases; 

Non-food grade corn oil. 

One of the following: 

Trans-Esterification 

Hydrotreating 

Includes only processes that co-process renewable biomass and petroleum. 

5 

Ethanol ............................. Sugarcane ............................................................... Fermentation ........................................................... 5 

Ethanol ............................. Cellulosic Biomass from agricultural residues, 

slash, forest thinnings and forest product residues, annual covercrops; switchgrass, and 

miscanthus; cellulosic components of separated 

yard wastes; cellulosic components of separated 

food wastes; and cellulosic components of separated MSW.

Any .......................................................................... 3 

Cellulosic Diesel, Jet Fuel 

and Heating Oil.

Cellulosic Biomass from agricultural residues, 

slash, forest thinnings and forest product residues, annual covercrops, switchgrass, and 

miscanthus; cellulosic components of separated 

yard wastes; cellulosic components of separated 

food wastes; and cellulosic components of separated MSW.

Any .......................................................................... 7 

Butanol ............................. Corn starch .............................................................. Fermentation; dry mill using natural gas, biomass, 

or biogas for process energy.

6 

Cellulosic Naphtha ........... Cellulosic Biomass from agricultural residues, 

slash, forest thinnings and forest product residues, annual covercrops, switchgrass, and 

miscanthus; cellulosic components of separated 

yard wastes; cellulosic components of separated 

food wastes; and cellulosic components of separated MSW.

Fischer-Tropsch process ......................................... 3 

Ethanol, renewable diesel, 

jet fuel, heating oil, and 

naphtha.

The non-cellulosic portions of separated food 

wastes.

Any .......................................................................... 5 

Biogas .............................. Landfills, sewage and waste treatment plants, manure digesters.Any .......................................................................... 5 

TABLE 2 TO § 80.1426—ADVANCED

TECHNOLOGIES

Corn oil fractionation. 

Corn oil extraction. 

Membrane separation. 

Raw starch hydrolysis. 

Combined heat and power. 

(2) Renewable fuel that can be 

described by a single pathway. 

(i) The number of gallon-RINs that 

shall be generated for a batch of 

renewable fuel by a producer or 

importer for renewable fuel that can be 

described by a single pathway 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 the batch. 

EV = Equivalence value for the batch of 

renewable fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(f)(8) 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, or 

a D code as approved by the 

Administrator, which corresponds to 

the pathway that describes the 

producer’s operations. 

(3) Renewable fuel that can be 

described by two or more pathways. 

(i) The D codes that shall be used in 

the RINs generated by a producer or 

importer whose renewable fuel can be 

described by two or more pathways 

shall be the D codes specified in Table 

1 to this section, or D codes as approved 

by the Administrator, which correspond 

to the pathways that describe the 

renewable fuel throughout that calendar 

year. 

(ii) If all the pathways describing the 

producer’s operations have the same D 

code and each batch is of a single fuel 

type, then that D code shall be used in 

all the RINs generated and the number 

of gallon-RINs that shall be generated 

for a 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 for the batch. 

EV = Equivalence value for the batch of 

renewable fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(f)(8) of this section. 

(iii) If all the pathways describing the 

producer’s operations have the same D 

code but individual batches are 

comprised of a mixture of fuel types 

with different equivalence values, then 

that D code shall be used in all the RINs 

generated and the number of gallonRINs that shall be generated for a batch 

of renewable fuel shall be equal to a 

volume calculated according to the 

following formula: 

VRIN = S(EVi * Vs,i) 

Where: 

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VRIN = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated for the batch. 

EVi = Equivalence value for fuel type i in the 

batch of renewable fuel per § 80.1415. 

Vs,i = Standardized volume of fuel type i 

in the batch of renewable fuel at 60 °F, in 

gallons, calculated in accordance with 

paragraph (f)(8) of this section. 

(iv) 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, and each batch is 

of a single fuel type, then the applicable 

D code and batch identifier used in 

generating RINs must change on the 

date that the change in pathway occurs 

and the number of gallon-RINs that shall 

be generated for a 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 for a batch with 

a single applicable D code. 

EV = Equivalence value for the batch of 

renewable fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(f)(8) of this section. 

(v) If a producer produces batches that 

are comprised of a mixture of fuel types 

with different equivalence values and 

different applicable D codes, then 

separate values for VRIN shall be 

calculated for each category of 

renewable fuel according to formulas in 

Table 3 to this section. All batch-RINs 

thus generated shall be assigned to 

unique batch identifiers for each portion 

of the batch with a different D code. 

TABLE 3 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 

gallon-RINs 

D = 3 ......................... VRIN, CB = EVCB * 

Vs,CB

D = 4 ......................... VRIN, BBD = EVBBD * 

Vs,BBD

D = 5 ......................... VRIN, AB = EVAB * 

Vs,AB

D = 6 ......................... VRIN, RF = EVRF * 

Vs,RF

D = 7 ......................... VRIN, CD = EVCD * 

Vs,CD

Where: 

VRIN,CB = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated for the cellulosic 

biofuel portion of the batch with a D 

code of 3. 

VRIN,BBD = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated for the biomassbased diesel portion of the batch with a 

D code of 4. 

VRIN,AB = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated for the advanced 

biofuel potion of the batch with a D code 

of 5. 

VRIN,RF = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated for the renewable 

fuel potion of the batch with a D code 

of 6. 

VRIN,CD = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated for the cellulosic 

diesel portion of the batch with a D code 

of 7. 

EVCB = Equivalence value for the cellulosic 

biofuel portion of the batch per 

§ 80.1415. 

EVBBD = Equivalence value for the biomassbased diesel portion of the batch per 

§ 80.1415. 

EVAB = Equivalence value for the advanced 

biofuel portion of the batch per 

§ 80.1415. 

EVRF = Equivalence value for the renewable 

fuel portion of the batch per § 80.1415. 

EVCD = Equivalence value for the cellulosic 

diesel portion of the batch per § 80.1415. 

Vs,CB = Standardized volume at 60 °F of the 

portion of the batch that must be 

assigned a D code of 3, in gallons, 

calculated in accordance with paragraph 

(f)(8) of this section. 

Vs,BBD = Standardized volume at 60 °F of the 

portion of the batch that must be 

assigned a D code of 4, in gallons, 

calculated in accordance with paragraph 

(f)(8) of this section. 

Vs,AB = Standardized volume at 60 °F of the 

portion of the batch that must be 

assigned a D code of 5, in gallons, 

calculated in accordance with paragraph 

(f)(8) of this section. 

Vs,RF = Standardized volume at 60 °F of the 

portion of the batch that must be 

assigned a D code of 6, in gallons, 

calculated in accordance with paragraph 

(f)(8) of this section. 

Vs,CD = Standardized volume at 60 °F of the 

portion of the batch that must be 

assigned a D code of 7, in gallons, 

calculated in accordance with paragraph 

(f)(8) of this section. 

(vi) If a producer produces a single 

type of renewable fuel using two or 

more different feedstocks which are 

processed simultaneously, and each 

batch is comprised of a single type of 

fuel, then the number of gallon-RINs 

that shall be generated for a batch of 

renewable fuel and assigned a particular 

D code shall be determined according to 

the formulas in Table 4 to this section. 


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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 3. 

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 4. 

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 5. 

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 6. 

VRIN,CD = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated for a batch of 

cellulosic diesel with a D code of 7. 

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 

(f)(8) of this section. 

FE3 = Feedstock energy from all feedstocks 

whose pathways have been assigned a D 

code of 3 under Table 1 to this section, 

or a D code of 3 as approved by the 

Administrator, in Btu. 

FE4 = Feedstock energy from all feedstocks 

whose pathways have been assigned a D 

code of 4 under Table 1 to this section, 

or a D code of 4 as approved by the 

Administrator, in Btu. 

FE5 = Feedstock energy from all feedstocks 

whose pathways have been assigned a D 

code of 5 under Table 1 to this section, 

or a D code of 5 as approved by the 

Administrator, in Btu. 

FE6 = Feedstock energy from all feedstocks 

whose pathways have been assigned a D 

code of 6 under Table 1 to this section, 

or a D code of 6 as approved by the 

Administrator, in Btu. 

FE7 = Feedstock energy from all feedstocks 

whose pathways have been assigned a D 

code of 7 under Table 1 to this section, 

or a D code of 7 as approved by the 

Administrator, in Btu. 

Feedstock energy values, FE, shall be 

calculated according to the following 

formula: 

FE = M * (1 ¥ m) * CF * E 

Where: 

FE = Feedstock energy, in Btu. 

M = Mass of feedstock, in pounds, measured 

on a daily or per-batch basis. 

m = Average moisture content of the 

feedstock, in mass percent. 

CF = Converted Fraction in annual average 

mass percent, representing that portion 

of the feedstock that is converted into 

renewable fuel by the producer. 

E = Energy content of the components of the 

feedstock that are converted to 

renewable fuel, in annual average Btu/lb, 

determined according to paragraph (f)(7) 

of this section. 

(4) Renewable fuel that is produced by 

co-processing renewable biomass and 

non-renewable feedstocks 

simultaneously to produce a 

transportation fuel that is partially 

renewable. 

(i) The number of gallon-RINs that 

shall be generated for a batch of 

partially renewable transportation fuel 

shall be equal to a volume VRIN

calculated according to Method A or 

Method B. 

(A) Method A. 

(1) VRIN shall be calculated according 

to the following formula: 

VRIN = EV * Vs * FER/(FER + FENR) 

Where: 

VRIN = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated for the batch. 

EV = Equivalence value for the batch of 

renewable fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(f)(8) of this section. 

FER = Feedstock energy from renewable 

biomass used to make the transportation 

fuel, in Btu. 

FENR = Feedstock energy from non-renewable 

feedstocks used to make the 

transportation fuel, in Btu. 

(2) The value of FE for use in 

paragraph (f)(4)(i)(A)(1) of this section 

shall be calculated from the following 

formula: 

FE = M * (1 ¥ m) * CF * E 

FE = Feedstock energy, in Btu. 

M = Mass of feedstock, in pounds, measured 

on a daily or per-batch basis. 

m = Average moisture content of the 

feedstock, in mass percent. 

CF = Converted fraction in annual average 

mass percent, representing that portion 

of the feedstock that is converted into 

transportation fuel by the producer. 

E = Energy content of the components of the 

feedstock that are converted to fuel, in 

annual average Btu/lb, determined 

according to paragraph (f)(7) of this 

section. 

(B) Method B. VRIN shall be calculated 

according to the following formula: 

VRIN = EV * Vs * R 

Where: 

VRIN = RIN volume, in gallons, for use in 

determining the number of gallon-RINs 

that shall be generated for the batch. 

EV = Equivalence value for the batch of 

renewable fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(f)(8) of this section. 

R = The renewable fraction of the fuel as 

measured by a carbon-14 dating test 

method as provided in paragraph (f)(9) of 

this section. 

(ii) 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, or a D code as approved by the 

Administrator, 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. 

(5) Renewable fuel produced from 

separated yard and food waste. 

(i) Separated yard waste and food 

waste means, for the purposes of this 

section, waste that is one of the 

following: 

(A) Separated yard wastes, which are 

feedstock streams consisting of yard 

waste kept separate since generation 

from other waste materials. Separated 

yard wastes are deemed to be composed 

entirely of cellulosic materials. 

(B) Separated food wastes, which are 

feedstock streams consisting of food 

wastes kept separate since generation 

from other waste materials, and which 

include food and beverage production 

wastes and post-consumer food and 

beverage wastes. Separated food wastes 

are deemed to be composed entirely of 

non-cellulosic materials, unless a party 

demonstrates that a portion of the 

feedstock is cellulosic through approval 

of their facility registration. 

(C) Separated municipal solid waste 

(MSW), which is material remaining 

after separation actions have been taken 

to remove recyclable paper, cardboard, 

plastics, rubber, textiles, metals, and 

glass from municipal solid waste, and 

which is composed of both cellulosic 

and non-cellulosic materials. 

(ii)(A) A feedstock qualifies under 

paragraph (f)(5)(i)(A) or (f)(5)(i)(B) of 

this section only if it is collected 

according to a plan submitted to and 

approved by U.S. EPA under the 

registration procedures specified in 

§ 80.1450(b)(1)(vii). 

(B) A feedstock qualifies under 

paragraph (f)(5)(i)(C) of this section only 

if it is collected according to a plan 

submitted to and approved by U.S. EPA 

under the registration procedures 

specified in § 80.1450(b)(1)(viii). 

(iii) Separation and recycling actions 

specified in paragraph (f)(5)(i)(C) of this 

section are considered to occur if: 

(A) Recyclable paper, cardboard, 

plastics, rubber, textiles, metals, and 

glass that can be recycled are separated 

and removed from the municipal solid 

waste stream to the extent reasonably 

practicable according to a plan 

submitted to and approved by U.S. EPA 

under the registration procedures 

specified in § 80.1450(b)(1)(viii); and 

(B) The fuel producer has evidence of 

all contractual arrangements for paper, 

cardboard, plastics, rubber, textiles, 

metals, and glass that are recycled. 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14875 

(iv)(A) The number of gallon-RINs 

that shall be generated for a batch of 

renewable fuel derived from separated 

yard waste as defined in paragraph 

(f)(5)(i)(A) of this section shall be equal 

to a volume VRIN and is calculated 

according to the following formula: 

VRIN = EV * Vs

Where: 

VRIN = RIN volume, in gallons, for use in 

determining the number of cellulosic 

biofuel gallon-RINs that shall be 

generated for the batch. 

EV = Equivalence value for the batch of 

renewable fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(f)(8) of this section. 

(B) The number of gallon-RINs that 

shall be generated for a batch of 

renewable fuel derived from separated 

food waste as defined in paragraph 

(f)(5)(i)(B) of this section shall be equal 

to a volume VRIN and is calculated 

according to the following formula: 

VRIN = EV * Vs

Where: 

VRIN = RIN volume, in gallons, for use in 

determining the number of cellulosic or 

advanced biofuel gallon-RINs that shall 

be generated for the batch. 

EV = Equivalence value for the batch of 

renewable fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(f)(8) of this section. 

(v) The number of cellulosic biofuel 

gallon-RINs that shall be generated for 

the cellulosic portion of a batch of 

renewable fuel derived from separated 

MSW as defined in paragraph (f)(5)(i)(C) 

of this section shall be determined 

according to the following formula: 

VRIN = EV * Vs * R 

Where: 

VRIN = RIN volume, in gallons, for use in 

determining the number of cellulosic 

biofuel gallon-RINs that shall be 

generated for the batch. 

EV = Equivalence value for the batch of 

renewable fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(f)(8) of this section. 

R = The calculated non-fossil fraction of the 

fuel as measured by a carbon-14 dating 

test method as provided in paragraph 

(f)(9) of this section. 

(vi) The D code that shall be used in 

the RINs generated to represent 

separated yard waste, food waste, and 

MSW shall be the D code specified in 

Table 1 to this section, or a D code as 

approved by the Administrator, which 

corresponds to the pathway that 

describes the producer’s operations and 

feedstocks. 

(6) Renewable fuel neither covered by 

the pathways in Table 1 to this section, 

nor given an approval by the 

Administrator for use of a specific D 

code. 

If none of the pathways described in 

Table 1 to this section apply to a 

producer’s operations, and the producer 

has not received approval for the use of 

a specific D code by the Administrator, 

the party may generate RINs if the fuel 

from its facility is made from renewable 

biomass and qualifies for an exemption 

under § 80.1403 from the requirement 

that renewable fuel achieve at least a 20 

percent reduction in lifecycle 

greenhouse gas emissions compared to 

baseline lifecycle greenhouse gas 

emissions. 

(i) The number of gallon-RINs that 

shall be generated for a batch of 

renewable fuel that qualifies for an 

exemption from the 20 percent GHG 

reduction requirements under § 80.1403 

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 the batch. 

EV = Equivalence value for the batch of 

renewable fuel per § 80.1415. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons, 

calculated in accordance with paragraph 

(f)(8) of this section. 

(ii) A D code of 6 shall be used in the 

RINs generated under this paragraph 

(f)(6). 

(7) Determination of feedstock energy 

content factors. 

(i) For purposes of paragraphs 

(f)(3)(vi) and (f)(4)(i)(A)(2) of this 

section, producers must specify the 

value for E, the energy content of the 

components of the feedstock that are 

converted to renewable fuel, used in the 

calculation of the feedstock energy 

value FE. 

(ii) The value for E shall represent the 

higher or gross calorific heating value 

for a feedstock on a zero moisture basis. 

(iii) Producers must specify the value 

for E for each type of feedstock at least 

once per calendar year. 

(iv) A producer must use default 

values for E as provided in paragraph 

(f)(7)(vi) of this section, or must 

determine alternative values for its own 

feedstocks according to paragraph 

(f)(7)(v) of this section. 

(v) Producers that do not use a default 

value for E must use the following test 

methods, or alternative test methods as 

approved by EPA, to determine the 

value of E. The value of E shall be based 

upon the test results of a sample of 

feedstock that, based upon good 

engineering judgment, is representative 

of the feedstocks used to produce 

renewable fuel: 

(A) ASTM E 870 or ASTM E 711 for 

gross calorific value (both incorporated 

by reference, see § 80.1468). 

(B) ASTM D 4442 or ASTM D 4444 for 

moisture content (both incorporated by 

reference, see § 80.1468). 

(vi) Default values for E. 

(A) Starch: 7,600 Btu/lb. 

(B) Sugar: 7,300 Btu/lb. 

(C) Vegetable oil: 17,000 Btu/lb. 

(D) Waste cooking oil or trap grease: 

16,600 Btu/lb. 

(E) Tallow or fat: 16,200 Btu/lb. 

(F) Manure: 6,900 Btu/lb. 

(G) Woody biomass: 8,400 Btu/lb. 

(H) Herbaceous biomass: 7,300 Btu/lb. 

(I) Yard wastes: 2,900 Btu/lb. 

(J) Biogas: 11,000 Btu/lb. 

(K) Food waste: 2,000 Btu/lb. 

(L) Paper: 7,200 Btu/lb. 

(M) Crude oil: 19,100 Btu/lb. 

(N) Coal—bituminous: 12,200 Btu/lb. 

(O) Coal—anthracite: 13,300 Btu/lb. 

(P) Coal—lignite or sub-bituminous: 

7,900 Btu/lb. 

(Q) Natural gas: 19,700 Btu/lb. 

(R) Tires or rubber: 16,000 Btu/lb. 

(S) Plastic: 19,000 Btu/lb. 

(8) Standardization of volumes. In 

determining the standardized volume of 

a batch of renewable fuel for purposes 

of generating RINs under this paragraph 

(f), 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), 

one of the following two methods for 

biodiesel temperature standardization to 

60 °Fahrenheit (°F ) shall be used: 

(A) Vs,b = Va.b * (-0.00045767 * T + 

1.02746025) 

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. 

(B) The standardized volume of 

biodiesel at 60 °F, in gallons, as 

calculated from the use of the American 

Petroleum Institute Refined Products 

Table 6B, as referenced in ASTM D 1250 

(incorporated by reference, see 

§ 80.1468). 

(iii) For other renewable fuels, an 

appropriate formula commonly 

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14876 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

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 determined to be 

inappropriate. 

(9) Use of radiocarbon dating test 

methods. 

(i) Parties may use a radiocarbon 

dating test method for determination of 

the renewable fraction of a fuel R used 

to determine VRIN as provided in 

paragraphs (f)(4) and (f)(5) of this 

section. 

(ii) Parties must use Method B or 

Method C of ASTM D 6866 

(incorporated by reference, see 

§ 80.1468), or an alternative test method 

as approved by EPA. 

(iii) For each batch of fuel, the value 

of R must be based on: 

(A) A radiocarbon dating test of the 

batch of fuel produced; or 

(B) A radiocarbon dating test of a 

composite sample of previously 

produced fuel, if all of the following 

conditions are met: 

(1) Based upon good engineering 

judgment, the renewable fraction of the 

composite sample must be 

representative of the batch of fuel 

produced. 

(2) The composite sample is 

comprised of a volume weighted 

combination of samples from every 

batch of partially renewable 

transportation fuel produced by the 

party over a period not to exceed one 

calendar month, or more frequently if 

necessary to ensure that the test results 

are representative of the renewable 

fraction of the partially renewable fuel. 

(3) The composite sample must be 

well mixed prior to testing. 

(4) A volume of each composite 

sample must be retained for a minimum 

of two years, and be of sufficient volume 

to permit two additional tests to be 

conducted. 

(iv) If the party is using the composite 

sampling approach according to 

paragraph (f)(9)(iii)(B) of this section, 

the party may estimate the value of R for 

use in generating RINs in the first month 

if all of the following conditions are 

met: 

(A) The estimate of R for the first 

month is based on information on the 

composition of the feedstock; 

(B) The party calculates R in the 

second month based on the application 

of a radiocarbon dating test on a 

composite sample pursuant to 

(f)(9)(iii)(B) of this section; and 

(C) The party adjusts the value of R 

used to generate RINs in the second 

month using the following formula: 

Ri∂1,adj = 2 × Ri∂1,calc¥Ri,est

Where: 

Ri∂1,adj = Adjusted value of R for use in 

generating RINs in month the second 

month i+1. 

Ri∂1,calc = Calculated value of R in second 

month i+1 by applying a radiocarbon 

dating test method to a composite 

sample of fuel. 

Ri,est = Estimate of R for the first month i. 

(10)(i) For purposes of this section, 

electricity and biogas used as 

transportation fuel is considered 

renewable fuel and the producer may 

generate RINs if all of the following 

apply: 

(A) The fuel is produced from 

renewable biomass and qualifies for a D 

code in Table 1 to this section or has 

received approval for use of a D code by 

the Administrator; 

(B) The renewable electricity, or 

biogas, is not placed in a commercial 

distribution system along with fuels 

derived from nonrenewable feedstocks; 

and 

(C) The fuel producer has entered into 

a written contract for the sale and use 

as transportation fuel of a specific 

quantity of electricity or biogas. 

(ii) Electricity that is generated by cofiring a combination of renewable 

biomass and fossil fuel may generate 

RINs only for the portion attributable to 

the renewable biomass portion, using 

the procedure described in paragraph 

(f)(4) of this section. 

(11)(i) For purposes of this section, 

electricity and biogas that is introduced 

into a commercial distribution system 

may be considered renewable fuel and 

may qualify for RINs if: 

(A) The fuel is produced from 

renewable biomass and qualifies for a D 

code in Table 1 of this section or has 

received approval for use of a D code by 

the Administrator; 

(B) The fuel producer has entered into 

a written contract for the sale of a 

specific quantity of fuel derived from 

renewable biomass sources with a party 

that uses fuel taken from a commercial 

distribution system for transportation 

purposes, and such fuel has been 

introduced into that commercial 

distribution system (e.g., pipeline, 

transmission line); and 

(C) The quantity of biogas or 

electricity for which RINs were 

generated was sold to the transportation 

fueling facility and to no other facility. 

(ii) Biogas that is introduced into a 

commercial distribution system may 

qualify for RINs only for the volume of 

biogas that has been gathered, 

processed, and injected into a common 

carrier pipeline: 

(A) The gas that is ultimately 

withdrawn from that pipeline for 

transportation purposes is withdrawn in 

a manner and at a time consistent with 

the transport of fuel between the 

injection and withdrawal points; and 

(B) The volume and heat content of 

biogas injected into the pipeline and the 

volume of gas used as transportation 

fuel are measured by continuous 

metering. 

(iii) The fuel used for transportation 

purposes is considered produced from 

renewable biomass only to the extent 

that: 

(A) The amount of fuel used at the 

transportation fueling facility matches 

the amount of fuel derived from 

renewable biomass that the producer 

contracted to have placed into the 

commercial distribution system; and 

(B) No other party relied upon the 

contracted volume of biogas for the 

creation of RINs. 

(iv) Electricity that is generated by cofiring a combination of renewable 

biomass and fossil fuel may qualify for 

RINs only for the portion attributable to 

the renewable biomass, using the 

procedure described in paragraph (f)(4) 

of this section. 

(12)(i) For purposes of Table 1 to this 

section, process heat produced from 

combustion of gas at a renewable fuel 

facility is considered derived from 

biomass if the gas used for process heat 

is biogas, and is generated at the facility 

or directly transported to the facility 

and meets all of the following 

conditions: 

(A) The producer has entered into a 

written contract for the procurement of 

a specific volume of biogas with a 

specific heat content. 

(B) The volume of biogas was sold to 

the renewable fuel production facility, 

and to no other facility. 

(C) The volume of biogas has been 

gathered, processed and injected into a 

common carrier pipeline and the gas 

that is ultimately withdrawn from that 

pipeline is withdrawn in a manner and 

at a time consistent with the transport 

of fuel between the injection and 

withdrawal points. 

(D) The volume and heat content of 

biogas injected into the pipeline and the 

volume of gas used as process heat are 

measured by continuous metering. 

(E) The common carrier pipeline into 

which the biogas is placed ultimately 

serves the producer’s renewable fuel 

facility. 

(ii) The process heat produced from 

combustion of gas at a renewable fuel 

facility described in (f)(12)(i) of this 

section shall not be considered derived 

from biomass if any other party relied 

upon the contracted volume of biogas 

for the creation of RINs. 

§ 80.1427 How are RINs used to 

demonstrate compliance? 

(a) Renewable Volume Obligations. 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14877 

(1) Except as specified in paragraph 

(b) of this section or § 80.1456, each 

party that is an obligated party under 

§ 80.1406 and is obligated to meet the 

Renewable Volume Obligations under 

§ 80.1407, or is an exporter of renewable 

fuels that is obligated to meet 

Renewable Volume Obligations under 

§ 80.1430, must demonstrate pursuant to 

§ 80.1451(a)(1) that it is retiring for 

compliance purposes a sufficient 

number of 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. Use the 

equation in this paragraph, except as 

provided in paragraph (a)(7) of this 

section. 

(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 gallonRINs 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)(4) 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 3 or 7 are 

valid for compliance with the cellulosic 

biofuel RVO. 

(ii) RINs with a D code of 4 or 7 are 

valid for compliance with the biomassbased diesel RVO. 

(iii) RINs with a D code of 3, 4, 5, or 

7 are valid for compliance with the 

advanced biofuel RVO. 

(iv) RINs with a D code of 3, 4, 5, 6, 

or 7 are valid for compliance with the 

renewable fuel RVO. 

(3)(i) Except as provided in paragraph 

(a)(3)(ii) of this section, 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. 

(ii) A cellulosic diesel RIN with a D 

code of 7 cannot be used to demonstrate 

compliance with both a cellulosic 

biofuel RVO and a biomass-based diesel 

RVO. 

(4) Notwithstanding the requirements 

of § 80.1428(c) or paragraph (a)(6)(i) of 

this section, for purposes of 

demonstrating compliance for calendar 

years 2010 or 2011, RINs generated 

pursuant to § 80.1126 that have not been 

used for compliance purposes may be 

used for compliance in 2010 or 2011, as 

follows, insofar as permissible pursuant 

to paragraphs (a)(5) and (a)(7)(iii) of this 

section: 

(i) A RIN generated pursuant to 

§ 80.1126 with a D code of 2 and an RR 

code of 15 or 17 is deemed equivalent 

to a RIN generated pursuant to § 80.1426 

having a D code of 4. 

(ii) A RIN generated pursuant to 

§ 80.1126 with a D code of 1 is deemed 

equivalent to a RIN generated pursuant 

to § 80.1426 having a D code of 3. 

(iii) All other RINs generated pursuant 

to § 80.1126 are deemed equivalent to 

RINs generated pursuant to § 80.1426 

having D codes of 6. 

(iv) A RIN generated pursuant to 

§ 80.1126 that was retired pursuant to 

§ 80.1129(e) because the associated 

volume of fuel was not used as motor 

vehicle fuel may be reinstated for use in 

complying with a 2010 RVO pursuant to 

§ 80.1429(g). 

(5) The value of (SRINNUM)i-1 may 

not exceed values determined by the 

following inequalities except as 

provided in paragraph (a)(7)(iii) of this 

section and § 80.1442(d): 

(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 paragraph 

(a)(7) of this section: 

(i) 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. 

(ii) 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 that they used for compliance 

purposes for calendar year 2009 which 

have a D code of 2 and 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 

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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 for calendar year 

2010, in gallons, pursuant to § 80.1407 or 

§ 80.1430, as adjusted by paragraph 

(a)(7)(i) of this section. 

(iii) 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) or (a)(7) 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)(7) 

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. 

(iv) The party uses the same 

compliance approach in year i+1 as it 

did in year i, as provided in 

§ 80.1406(c)(2). 

(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 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. 

(SRINNUM)i = Sum of all acquired gallonRINs that were generated in year i and 

are being applied towards the RVOi, in 

gallons. 

(SRINNUM)i-1 = Sum of all acquired gallonRINs 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. 

(1) 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. 

(2) Except as provided in § 80.1429, 

no person 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 person without 

simultaneously transferring a volume of 

renewable fuel to that same person. 

(4) No more than 2.5 assigned gallonRINs with a K code of 1 can be 

transferred to another person with every 

gallon of renewable fuel transferred to 

that same person. 

(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 

person: 

S(RIN)D ≤ S(Vsi * 2.5)D

Where: 

D = Applicable date. 

S(RIN)D = Sum of all assigned gallon-RINs 

with a K code of 1 that are owned on 

date D. 

(Vsi)D = Volume i of renewable fuel owned on 

date D, standardized to 60 °F, in gallons. 

(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 person; or 

(ii) The RIN must be recorded on a 

separate product transfer document 

transferred to the same person 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 person that has registered 

pursuant to § 80.1450 can own a 

separated RIN. 

(3) Separated RINs can be transferred 

any number of times. 

(c) RIN expiration. Except as provided 

in § 80.1427(a)(7), a RIN is valid for 

compliance during the calendar year in 

which it was generated, or the following 

calendar year. Any RIN that is not used 

for compliance purposes for the 

calendar year in which it was generated, 

or for the following calendar year, will 

be considered an expired RIN. Pursuant 

to § 80.1431(a), an expired RIN that is 

used for compliance will be considered 

an invalid RIN. 

(d) Any batch-RIN can be divided into 

multiple batch-RINs, each representing 

a smaller number of gallon-RINs, if all 

of the following conditions are met: 

(1) All RIN components other than 

SSSSSSSS and EEEEEEEE are identical 

for the original parent and newly 

formed daughter RINs. 

(2) The sum of the gallon-RINs 

associated with the multiple daughter 

batch-RINs is equal to the gallon-RINs 

associated with the parent batch-RIN. 

§ 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 can be separated from 

that volume only under one of the 

following conditions: 

(1) Except as provided in paragraphs 

(b)(7) and (b)(9) 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 that party owns that 

volume. 

(2) Except as provided in paragraph 

(b)(6) 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, 

heating oil, or jet fuel. A party may 

separate up to 2.5 RINs per gallon of 

blended renewable fuel. 

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(3) Any party that exports a volume of 

renewable fuel must separate any RINs 

that have been assigned to the exported 

volume. A party may separate up to 2.5 

RINs per gallon of exported renewable 

fuel. 

(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, 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, 

heating oil, or jet fuel. 

(5) Any party that produces, imports, 

owns, sells, or uses a volume of 

electricity or biogas for which RINs have 

been generated in accordance with 

§ 80.1426(f) must separate any RINs that 

have been assigned to that volume of 

renewable electricity or biogas if: 

(i) The party designates the electricity 

or biogas as transportation fuel; and 

(ii) The electricity or biogas is used as 

transportation fuel. 

(6) 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)(6) shall not 

apply to biodiesel owned by obligated 

parties or to exported volumes of 

biodiesel. 

(ii) This paragraph (b)(6) shall not 

apply to parties meeting the 

requirements of paragraph (b)(4) of this 

section. 

(7) For RINs that an obligated party 

generates for renewable fuel that has not 

been blended into gasoline or diesel to 

produce a transportation fuel, heating 

oil, or jet 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 

are less than or equal to a limit set as 

follows: 

(i) For RINs with a D code of 3, the 

limit shall be equal to RVOCB. 

(ii) For RINs with a D code of 4, the 

limit shall be equal to RVOBBD. 

(iii) For RINs with a D code of 7, the 

limit shall be equal to the larger of 

RVOBBD or RVOCB. 

(iv) For RINs with a D code of 5, the 

limit shall be equal to 

RVOAB¥RVOCB¥RVOBBD.

(v) For RINs with a D code of 6, the 

limit shall be equal to RVORF¥RVOAB. 

(8) Small refiners and small refineries 

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, 

heating oil, or jet fuel, or that the party 

used as transportation fuel, heating oil, 

or jet fuel. This paragraph (b)(8) shall 

apply only under the following 

conditions: 

(i) During the calendar year in which 

the party has received a small refinery 

exemption under § 80.1441 or a small 

refiner exemption under § 80.1442; and 

(ii) The party is not otherwise an 

obligated party during the period of 

time that the small refinery or small 

refiner exemption is in effect. 

(9) Except as provided in paragraphs 

(b)(2) through (b)(5) and (b)(8) of this 

section, RINs owned by obligated 

parties whose non-export renewable 

volume obligations are solely related to 

the addition of blendstocks into a 

volume of finished gasoline, finished 

diesel fuel, RBOB, or CBOB, can only be 

separated from volumes of renewable 

fuel if the number of gallon-RINs 

separated in a calendar year are less 

than or equal to a limit set as follows: 

(i) For RINs with a D code of 3, the 

limit shall be equal to RVOCB. 

(ii) For RINs with a D code of 4, the 

limit shall be equal to RVOBBD. 

(iii) For RINs with a D code of 7, the 

limit shall be equal to the larger of 

RVOBBD or RVOCB. 

(iv) For RINs with a D code of 5, the 

limit shall be equal to 

RVOAB¥RVOCB¥RVOBBD.

(v) For RINs with a D code of 6, the 

limit shall be equal to RVORF¥RVOAB. 

(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 to another party pursuant to 

§ 80.1453. 

(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 

meet the requirements of § 80.1453. 

(f) Any party that uses a renewable 

fuel in any application that is not 

transportation fuel, heating oil, or jet 

fuel, or designates a renewable fuel for 

use as something other than 

transportation fuel, heating oil, or jet 

fuel, must retire any RINs received with 

that renewable fuel and report the 

retired RINs in the applicable reports 

under § 80.1451. 

(g) Any 2009 RINs retired pursuant to 

§ 80.1129 because renewable fuel was 

used in a non-motor vehicle application, 

heating oil, or jet fuel 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(b) shall acquire 

sufficient RINs to comply with all 

applicable Renewable Volume 

Obligations under paragraph (b) of this 

section 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) Cellulosic biofuel. 

RVOCB,i = S(VOLk * EVk)i + DCB,i-1

Where: 

RVOCB,i = The Renewable Volume Obligation 

for cellulosic biofuel for the exporter for 

calendar year i, in gallons. 

k = A discrete volume of exported renewable 

fuel. 

VOLk = The standardized volume of discrete 

volume k of exported renewable fuel that 

the exporter knows or has reason to 

know is cellulosic biofuel, in gallons, 

calculated in accordance with 

§ 80.1426(f)(8). 

EVk = The equivalence value associated with 

discrete volume k. 

S = Sum involving all volumes of cellulosic 

biofuel exported. 

DCB,i-1 = Deficit carryover from the 

previous year for cellulosic biofuel, in 

gallons. 

(2) Biomass-based diesel. 

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 exported renewable 

fuel. 

VOLk = The standardized volume of discrete 

volume k of exported renewable fuel that 

is biodiesel or renewable diesel, or that 

the exporter knows or has reason to 

know is biomass-based diesel, in gallons, 

calculated in accordance with 

§ 80.1426(f)(8). 

EVk = The equivalence value associated with 

discrete volume k. 

S = Sum involving all volumes of biomassbased diesel exported. 

DBBD,i-1 = Deficit carryover from the previous 

year for biomass-based diesel, in gallons. 

(3) Advanced biofuel. 

RVOAB,i = S(VOLk * EVk)i + DAB,i-1

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Where: 

RVOAB,i = The Renewable Volume Obligation 

for advanced biofuel for the exporter for 

calendar year i, in gallons. 

k = A discrete volume of exported renewable 

fuel. 

VOLk = The standardized volume of discrete 

volume k of exported renewable fuel that 

is biodiesel or renewable diesel, or that 

the exporter knows or has reason to 

know is biomass-based diesel, cellulosic 

biofuel, or advanced biofuel, in gallons, 

calculated in accordance with 

§ 80.1426(f)(8). 

EVk = The equivalence value associated with 

discrete volume k. 

S = Sum involving all volumes of advanced 

biofuel exported. 

DAB,i-1 = Deficit carryover from the previous 

year for advanced biofuel, in gallons. 

(4) Renewable fuel. 

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. 

k = A discrete volume of exported renewable 

fuel. 

VOLk = The standardized volume of discrete 

volume k of any exported renewable 

fuel, in gallons, calculated in accordance 

with § 80.1426(f)(8). 

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. 

(c) If the exporter knows or has reason 

to know that a volume of exported 

renewable fuel is cellulosic diesel, he 

must treat the exported volume as either 

cellulosic biofuel or biomass-based 

diesel when determining his Renewable 

Volume Obligations pursuant to 

paragraph (b) of this section. 

(d) For the purposes of calculating the 

Renewable Volume Obligations: 

(1) If the equivalence value for a 

volume of exported 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 under 

paragraph (b) of this section. 

(2) If the category of the exported 

renewable fuel is known to be biomassbased diesel but the composition is 

unknown, the value of EVk shall be 1.5. 

(3) If neither the category nor 

composition of a volume of exported 

renewable fuel can be determined, the 

value of EVk shall be 1.0. 

(e) For renewable fuels that are in the 

form of a blend with gasoline or diesel 

at the time of export, the exporter shall 

determine the volume of exported 

renewable fuel based on one of the 

following: 

(1) Information from the supplier of 

the blend of the concentration of 

renewable fuel in the blend. 

(2) Determination of the renewable 

portion of the blend using Method B or 

Method C of ASTM D 6866 

(incorporated by reference, see 

§ 80.1468), or an alternative test method 

as approved by the EPA. 

(3) Assuming the maximum 

concentration of the renewable fuel in 

the blend as allowed by law and/or 

regulation. 

(f) Each exporter of renewable fuel 

must demonstrate compliance with its 

RVOs pursuant to § 80.1427. 

§ 80.1431 Treatment of invalid RINs. 

(a) Invalid RINs. 

(1) An invalid RIN is a RIN that is any 

of the following: 

(i) A duplicate of a valid RIN. 

(ii) Was based on incorrect volumes or 

volumes that have not been 

standardized to 60 °F. 

(iii) Has expired, as provided in 

§ 80.1428(c). 

(iv) Was based on an incorrect 

equivalence value. 

(v) Deemed invalid under 

§ 80.1467(g). 

(vi) Does not represent renewable fuel 

as defined in § 80.1401. 

(vii) Was assigned an incorrect ‘‘D’’ 

code value under § 80.1426(f) for the 

associated volume of fuel. 

(viii) Was improperly separated 

pursuant to § 80.1429. 

(ix) Was otherwise improperly 

generated. 

(2) 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. 

(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 keep copies and adjust its records, 

reports, and compliance calculations in 

which the invalid RINs were used. The 

party must retire the invalid RINs in the 

applicable RIN transaction reports 

under § 80.1451(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 

invalid RINs are retired 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 

§ 80.1451. 

(2) May not be transferred to another 

person 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 of the following: 

(1) The RIN separation requirements 

of § 80.1429. 

(2) The reporting requirements of 

§ 80.1451. 

(3) The recordkeeping requirements of 

§ 80.1454. 

(4) The attest engagement 

requirements of § 80.1464. 

(c) For upstream delegation of RINrelated responsibilities, both parties 

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must agree on the delegation, and a 

quarterly written statement signed by 

both parties must be included with the 

reporting party’s reports under 

§ 80.1451. 

(1) Both parties must keep copies of 

the signed quarterly written statement 

agreeing to the upward delegation for 5 

years. 

(2) Parties delegating their RIN 

responsibilities upward shall keep 

copies of their registration forms as 

submitted to EPA. 

(3) 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. 

(d) Renewable fuel blenders who 

handle and blend less than 125,000 

gallons of renewable fuel per year and 

delegate their RIN-related 

responsibilities under paragraph (b) of 

this section must register pursuant to 

§ 80.1450(e). 

(e) 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 

from January 1, 2010 through December 

31, 2010 from the renewable fuel 

standards of § 80.1405, and the owner or 

operator of the refinery, or foreign 

refinery, is exempt from the 

requirements that apply to obligated 

parties under this subpart M for fuel 

produced at the refinery if the refinery 

meets the definition of a small refinery 

under § 80.1401 for calendar year 2006. 

(2) The exemption of paragraph (a)(1) 

of this section 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. 

(6) Refiners who own refineries that 

qualified as small under 40 CFR 80.1141 

do not need to resubmit a small refinery 

verification letter under this subpart M. 

This paragraph (a) does not supersede 

§ 80.1141. 

(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 July 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 (i) 

and (o), and must be submitted by July 

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 complete 

verification letter under subpart K of 

this part 80. Verification letters 

submitted under subpart K prior to July 

1, 2010 that satisfy the requirements of 

subpart K shall be deemed to satisfy the 

requirements for verification letters 

under this subpart M. 

(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 

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 a 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 

transportation fuel produced at that 

refinery will be subject to the renewable 

fuels standard of § 80.1405 and the 

owner or operator of the refinery shall 

be subject to all other requirements that 

apply to obligated parties under this 

Subpart M. 

(3) The waiver notice 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 waiver notices 

under paragraph (f) of this section shall 

be sent to one of the following 

addresses: 

(1) For US mail: U.S. EPA, Attn: RFS 

Program, 6406J, 1200 Pennsylvania 

Avenue, NW., Washington, DC 20460. 

(2) For overnight or courier services: 

U.S. EPA, Attn: RFS Program, 6406J, 

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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. 

(3) Refiners who qualified as small 

under 40 CFR 80.1142 do not need to 

reapply for small refiner status under 

this subpart M. This paragraph (a) does 

not supersede § 80.1142. 

(b)(1) The small refiner exemption is 

effective immediately, except as 

provided in paragraph (b)(5) of this 

section. 

(2) Refiners who qualify for the small 

refiner exemption under paragraph (a) 

of this section must submit a 

verification letter (and any other 

relevant information) to EPA by July 1, 

2010. The small refiner verification 

letter must include all of 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) The verification letter must be 

signed by the president, chief operating 

or chief executive officer of the 

company, or his/her designee, stating 

that the information is true to the best 

of his/her knowledge, and that the 

company owned the refinery as of 

December 31, 2006. 

(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 shutdown 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 verification 

letters (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 July 1, 2010 to 

one of the addresses listed in paragraph 

(i) of this section. 

(6) Small refiner verification letters 

submitted under subpart K (§ 80.1142) 

prior to July 1, 2010 that satisfy the 

requirements of subpart K shall be 

deemed to satisfy the requirements for 

small refiner verification letters under 

this subpart M. 

(c) Small refiner temporary 

exemption. 

(1) Transportation fuel produced by 

an approved small refiner, or foreign 

small refiner (as defined at § 80.1465(a)), 

is exempt from January 1, 2010 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 the criteria 

of paragraph (a)(1) of this section. 

(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 (i) 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 of January 

1 of the next calendar year, 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 

small refiner status verification letter 

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 affects 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. 

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(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 M. 

(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) Small refiner status verification 

letters, small refiner exemption waivers, 

or applications for 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: RFS 

Program, 6406J, 1200 Pennsylvania 

Avenue, NW., Washington, DC 20460. 

(2) For overnight or courier services: 

U.S. EPA, Attn: RFS 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 registered renewable fuel 

producer or importer, for each of its 

facilities, must submit all of the 

following information, as applicable, to 

EPA by March 31 of each year 

(September 1 for the report due in 

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 for expansion of 

production capacity at existing facilities 

or construction of new facilities. 

(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. 

(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, as 

available: 

(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) 

of this section in comparison to 

information provided in previous year 

production outlook reports. 

(d) Production outlook reports shall 

be sent to one of the following 

addresses: 

(1) For U.S. Mail: U.S. EPA, Attn: RFS 

Program—Production Outlook Reports, 

6406J, 1200 Pennsylvania Avenue, NW., 

Washington, DC 20460. 

(2) For overnight or courier services: 

U.S. EPA, Attn: RFS Program— 

Production Outlook Reports, 6406J, 

1310 L Street, NW., 6th floor, 

Washington, DC 20005; (202) 343–9038. 

(e) All production outlook reports 

required under this section shall be 

submitted on forms and following 

procedures prescribed by the 

Administrator. 

§ 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 may be 

submitted to EPA at any time after 

publication of this rule in the Federal 

Register, but must be submitted and 

accepted by EPA by July 1, 2010, or 60 

days prior to RIN ownership, whichever 

date comes later. 

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(b) Producers. Any RIN-generating 

foreign or domestic producer of 

renewable fuel or any foreign producer 

that sells renewable fuel for RIN 

generation by a United States importer 

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 the generation of any 

RINs for their fuel. All the following 

registration information may be 

submitted to EPA at any time after 

promulgation of this rule in the Federal 

Register, but must be submitted and 

accepted by EPA by July 1, 2010, or 60 

days prior to the generation of RINs, 

whichever date comes later, subject to 

this subpart: 

(1) A description of the types of 

renewable fuels that the producer 

intends to produce at the facility and 

that the facility is capable of producing 

without significant modifications to the 

existing facility. For each type of 

renewable fuel, the renewable fuel 

producer shall also provide all the 

following: 

(i) A list of all the feedstocks the 

facility is capable of utilizing without 

significant modification to the existing 

facility. 

(ii) A description of the facility’s 

renewable fuel production processes. 

(iii) The type of co-products produced 

with each type of renewable fuel. 

(iv) A list of the facility’s process 

energy fuel types and locations from 

which the fuel was produced or 

extracted. 

(v) For facilities described in 

§ 80.1403(c) and (d): 

(A) The facility’s baseline volume as 

defined in § 80.1403(a)(1). 

(B) The facility’s renewable fuel 

production capacity as specified in 

applicable air permits issued by the U.S. 

Environmental Protection Agency, state, 

local air pollution control agencies, or 

foreign governmental agencies and that 

govern the construction and/or 

operation of the renewable fuel facility: 

(1) Issued or revised no later than 

December 19, 2007 for facilities 

described in § 80.1403(c). 

(2) Issued or revised no later than 

December 31, 2009 for facilities 

described in § 80.1403(d). 

(C) Copies of applicable air permits 

issued by the U.S. Environmental 

Protection Agency, state, local air 

pollution control agencies, or foreign 

governmental agencies, that provide 

evidence that such permits were issued 

prior to December 19, 2007 for facilities 

described in § 80.1403(c), and prior to 

December 31, 2009 for facilities 

described in § 80.1403(d). 

(D) Copies of documents 

demonstrating the facility’s actual peak 

capacity as defined in § 80.1401(a)(3) 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, local air pollution control 

agencies, or foreign governmental 

agencies. 

(E) The date that construction 

commences, along with evidence 

demonstrating that construction 

commenced as defined in 

§ 80.1403(a)(4) including, but not 

limited to, contracts with construction 

and other companies. 

(vi) Records relevant to generation of 

RINs from: 

(A) Producers providing biogas, or 

renewable electricity to transportation 

fueling facilities as described in 

§ 80.1426(f)(10); 

(B) Producers providing biogas, or 

renewable electricity to transportation 

fueling facilities via commercial 

distribution systems as described in 

§ 80.1426(f)(11); and 

(C) Producers using biogas for process 

heat in the production of renewable fuel 

as described in § 80.1426(f)(12). 

(vii)(A) For a producer of renewable 

fuel made from separated yard waste per 

§ 80.1426(f)(5)(i)(A): 

(1) The location of any municipal 

waste facility or other facility from 

which the waste stream consisting 

solely of separated yard waste is 

collected; and 

(2) A plan documenting how the 

waste will be collected and for ongoing 

verification that such waste consists 

only of yard waste and kept separate 

since generation from other waste 

materials, and incidental other 

components (e.g., paper and plastics). 

(B) For a producer of renewable fuel 

made from separated food waste per 

§ 80.1426(f)(5)(i)(B): 

(1) The location of any municipal 

waste facility or other facility from 

which the waste stream consisting 

solely of separated food waste is 

collected; and 

(2) A plan documenting how the 

waste will be collected, how the 

cellulosic and non-cellulosic portions of 

the waste will be quantified, and for 

ongoing verification that such waste 

consists only of food waste kept 

separate since generation from other 

waste materials, containing only 

incidental other components (e.g., paper 

and plastics). 

(viii) For a producer of renewable fuel 

made from separated municipal solid 

waste per § 80.1426(f)(5)(i)(C): 

(A) The location of the municipal 

waste facility from which the separated 

food and yard waste is collected. 

(B) A plan providing ongoing 

verification that there is separation of 

recyclable paper, cardboard, plastics, 

rubber, textiles, metals, and glass wastes 

to the extent reasonably practicable and 

which documents the following: 

(1) Extent and nature of recycling that 

occurred prior to receipt of the waste 

material by the renewable fuel producer; 

(2) Identification of available 

recycling technology and practices that 

are appropriate for removing recycling 

materials from the waste stream; and 

(3) Identification of the technology or 

practices selected including an 

explanation for such selection, and 

reasons why other technologies or 

practices were not. 

(C) Contracts relevant to materials 

recycled from municipal waste streams 

as described in § 80.1426(f)(5)(iii). 

(D) Certification by the producer that 

recycling is conducted in a manner 

consistent with goals and requirements 

of applicable State and local laws 

relating to recycling and waste 

management. 

(2) An independent third party 

engineering review and written report 

and verification of the information 

provided pursuant to paragraph (b)(1) of 

this section. The report and verification 

shall be based upon a site visit and 

review of relevant documents and shall 

separately identify each item required 

by paragraph (b)(1) of this section, 

describe how the independent third 

party evaluated the accuracy of the 

information provided, state whether the 

independent third party agrees with the 

information provided, and identify any 

exceptions between the independent 

third party’s findings and the 

information provided. 

(i) The verifications required under 

this section must be conducted by: 

(A) A Professional Chemical Engineer 

who is based in the United States and 

is licensed by an appropriate state 

agency for a domestic production 

facility. 

(B) An independent third party who 

is a licensed professional engineer or 

foreign equivalent who works in the 

chemical engineering field for a foreign 

production facility. 

(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. 

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(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. 

(E) The third party must provide to 

EPA documentation of his or her 

qualifications as part of the engineering 

review, including proof of appropriate 

professional license or foreign 

equivalent. 

(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 

§ 80.1454(b)(6). 

(3) A Fuel Supply Plan that includes 

all the following information: 

(i) Name of source of each and every 

fuel that the renewable fuel producer 

intends to be co-fired or used in a fuel 

blend. 

(ii) Anticipated proportion of each 

fuel in the mix or in the fuel blend. 

(iii) Anticipated net heat content of 

each, including any expected seasonal 

variations, such as those due to 

moisture content or wood species. 

(iv) Seasonal variation, if any, of the 

fuel mix or blend. 

(v) An affidavit from the biogas 

supplier stating its intent to supply 

biogas to the renewable fuel producer, 

the quantity and energy content of the 

biogas that it intends to provide to the 

renewable fuel producer, and a 

statement that this volume of biogas will 

not be used for the creation of a 

Renewable Energy Credit, or of any 

other type of environmental or energy 

attribute or credit. 

(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 

generating or owning RINs. Registration 

information may be submitted to EPA at 

any time after promulgation of this rule 

in the Federal Register, but must be 

submitted and accepted by EPA by July 

1, 2010, or 60 days prior to an importer 

importing any renewable fuel with 

assigned RINs or generating any RINs 

for renewable fuel, whichever date 

comes later. 

(d) Registration updates. 

(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 that do not affect the renewable 

fuel category for which the producer is 

registered per paragraph (b) of this 

section must update his registration 

information 7 days prior to the change. 

(3) All producers of renewable fuel 

must update registration information 

and submit a copy of an updated 

independent engineering review every 3 

years after initial registration. In 

addition to conducting the engineering 

review and written report and 

verification required by paragraph (b)(2) 

of this section, the updated independent 

engineering review shall include a 

detailed review of the renewable fuel 

producer’s calculations used to 

determine VRIN of a representative 

sample of batches of each type of 

renewable fuel produced since the last 

registration. The representative sample 

shall be selected in accordance with the 

sample size guidelines set forth at 

§ 80.127. 

(e) Any party who owns RINs, intends 

to own RINs, or intends to allow another 

party to separate RINs as per § 80.1440, 

but who is not covered by paragraphs 

(a), (b), or (c) 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 may be 

submitted to EPA at any time after 

promulgation of this rule in the Federal 

Register, but must be submitted at least 

30 days prior to RIN ownership. 

(f) To aid EPA in verifying claims that 

a facility qualifies for an exemption 

described in § 80.1403(c) or (d), 

registrations for such facilities must be 

submitted by July 1, 2013. EPA may in 

its sole discretion waive this 

requirement if it determines that the 

information submitted in any later 

registration can be verified by EPA in 

the same manner as would have been 

possible with a timely submission. 

(g) Registration shall be on forms, and 

following policies, established by the 

Administrator. 

§ 80.1451 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 reports for the 

previous compliance period shall be 

submitted by February 28 of each year 

and shall include all of the following 

information: 

(i) The obligated party’s or exporter’s 

name. 

(ii) The EPA company registration 

number. 

(iii) Whether the domestic refiner, as 

defined in § 80.1406, 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 and 

import volume of all of the products 

listed in § 80.1407(c) and (e) 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 

category of renewable fuel, as those 

fuels are defined in § 80.1401 (i.e., 

cellulosic biofuel, biomass-based diesel, 

advanced biofuel, renewable fuel, and 

cellulosic diesel), retired for 

compliance. 

(ix) The total prior-year RINs by 

renewable fuel category, as those fuels 

are defined in § 80.1401, retired for 

compliance. 

(x) The total cellulosic biofuel waiver 

credits used to meet the party’s 

cellulosic biofuel RVO. 

(xi) A list of all RINs retired for 

compliance in the reporting year. 

(A) RIN information provided by the 

EPA Moderated Transaction System 

(EMTS) that is retired to meet 

compliance conveyed via the EMTS as 

per § 80.1452. 

(B) [Reserved] 

(xii) Any deficit RVO(s) carried into 

the subsequent year. 

(xiii) Any additional information that 

the Administrator may require. 

(2) The RIN transaction reports 

required under paragraph (c)(1) of this 

section. 

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(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 or exporter. 

(b) Renewable fuel producers 

(domestic and foreign) and importers. 

Any domestic producer or importer of 

renewable fuel who generates RINs, 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) For RINs generated beginning on 

July 1, 2010, RIN generation reports for 

each facility owned by the renewable 

fuel producer or importer shall be 

submitted according to the schedule 

specified in paragraph (f)(2) of this 

section. 

(ii) The RIN generation reports shall 

include all the following information for 

each batch of renewable fuel produced 

or imported, where ‘‘batch’’ means a 

discrete quantity of renewable fuel 

produced or imported and assigned a 

unique batch-RIN per § 80.1426(d): 

(A) The RIN generator’s name. 

(B) The RIN generator’s EPA company 

registration number. 

(C) The renewable fuel producer EPA 

facility registration number. 

(D) The importer EPA facility 

registration number and foreign 

renewable producer company 

registration number, if applicable. 

(E) The applicable reporting period. 

(F) The quantity of RINs generated for 

each batch according to § 80.1426. 

(G) The production date of each batch. 

(H) The category of renewable fuel of 

each batch, as defined in § 80.1401. 

(I) The volume of denaturant and 

applicable equivalence value of each 

batch. 

(J) The volume of each batch 

produced. 

(K) The types and volumes of 

feedstocks used. 

(L) The process(es) and feedstock(s) 

used and proportion of renewable 

volume attributable to each process and 

feedstock. 

(M) The type of co-products produced 

with each batch of renewable fuel. 

(N) The volume of co-products 

produced in each quarter. 

(O) A list of the RINs generated and 

an affirmation that the feedstock(s) used 

for each batch meets the definition of 

renewable biomass as defined in 

§ 80.1401. 

(P) Producers of renewable electricity 

and biogas used for transportation as 

described in § 80.1426(f)(10) and (11), 

and producers of renewable fuel that 

use biogas for process heat as described 

in § 80.1426(f)(12), shall report the 

energy content produced and supplied 

to the transportation fueling facility, in 

units of energy (for example, MMBtu or 

MW) based on metering of gas volume 

or electricity. And the name and EPA 

company registration number of the 

transportation fueling facility. 

(Q) Producers of renewable fuel that 

use biogas for process heat as described 

in § 80.1426(f)(12), shall identify the 

supplier of the biogas and report the 

energy content produced and supplied 

to the renewable fuel facility, in MMBtu 

based on metering of gas volume. 

(R) Producers of renewable fuel made 

from municipal solid waste as described 

in § 80.1426(f)(5)(i)(C), shall report the 

amount of paper, cardboard, plastics, 

rubber, textiles, metals, and glass 

separated from municipal solid waste 

for recycling. Reporting shall be in units 

of weight. 

(S) Any additional information the 

Administrator may require. 

(2) The RIN transaction reports 

required under paragraph (c)(1) of this 

section. 

(3) The 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 or 

importer. 

(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 

according to the schedule, and 

containing all the information, that is 

set forth in this paragraph (c). 

(1)(i) For RIN transactions beginning 

on July 1, 2010, RIN transaction reports 

listing each RIN transaction shall be 

submitted according to the schedule in 

paragraph (f)(2) of this section. 

(ii) As per § 80.1452, RIN transaction 

information listing each RIN transaction 

shall be submitted to the EMTS. 

(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 submitting party’s EPA 

company registration number. 

(C) The applicable reporting period. 

(D) Transaction type (i.e., RIN buy, 

RIN sell, RIN separation, RIN retire, 

reinstated 2009 RIN). 

(E) Transaction date. 

(F) For a RIN purchase or sale, the 

trading partner’s name. 

(G) 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. 

(H) RIN subject to the transaction. 

(I) For a RIN purchase or sale, the per 

gallon RIN price and/or the per gallon 

price of renewable fuel price with RINs 

included. 

(J) The reason code for retiring RINs, 

separating RINs, buying RINs, or selling 

RINs. 

(K) Any additional information that 

the Administrator may require. 

(2) RIN activity reports shall be 

submitted to EPA according to the 

schedule specified in paragraph (f)(2) of 

this section. Each report shall 

summarize RIN activities for the 

reporting period, separately for RINs 

separated from a renewable fuel volume 

and RINs 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 submitting party’s EPA 

company registration number. 

(iii) The number of current-year RINs 

owned at the start of the quarter. 

(iv) The number of prior-year RINs 

owned at the start of the quarter. 

(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) The number of RINs generated. 

(xiv) The volume of renewable fuel (in 

gallons) owned at the end of the quarter. 

(xv) The total 2009 retired RINs 

reinstated. 

(xvi) 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) Except for those producers subject 

to the aggregate compliance approach 

described in § 80.1454(g), producers and 

RIN-generating importers of renewable 

fuel made from feedstocks that are 

planted crops and crop residue from 

existing agricultural land, planted trees 

or tree residue from actively managed 

tree plantations, slash and precommercial thinnings from forestlands 

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or biomass obtained from areas at risk 

of wildfire must submit quarterly 

reports according to the schedule in 

paragraph (f)(2) of this section that 

include all of the following: 

(1) A summary of the types and 

volumes of feedstocks used in that 

quarter. 

(2) Electronic data identifying the 

land by coordinates of the points 

defining the boundaries from which 

each type of feedstock listed per 

paragraph (d)(1) of this section was 

harvested. 

(3) If electronic data identifying a plot 

of land have been submitted previously, 

producers and RIN-generating importers 

may submit a cross-reference to that 

electronic data. 

(e) If EPA finds that the 2007 baseline 

amount of agricultural land has been 

exceeded in any year beginning in 2010, 

beginning on the first day of July of the 

following calendar year any domestic 

producers of renewable fuel as defined 

in § 80.1401 who use planted crops and/ 

or crop residue from existing 

agricultural lands as feedstock must 

submit quarterly reports according to 

the schedule in paragraph (f)(2) of this 

section that include all of the following: 

(1) A summary of the types and 

volumes of feedstocks used in that 

quarter. 

(2) Maps or electronic data identifying 

the land from which each type of 

feedstock listed per paragraph (d)(1) 

above was harvested. 

(i) If maps or electronic data 

identifying a plot of land have been 

submitted previously, producers and 

RIN-generating importers may submit a 

cross-reference to that map or electronic 

data. 

(ii) [Reserved.] 

(f) Quarterly report submission 

deadlines. The submission deadlines for 

quarterly reports shall be as follows: 

(1) [Reserved.] 

(2) Quarterly reports shall be 

submitted to EPA by the last day of the 

second month following the reporting 

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). Any reports generated 

by EMTS must be reviewed, 

supplemented, and/or corrected if not 

complete and accurate, and verified by 

the owner or responsible corporate 

office prior to submittal. 

(3) Reports required must be signed 

and certified as meeting all the 

applicable requirements of this subpart 

by the owner or a responsible corporate 

officer of the submitter. 

(g) All reports required under this 

section shall be submitted on forms and 

following procedures prescribed by the 

Administrator. 

§ 80.1452 What are the requirements 

related to the EPA Moderated Transaction 

System (EMTS)? 

(a) Each party required to submit 

information under this section must 

establish an account with the EPA 

Moderated Transaction System (EMTS) 

at least 60 days prior to engaging in any 

RIN transactions, or July 1, 2010, 

whichever is later. 

(b) Starting July 1, 2010, 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 

via the submitting party’s EMTS 

account within five (5) business days: 

(1) The renewable fuel producer’s, 

foreign renewable fuel producer’s, or 

importer’s name. 

(2) The renewable fuel producer’s or 

foreign renewable fuel producer’s EPA 

company registration number. 

(3) The importer’s EPA company 

registration number if applicable. 

(4) The renewable fuel producer’s or 

foreign renewable fuel producer’s EPA 

facility registration number. 

(5) The importer’s EPA facility 

registration number. 

(6) The RIN type (i.e., D code) of the 

batch. 

(7) The production process(es) used 

for the batch. 

(8) The production date of the batch. 

(9) The category of renewable fuel of 

the batch, as defined in § 80.1401. 

(10) The volume of the batch. 

(11) The volume of denaturant and 

applicable equivalence value of each 

batch. 

(12) Quantity of RINs generated for 

the batch. 

(13) The type and volume of 

feedstock(s) used for the batch. 

(14) An affirmation that the 

feedstock(s) used for each batch meets 

the definition of renewable biomass as 

defined in § 80.1401. 

(15) The type of co-products produced 

with the batch of renewable fuel. 

(16) Any additional information the 

Administrator may require. 

(c) Starting July 1, 2010, each time 

any party engages in a transaction 

involving RINs, all the following 

information must be submitted to EPA 

via the submitting party’s EMTS 

account within five (5) business days: 

(1) The submitting party’s name. 

(2) The submitting party’s EPA 

company registration number. 

(3) The generation year of the RINs. 

(4) The RIN assignment information 

(Assigned or Separated). 

(5) The RIN type, or D code. 

(6) Transaction type (i.e., RIN buy, 

RIN sell, RIN separation, RIN retire). 

(7) Transaction date as per 

§ 80.1453(a)(4). 

(8) For a RIN purchase or sale, the 

trading partner’s name. 

(9) For a RIN purchase or sale, the 

trading partner’s EPA company 

registration number. 

(10) For an assigned RIN purchase or 

sale, the renewable fuel volume 

associated with the sale. 

(11) Quantity of RINs involved in a 

transaction. 

(12) The per gallon RIN price or the 

per-gallon price of renewable fuel with 

RINs included. 

(13) The reason for retiring RINs, 

separating RINs, buying RINs, or selling 

RINs. 

(14) Any additional information that 

the Administrator may require. 

(d) All information 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 

or separated RINs subject to this 

subpart, the transferor must provide to 

the transferee documents identifying the 

renewable fuel and any RINs (whether 

assigned or separated) 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 numbers. 

(3) The volume of renewable fuel that 

is being transferred, if any. 

(4) The date of the transfer. 

(5) For assigned or separated RINs, the 

per gallon RIN price or the per gallon 

renewable fuel price if the RIN price is 

included. 

(6) The quantity of RINs being traded. 

(7) The RIN type (i.e., D code). 

(8) The Assignment Code (Assigned or 

Separated, or K code = 1 or 2). 

(9) The RIN generation year. 

(10) The associated reason for the sell 

or buy transaction. 

(11) 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. 

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(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 

§ 80.1429(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)(11) of this section if such 

codes are clearly understood by each 

transferee. 

(c) For renewable fuel, other than 

ethanol, that is not registered as motor 

vehicle fuel under 40 CFR Part 79, the 

PTD which is used to transfer 

ownership of the renewable fuel shall 

state ‘‘This volume of renewable fuel 

may not be used as a motor vehicle 

fuel.’’ 

§ 80.1454 What are the recordkeeping 

requirements under the RFS program? 

(a) Requirements for obligated parties 

and exporters. Beginning July 1, 2010, 

any obligated party (as described at 

§ 80.1406) or exporter of renewable fuel 

(as described at § 80.1401) must keep all 

of the following records: 

(1) Product transfer documents 

consistent with § 80.1453 and associated 

with the obligated party’s or exporter’s 

activity, if any, as transferor or 

transferee of renewable fuel or separated 

RINs. 

(2) Copies of all reports submitted to 

EPA under §§ 80.1449 and 80.1451(a), 

as applicable. 

(3) Records related to each RIN 

transaction, including all of the 

following: 

(i) A list of the RINs owned, 

purchased, sold, separated, 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 RIN transaction and its 

terms. 

(4) Records related to the use of RINs 

(by facility, if applicable) for 

compliance, including all of 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. 

(5) Records related to the separation 

of assigned RINs from renewable fuel 

volume. 

(b) Requirements for all producers of 

renewable fuel. Beginning July 1, 2010, 

any domestic or RIN-generating foreign 

producer of a renewable fuel as defined 

in § 80.1401 must keep all of the 

following records in addition to those 

required under paragraphs (c) or (d) of 

this section: 

(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 or separated 

RINs. 

(2) Copies of all reports submitted to 

EPA under §§ 80.1449 and 80.1451(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, 

if applicable. 

(iv) Identification of batches by 

renewable category. 

(v) Type and quantity of co-products 

produced. 

(vi) Type and quantity of feedstocks 

used. 

(vii) Type and quantity of fuel used 

for process heat. 

(viii) Feedstock energy calculations 

per § 80.1426(f)(4). 

(ix) Date of production. 

(x) Results of any laboratory analysis 

of batch chemical composition or 

physical properties. 

(xi) All commercial documents and 

additional information related to details 

of RIN generation. 

(4) Records related to each RIN 

transaction, separately for each 

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 for which 

RINs were generated or blend of 

renewable fuel for which RINs were 

generated and gasoline or diesel fuel 

that any party designates for use as 

transportation fuel, jet fuel, or heating 

oil and the use of the fuel or blend as 

transportation fuel, jet fuel, or heating 

oil without further blending, in the 

designated form. 

(6) Copies of registration documents 

required under § 80.1450, including 

information on fuels and products, 

feedstocks, facility production 

processes, process changes, and 

capacity, energy sources, and a copy of 

the independent third party engineering 

review submitted to EPA per 

§ 80.1450(b)(2). 

(c) Additional requirements for 

imports of renewable fuel. 

(1) Beginning July 1, 2010, any RINgenerating foreign producer of a 

renewable fuel or RIN-generating 

importer must keep records of feedstock 

purchases and transfers associated with 

renewable fuel for which RINs are 

generated, sufficient to verify that 

feedstocks used are renewable biomass 

(as defined in § 80.1401). 

(i) RIN-generating foreign producers 

and importers of renewable fuel made 

from feedstocks that are planted crops 

or crop residue from existing 

agricultural land, planted trees or tree 

residue from actively managed tree 

plantations, slash and pre-commercial 

thinnings from forestlands or biomass 

obtained from wildland-urban interface 

must maintain all of the following 

records to verify the location where 

these feedstocks were produced: 

(A) Maps or electronic data 

indentifying the boundaries of the land 

where each type of feedstock was 

produced. 

(B) Bills of lading, product transfer 

documents, or other commercial 

documents showing the quantity of 

feedstock purchased from each area 

identified in paragraph (c)(1)(i)(A) of 

this section, and showing each transfer 

of custody of the feedstock from the 

location where it was produced to the 

renewable fuel production facility. 

(ii)(A) RIN-generating foreign 

producers and importers of renewable 

fuel made from planted crops or crop 

residue from existing agricultural land 

must keep records that serve as 

evidence that the land from which the 

feedstock was obtained was cleared or 

cultivated prior to December 19, 2007 

and actively managed or fallow, and 

nonforested on December 19, 2007. RINgenerating foreign producers or 

importers of renewable fuel made from 

planted trees or tree residue from 

actively managed tree plantations must 

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keep records that serve as evidence that 

the land from which the feedstock was 

obtained was cleared prior to December 

19, 2007 and actively managed on 

December 19, 2007. 

(B) The records must be provided by 

the feedstock producer, traceable to the 

land in question, and consist of at least 

one of the following documents: 

(1) Sales records for planted crops or 

trees, crop or tree residue, or livestock; 

purchasing records for fertilizer, weed 

control, or reseeding, including seeds, 

seedlings, or other nursery stock. 

(2) 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. 

(3) Documentation of land 

management in accordance with an 

agricultural or silvicultural product 

certification program, an agreement for 

land management consultation with a 

professional forester that identifies the 

land in question. 

(4) Evidence of the existence and 

ongoing maintenance of a road system 

or other physical infrastructure 

designed and maintained for logging 

use, together with one of the 

aforementioned documents in this 

paragraph (c)(1)(ii)(B). 

(iii) RIN-generating foreign producers 

and importers of renewable fuel made 

from any other type of renewable 

biomass must have documents from 

their feedstock supplier certifying that 

the feedstock qualifies as renewable 

biomass as defined in § 80.1401, 

describing the feedstock and identifying 

the process that was used to generate 

the feedstock. 

(2) Beginning July 1, 2010, any RINgenerating importer of renewable fuel 

(as defined in § 80.1401) must keep all 

of the following records: 

(i) 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. 

(ii) Copies of all reports submitted to 

EPA under §§ 80.1449 and 80.1451(b); 

however, duplicate records are not 

required. 

(iii) Records related to the generation 

and assignment of RINs for each facility, 

including all of the following: 

(A) Batch volume in gallons. 

(B) Batch number. 

(C) RIN as assigned under § 80.1426. 

(D) Identification of batches by 

renewable category. 

(E) Type and quantity of feedstocks 

used. 

(F) Type and quantity of fuel used for 

process heat. 

(G) Date of import. 

(H) Results of any laboratory analysis 

of batch chemical composition or 

physical properties. 

(I) The EPA registration number of the 

foreign renewable fuel producers 

producing the fuel. 

(J) Additional information related to 

details of RIN generation. 

(iv) Records related to each RIN 

transaction, including all of the 

following: 

(A) A list of the RINs owned, 

purchased, sold, separated, retired, or 

reinstated. 

(B) The parties involved in each 

transaction including the transferor, 

transferee, and any broker or agent. 

(C) The date of the transfer of the 

RIN(s). 

(D) Additional information related to 

details of the transaction and its terms. 

(v) Copies of registration documents 

required under § 80.1450. 

(vi) Records related to the import of 

any volume of renewable fuel that the 

importer designates for use as 

transportation fuel, jet fuel, or heating 

oil. 

(d) Additional requirements for 

domestic producers of renewable fuel. 

Except as provided in paragraphs (g) 

and (h) of this section, beginning July 1, 

2010, any domestic producer of 

renewable fuel as defined in § 80.1401 

that generates RINs for such fuel must 

keep 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. 

(1) Domestic producers of renewable 

fuel made from feedstocks that are 

planted trees or tree residue from 

actively managed tree plantations, slash 

and pre-commercial thinnings from 

forestlands or biomass obtained from 

areas at risk of wildfire must maintain 

all the following records to verify the 

location where these feedstocks were 

produced: 

(i) Maps or electronic data identifying 

the boundaries of the land where each 

type of feedstock was produced. 

(ii) Bills of lading, product transfer 

documents or other commercial 

documents showing the quantity of 

feedstock purchased from each area 

identified in paragraph (d)(1)(i) of this 

section, and showing each transfer of 

custody of the feedstock from the 

location where it was produced to the 

renewable fuel production facility. 

(2) Domestic producers of renewable 

fuel made from planted trees or tree 

residue from actively managed tree 

plantations must keep records that serve 

as evidence that the land from which 

the feedstock was obtained was cleared 

prior to December 19, 2007 and actively 

managed on December 19, 2007. The 

records must be provided by the 

feedstock producer and must include at 

least one of the following documents, 

which must be traceable to the land in 

question: 

(i) Sales records for planted trees or 

tree residue. 

(ii) Purchasing records for fertilizer, 

weed control, or reseeding, including 

seeds, seedlings, or other nursery stock. 

(iii) A written management plan for 

silvicultural purposes. 

(iv) Documentation of participation in 

a silvicultural program sponsored by a 

Federal, state, or local government 

agency. 

(v) Documentation of land 

management in accordance with a 

silvicultural product certification 

program, an agreement for land 

management consultation with a 

professional forester. 

(vi) Evidence of the existence and 

ongoing maintenance of a road system 

or other physical infrastructure 

designed and maintained for logging 

use, together with one of the 

aforementioned documents. 

(3) Domestic producers of renewable 

fuel made from any other type of 

renewable biomass must have 

documents from their feedstock supplier 

certifying that the feedstock qualifies as 

renewable biomass as defined in 

§ 80.1401, describing the feedstock and 

identifying the process that was used to 

generate the feedstock. 

(e) Additional requirements for 

producers of fuel exempt from the 20% 

GHG reduction requirement. Beginning 

July 1, 2010, any production facility 

with a baseline volume of fuel that is 

not subject to the 20% GHG threshold, 

pursuant to § 80.1403(c) and (d), must 

keep all of the following: 

(1) Detailed engineering plans for the 

facility. 

(2) Federal, State, and local (or foreign 

governmental) preconstruction 

approvals and permitting. 

(3) Procurement and construction 

contracts and agreements. 

(f) Requirements for other parties that 

own RINs. Beginning July 1, 2010, any 

party, other than those parties covered 

in paragraphs (a) and (b) of this section, 

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 

or separated RINs. 

(2) Copies of all reports submitted to 

EPA under § 80.1451(c). 

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(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 

heating oil and from which RINs were 

separated pursuant to § 80.1429(b)(4). 

(g) Aggregate compliance with 

renewable biomass requirement. Any 

domestic producer of renewable fuel 

made from planted crops or crop 

residue from existing agricultural land 

as defined in § 80.1401 is subject to the 

aggregate compliance approach and is 

not required to maintain feedstock 

records unless EPA publishes a finding 

that the 2007 baseline amount of 

agricultural land has been exceeded. 

(1) EPA will make a finding 

concerning whether the 2007 baseline 

amount of agricultural land has been 

exceeded and will publish this finding 

in the Federal Register by November 30 

of the year preceding the compliance 

period. 

(2) If EPA finds that the 2007 baseline 

amount of agricultural land has been 

exceeded, beginning on the first day of 

July of the compliance period in 

question any domestic producer of 

renewable fuel made from planted crops 

and/or crop residue from agricultural 

lands as feedstock for renewable fuel for 

which RINs are generated must keep all 

the following records: 

(i) Records that serve as evidence that 

the land from which the feedstock was 

obtained was cleared or cultivated prior 

to December 19, 2007 and actively 

managed or fallow, and nonforested on 

December 19, 2007. The records must be 

provided by the feedstock producer and 

must include at least one of the 

following documents, which must be 

traceable to the land in question: 

(A) Sales records for planted crops, 

crop residue or livestock. 

(B) Purchasing records for fertilizer, 

weed control, seeds, seedlings, or other 

nursery stock. 

(C) A written management plan for 

agricultural purposes. 

(D) Documentation of participation in 

an agricultural program sponsored by a 

Federal, state, or local government 

agency. 

(E) Documentation of land 

management in accordance with an 

agricultural product certification 

program. 

(ii) Records to verify the location 

where the feedstocks were produced: 

(A) Maps or electronic data 

indentifying the boundaries of the land 

where each type of feedstock was 

produced; and 

(B) Bills of lading, product transfer 

documents or other commercial 

documents showing the quantity of 

feedstock purchased from each area 

identified in paragraph (c)(1)(i)(A) of 

this section, and showing each transfer 

of custody of the feedstock from the 

location where it was produced to the 

renewable fuel facility. 

(h) Alternative renewable biomass 

tracking requirement. Any foreign or 

domestic renewable fuel producer or 

importer as defined in § 80.1401 may 

comply with the following alternative 

renewable biomass tracking requirement 

instead of the recordkeeping 

requirements in paragraphs (c)(1), (d), 

and (g) of this section: 

(1) To comply with the alternative 

renewable biomass tracking requirement 

under this paragraph (h), a renewable 

fuel producer or importer must either 

arrange to have an independent third 

party conduct a comprehensive program 

of annual compliance surveys, or 

participate in the funding of an 

organization which arranged to have an 

independent third party conduct a 

comprehensive program of annual 

compliance surveys, to be carried out in 

accordance with a survey plan which 

has been approved by EPA. 

(2) The annual compliance surveys 

under this paragraph (h) must be all the 

following: 

(i) Planned and conducted by an 

independent surveyor that meets the 

requirements in § 80.68(c)(13)(i). 

(ii) Conducted at renewable fuel 

production and import facilities and 

their feedstock suppliers. 

(iii) Representative of all renewable 

fuel producers and importers in the 

survey area and representative of their 

feedstock suppliers. 

(iv) Designed to achieve at least the 

same level of quality assurance required 

in paragraphs (c)(1), (d) and (g) of this 

section. 

(3) The compliance survey program 

shall require the independent surveyor 

conducting the surveys to do all the 

following: 

(i) Conduct feedstock audits of 

renewable fuel production and import 

facilities in accordance with the survey 

plan approved under this paragraph (h), 

or immediately notify EPA of any 

refusal of these facilities to allow an 

audit to be conducted. 

(ii) Obtain the records and product 

transfer documents associated with the 

feedstocks being audited. 

(iii) Determine the feedstock 

supplier(s) that supplied the feedstocks 

to the renewable fuel producer. 

(iv) Confirm that feedstocks used to 

produce RIN-generating renewable fuels 

meet the definition of renewable 

biomass as defined in § 80.1401. 

(v) Immediately notify EPA of any 

case where the feedstocks do not meet 

the definition of renewable biomass as 

defined in § 80.1401. 

(vi) Immediately notify EPA of any 

instances where a renewable fuel 

producer, importer or feedstock supplier 

subject to review under the approved 

plan fails to cooperate in the manner 

described in this section. 

(vii) Submit to EPA a report of each 

survey, within thirty days following the 

completion of each survey, such report 

to include all the following information: 

(A) The identification of the person 

who conducted the survey. 

(B) An attestation by the officer of the 

surveyor company that the survey was 

conducted in accordance with the 

survey plan and the survey results are 

accurate. 

(C) Identification of the parties for 

whom the survey was conducted. 

(D) Identification of the covered area 

surveyed. 

(E) The dates on which the survey 

was conducted. 

(F) The address of each facility at 

which the survey audit was conducted 

and the date of the audit. 

(G) A description of the methodology 

used to select the locations for survey 

audits and the number of audits 

conducted. 

(viii) Maintain all records relating to 

the survey audits conducted under this 

section (h) for a period of at least 5 

years. 

(ix) At any time permit any 

representative of EPA to monitor the 

conduct of the surveys, including 

observing audits, reviewing records, and 

analysis of the audit results. 

(4) A survey plan under this 

paragraph (h) must include all the 

following: 

(i) Identification of the parties for 

whom the survey is to be conducted. 

(ii) Identification of the independent 

surveyor. 

(iii) A methodology for determining 

all the following: 

(A) When the audits will be 

conducted. 

(B) The audit locations. 

(C) The number of audits to be 

conducted during the annual 

compliance period. 

(iv) Any other elements determined 

by EPA to be necessary to achieve the 

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level of quality assurance required 

under paragraphs (c)(1), (d), and (g) of 

this section. 

(5)(i) Each renewable fuel producer 

and importer who participates in the 

alternative renewable biomass tracking 

under this paragraph (h) must take all 

reasonable steps to ensure that each 

feedstock producer, aggregator, 

distributor, or supplier cooperates with 

this program by allowing the 

independent surveyor to audit their 

facility and by providing to the 

independent surveyor and/or EPA, upon 

request, copies of management plans, 

product transfer documents, and other 

records or information regarding the 

source of any feedstocks received. 

(ii) Reasonable steps under paragraph 

(h)(5)(i) of this section must include, but 

typically should not be limited to: 

Contractual agreements with feedstock 

producers, aggregators, distributors, and 

suppliers, which require them to 

cooperate with the independent 

surveyor and/or EPA in the manner 

described in paragraph (h)(5)(i) of this 

section. 

(6) The procedure for obtaining EPA 

approval of a survey plan under this 

paragraph (h), and for revocation of any 

such approval, are as follows: 

(i) A detailed survey plan which 

complies with the requirements of this 

paragraph (h) must be submitted to EPA, 

no later than September 1 of the year 

preceding the calendar year in which 

the surveys will be conducted. 

(ii) The survey plan must be signed by 

a responsible corporate officer of the 

renewable fuel producer or importer, or 

responsible officer of the organization 

which arranges to have an independent 

surveyor conduct a program of 

renewable biomass compliance surveys, 

as applicable. 

(iii) The survey plan must be sent to 

the following address: Director, 

Compliance and Innovative Strategies 

Division, U.S. Environmental Protection 

Agency, 1200 Pennsylvania Ave., NW. 

(6406J), Washington, DC 20460. 

(iv) EPA will send a letter to the party 

submitting a survey plan under this 

section, either approving or 

disapproving the survey plan. 

(v) EPA may revoke any approval of 

a survey plan under this section for 

cause, including an EPA determination 

that the approved survey plan had 

proved inadequate in practice or that it 

was not diligently implemented. 

(vi) The approving official for an 

alternative quality assurance program 

under this section is the Director of the 

Compliance and Innovative Strategies 

Division, Office of Transportation and 

Air Quality. 

(vii) Any notifications required under 

this paragraph (h) must be directed to 

the officer designated in paragraph 

(h)(6)(vi) of this section. 

(7)(i) No later than December 1 of the 

year preceding the year in which the 

surveys will be conducted, the contract 

with the independent surveyor shall be 

in effect, and an amount of money 

necessary to carry out the entire survey 

plan shall be paid to the independent 

surveyor or placed into an escrow 

account with instructions to the escrow 

agent to pay the money to the 

independent surveyor during the course 

of the conduct of the survey plan. 

(ii) No later than December 15 of the 

year preceding the year in which the 

surveys will be conducted, EPA must 

receive a copy of the contract with the 

independent surveyor, proof that the 

money necessary to carry out the survey 

plan has either been paid to the 

independent surveyor or placed into an 

escrow account, and, if placed into an 

escrow account, a copy of the escrow 

agreement, to be sent to the official 

designated in paragraph (h)(6)(iii) of this 

section. 

(8) A failure of any renewable fuel 

producers or importer to fulfill or cause 

to be fulfilled any of the requirements 

of this paragraph (h) will cause the 

option for such party to use the 

alternative quality assurance 

requirements under this paragraph (h) to 

be void ab initio. 

(i) Beginning July 1, 2010, all parties 

must keep transaction information sent 

to EMTS in addition to other records 

required under this section. 

(j) A renewable fuel producer that 

produces fuel from separated yard and 

food waste as described in 

§ 80.1426(f)(5)(i)(A) and (B) and 

separated municipal waste as described 

in § 80.1426(f)(5)(i)(C) shall keep all the 

following additional records: 

(1) For separated yard and food waste 

as described in § 80.1426(f)(5)(i)(A) and 

(B): 

(i) Documents demonstrating the 

amounts, by weight, purchased of 

separated yard and food waste for use as 

a feedstock in producing renewable fuel. 

(ii) Such other records as may be 

requested by the Administrator. 

(2) For separated municipal solid 

waste as described in 

§ 80.1426(f)(5)(i)(C): 

(i) Contracts and documents 

memorializing the sale of paper, 

cardboard, plastics, rubber, textiles, 

metals, and glass separated from 

municipal solid waste for recycling. 

(ii) Documents demonstrating the 

amounts by weight purchased of postrecycled separated yard and food waste 

for use as a feedstock in producing 

renewable fuel. 

(iii) Such other records as may be 

requested by the Administrator. 

(k) A renewable fuel producer that 

generates RINs for biogas or electricity 

produced from renewable biomass 

(renewable electricity) for fuels that are 

used for transportation pursuant to 

§ 80.1426(f)(10) and (11), or that uses 

process heat from biogas to generate 

RINs for renewable fuel pursuant to 

§ 80.1426(f)(12) shall keep all of the 

following additional records: 

(1) Contracts and documents 

memorializing the sale of biogas or 

renewable electricity for use as 

transportation fuel relied upon in 

§ 80.1426(f)(10), § 80.1426(f)(11), or for 

use of biogas for use as process heat to 

make renewable fuel as relied upon in 

§ 80.1426(f)(12), and the transfer of title 

of the biogas or renewable electricity 

and all associated environmental 

attributes from the point of generation to 

the transportation fueling facility. 

(2) Documents demonstrating the 

volume and energy content of biogas, or 

energy content of renewable electricity 

relied upon under § 80.1426(f)(10) that 

was delivered to the transportation 

fueling facility. 

(3) Documents demonstrating the 

volume and energy content of biogas, or 

energy content of renewable electricity 

relied upon under § 80.1426(f)(11) or 

biogas relied upon under 

§ 80.1426(f)(12) that was placed into the 

common carrier pipeline (for biogas) or 

transmission line (for renewable 

electricity). 

(4) Documents demonstrating the 

volume and energy content of biogas, or 

energy content of renewable electricity 

relied upon under § 80.1426(f)(12) at the 

point of distribution. 

(5) Affidavits from the biogas, or 

renewable electricity producer and all 

parties that held title to the biogas or 

renewable electricity confirming that 

title and environmental attributes of the 

biogas or renewable electricity relied 

upon under § 80.1426(f)(10) and (11) or 

biogas relied upon under 

§ 80.1426(f)(12) were delivered to the 

transportation fueling facility and only 

to the transportation fueling facility. 

The renewable fuel producer shall 

create and/or obtain these affidavits at 

least once per calendar quarter. 

(6) The biogas or renewable electricity 

producer’s Compliance Certification 

required under Title V of the Clean Air 

Act. 

(7) Such other records as may be 

requested by the Administrator. 

(l) The records required under 

paragraphs (a) through (d) and (f) 

through (k) of this section and under 

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§ 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 the RIN 

transaction. 

(m) The records required under 

paragraph (e) of this section shall be 

kept through calendar year 2022. 

(n) 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. 

(o) The records required in paragraphs 

(b)(3) and (c)(1) of this section must be 

transferred with any renewable fuel sent 

to the importer of that renewable fuel by 

any foreign producer not generating 

RINs for his renewable fuel. 

(p) Copies of all reports required 

under § 80.1464. 

§ 80.1455 What are the small volume 

provisions for renewable fuel production 

facilities and importers? 

(a) Standard volume threshold. 

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 subject 

to the requirements of § 80.1426(a) and 

(e) related to the generation and 

assignment of RINs or 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 registration requirements of 

§ 80.1450. 

(2) The reporting requirements of 

§ 80.1451. 

(3) The EMTS requirements of 

§ 80.1452. 

(4) The recordkeeping requirements of 

§ 80.1454. 

(5) The attest engagement 

requirements of § 80.1464. 

(6) 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 §§ 80.1426, 80.1449 

through 80.1452, 80.1454, 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)(6) and (b)(1) of this section, 

and all other applicable requirements of 

this subpart M. 

(c) Temporary volume threshold. 

Renewable fuel production facilities 

located within the United States that 

produce less than 125,000 gallons of 

renewable fuel each year are not subject 

to the requirements of § 80.1426(a) and 

(e) related to the generation and 

assignment of RINs to batches of 

renewable fuel for up to three years, 

beginning with the calendar year in 

which the production facility produces 

its first gallon of renewable fuel. Except 

as stated in paragraph (d) of this section, 

such production facilities that do not 

generate and/or assign RINs to batches 

of renewable fuel are also exempt from 

all the following requirements of this 

subpart for a maximum of three years: 

(1) The registration requirements of 

§ 80.1450. 

(2) The reporting requirements of 

§ 80.1451. 

(3) The EMTS requirements of 

§ 80.1452. 

(4) The recordkeeping requirements of 

§ 80.1454. 

(5) The attest engagement 

requirements of § 80.1464. 

(6) The production outlook report 

requirements of § 80.1449. 

(d)(1) Renewable fuel production 

facilities who produce less than 125,000 

gallons of renewable fuel each year and 

that generate and/or assign RINs to 

batches of renewable fuel are subject to 

the provisions of §§ 80.1426, 80.1449 

through 80.1452, 80.1454, and 80.1464. 

(2) Renewable fuel production 

facilities who produce less than 125,000 

gallons of renewable fuel each year but 

wish to own RINs will be subject to all 

requirements stated in paragraphs (c)(1) 

through (c)(6) and (d)(1) of this section, 

and all other applicable requirements of 

this subpart M. 

§ 80.1456 What are the provisions for 

cellulosic biofuel waiver credits? 

(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 waiver credits 

for purchase for that compliance year. 

(1) The price of these cellulosic 

biofuel waiver credits will be set by EPA 

on an annual basis in accordance with 

paragraph (d) of this section. 

(2) The total cellulosic biofuel waiver 

credits available will be equal to the 

reduced cellulosic biofuel volume 

established by EPA for the compliance 

year. 

(b) Use of cellulosic biofuel waiver 

credits. 

(1) Cellulosic biofuel waiver credits 

are only valid for use in the compliance 

year that they are made available. 

(2) Cellulosic biofuel waiver credits 

are nonrefundable. 

(3) Cellulosic biofuel waiver credits 

are nontransferable. 

(4) Cellulosic biofuel waiver credits 

may only be used for an obligated 

party’s current year cellulosic biofuel 

RVO and not towards any prior year 

deficit cellulosic biofuel volume 

obligations. 

(c) Purchase of cellulosic biofuel 

waiver credits. 

(1) Only parties with an RVO for 

cellulosic biofuel may purchase 

cellulosic biofuel waiver credits. 

(2) Cellulosic biofuel waiver credits 

shall be purchased from EPA at the time 

that a party submits its annual 

compliance report to EPA pursuant to 

§ 80.1451(a)(1). 

(3) Parties may not purchase more 

cellulosic biofuel waiver credits than 

their current year cellulosic biofuel RVO 

minus cellulosic biofuel RINs with a D 

code of 3 that they own. 

(4) Cellulosic biofuel waiver credits 

may only be used to meet an obligated 

party’s cellulosic biofuel RVO. 

(d) Setting the price of cellulosic 

biofuel waiver credits. 

(1) The price for cellulosic biofuel 

waiver credits shall be set equal to the 

greater of: 

(i) $0.25 per cellulosic biofuel waiver 

credit, adjusted for inflation in 

comparison to calendar year 2008; or 

(ii) $3.00 less the wholesale price of 

gasoline per cellulosic biofuel waiver 

credit, 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 

Refiners 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 at the time EPA sets the 

cellulosic biofuel standard to the most 

recent comparable value reported after 

December 31, 2008. When EPA must set 

the price of cellulosic biofuel waiver 

credits for a compliance year, EPA will 

calculate the new amounts for 

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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 at the time EPA sets the 

cellulosic biofuel standard. 

(e) Cellulosic biofuel waiver credits 

under this section will only be able to 

be purchased on forms and following 

procedures prescribed by EPA. 

§§ 80.1457–80.1459 [Reserved] 

§ 80.1460 What acts are prohibited under 

the RFS program? 

(a) Renewable fuels producer or 

importer violation. Except as provided 

in § 80.1455, no person shall produce or 

import a renewable fuel without 

complying with the requirements of 

§ 80.1426 regarding the generation and 

assignment of RINs. 

(b) RIN generation and transfer 

violations. No person 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 person a 

RIN that is invalid under § 80.1431. 

(3) Transfer to any person a RIN that 

is not properly identified as required 

under § 80.1425. 

(4) Transfer to any person a RIN with 

a K code of 1 without transferring an 

appropriate volume of renewable fuel to 

the same person 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 person’s 

registration information. 

(c) RIN use violations. No person shall 

do any of the following: 

(1) Fail to acquire sufficient RINs, or 

use invalid RINs, to meet the person’s 

RVOs under § 80.1427. 

(2) Fail to acquire sufficient RINs to 

meet the person’s RVOs under 

§ 80.1430. 

(3) Use a validly generated RIN to 

meet the person’s RVOs under 

§ 80.1427, or separate and transfer a 

validly generated RIN, where the person 

ultimately uses the renewable fuel 

volume associated with the RIN in an 

application other than for use as 

transportation fuel, jet fuel, or heating 

oil (as defined in § 80.1401). 

(d) RIN retention violation. No person 

shall retain RINs in violation of the 

requirements in § 80.1428(a)(5). 

(e) Causing a violation. No person 

shall cause another person to commit an 

act in violation of any prohibited act 

under this section. 

(f) Failure to meet a requirement. No 

person shall fail to meet any 

requirement that applies to that person 

under this subpart. 

§ 80.1461 Who is liable for violations 

under the RFS program? 

(a) Liability for violations of 

prohibited acts. 

(1) Any person who violates a 

prohibition under § 80.1460(a) through 

(d) is liable for the violation of that 

prohibition. 

(2) Any person who causes another 

person to violate a prohibition under 

§ 80.1460(a) through (d) is liable for a 

violation of § 80.1460(e). 

(b) Liability for failure to meet other 

provisions of this subpart. 

(1) Any person who fails to meet a 

requirement of any provision of this 

subpart is liable for a violation of that 

provision. 

(2) Any person who causes another 

person 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 person who is liable for a 

violation under § 80.1461 is subject a to 

civil penalty 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 person 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 

person 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 person 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 and 80.1466, 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: 

(1) Annual compliance demonstration 

report. 

(i) Obtain and read a copy of the 

annual compliance demonstration 

report required under § 80.1451(a)(1) 

which contains information regarding 

all the following: 

(A) The obligated party’s volume of 

all products listed in § 80.1407(c) and 

(e), or the exporter’s volume of each 

category of exported renewable fuel 

identified in § 80.1430 (b)(1)(i), (b)(1)(ii), 

(b)(2)(i), and (b)(2)(ii). 

(B) RVOs. 

(C) RINs used for compliance. 

(ii) Obtain documentation of any 

volumes of renewable fuel used in 

products listed in § 80.1407(c) and (e) 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) For obligated parties, compare the 

volumes of products listed in 

§ 80.1407(c) and (e) reported to EPA in 

the report required under § 80.1451(a)(1) 

with the volumes, excluding any 

renewable fuel volumes, contained in 

the inventory reconciliation analysis 

under § 80.133 and the volume of nonrenewable diesel produced or imported. 

Verify that the volumes reported to EPA 

agree with the volumes in the inventory 

reconciliation analysis and the volumes 

of non-renewable diesel produced or 

imported, and report as a finding any 

exception. 

(iv) For exporters, perform all of the 

following: 

(A) Obtain the database, spreadsheet, 

or other documentation that the 

exporter maintains for purposes for all 

exported renewable fuel. 

(B) Compare the volume of products 

identified in these documents with the 

volumes reported to EPA. 

(C) Verify that the volumes reported 

to EPA agree with the volumes 

identified in the database, spreadsheet, 

or other documentation, and report as a 

finding any exception. 

(v) 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. 

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(vi) Obtain the database, spreadsheet, 

or other documentation for all RINs by 

type of renewable fuel used for 

compliance during the year being 

reviewed; calculate the total number of 

RINs associated with each type of 

renewable fuel 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. 

(vii) For exporters, perform all the 

following: 

(A) Select sample batches in 

accordance with the guidelines in 

§ 80.127 from each separate category of 

renewable fuel exported and identified 

in § 80.1451(a). 

(B) Obtain invoices, bills of lading 

and other documentation for the 

representative samples. Calculate the 

RVO for the exported fuel, state whether 

this information agrees with the report 

to EPA and report as a finding any 

exception. 

(C) State whether any of these 

documents refer to the exported fuel as 

advanced biofuel or cellulosic biofuel, 

and report as a finding whether or not 

the exporter calculated an advanced 

biofuel or cellulosic biofuel RVO for 

these fuels pursuant to § 80.1430(b)(2)(i) 

or (ii). 

(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 

§ 80.1451(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 § 80.1451(a)(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 

(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 each 

quarter, purchased, sold, retired and 

reinstated, and for parties that reported 

RIN activity for RINs assigned to a 

volume of renewable fuel, the volume 

and type of renewable fuel (as defined 

in § 80.1401) of renewable fuel owned at 

the end of each 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 RIN-generating renewable fuel 

producer or importer: 

(1) RIN generation reports. 

(i) Obtain and read copies of the 

reports required under § 80.1451(b)(1), 

(e), and (d) for the compliance year. 

(ii) Obtain production data for each 

renewable fuel batch by type of 

renewable fuel that was 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; report the total RINs 

generated during the year being 

reviewed; and state whether this 

information agrees with the party’s 

reports to EPA. Report as a finding any 

exceptions. 

(iii) Verify that the proper number of 

RINs were generated and assigned 

pursuant to the requirements of 

§ 80.1426 for each batch of renewable 

fuel produced or imported. 

(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)(A) Obtain documentation, as 

required under § 80.1451(b), (d), and (e) 

associated with feedstock purchases 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. 

(B) Verify that feedstocks were 

properly identified in the reports and 

met the definition of renewable biomass 

in § 80.1401. 

(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 

§ 80.1451(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 § 80.1451(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; report the total number of 

each RIN generated during each quarter 

and compute and report the total 

number of current-year and prior-year 

RINs owned at the start and end of each 

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 each 

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 

reviews 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 separated, RINs reinstated) 

included in the RIN transaction reports 

required under § 80.1451(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 

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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 § 80.1451(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 each 

quarter, purchased, sold, retired, 

separated, 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 each quarter, as represented 

in these documents; and state whether 

this information agrees with the party’s 

reports to EPA. 

(d) 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. 

(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. 

§ 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 person that 

meets the definition of refiner under 

§ 80.2(i) for a foreign refinery. 

(3) Foreign small refinery is a foreign 

refinery that has received a small 

refinery exemption under § 80.1441. 

(4) Foreign small refiner is a foreign 

refiner that has received a small refiner 

exemption under § 80.1442. 

(5) 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. 

(6) 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 

person 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 temperaturecorrected 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 or owner 

of the foreign small refinery, 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). 

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(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 offloads 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 any 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 

foreign small refinery or foreign small 

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 

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) EPA inspectors and auditors may 

be 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 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 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 or 

contract 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 foreign small refinery or foreign 

small refiner exemption under this 

subpart. 

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(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 

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 person may combine RFS– 

FRFUEL with any Non-RFS–FRFUEL, 

and no person 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 person 

may cause another person 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. 

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(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 of 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 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 person’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 RINgenerating foreign producers and importers 

of renewable fuels for which RINs have 

been generated by the foreign producer? 

(a) Foreign producer of renewable 

fuel. For purposes of this subpart, a 

foreign producer of renewable fuel is a 

person 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 generate RINs 

for renewable fuel it produces for export 

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 that generates RINs 

for renewable fuel must designate each 

batch of such renewable fuel as ‘‘RFS– 

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FRRF’’ at the time the renewable fuel is 

produced. 

(2) On each occasion when RFS–FRRF 

is transferred for transport to a vessel or 

loaded onto a vessel or other 

transportation mode for transport to the 

United States, the RIN-generating 

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 identification of the 

renewable fuel by type, D code, and 

number of RINs generated. 

(iv) The volume of RFS–FRRF, 

standardized per § 80.1426(f)(8), being 

transported, in gallons. 

(3) On each occasion when any 

person 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 

producer identification. 

(1) On each occasion that RFS–FRRF 

is loaded onto a vessel for transport to 

the United States the RIN-generating 

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, standardized per § 80.1426(f)(8), 

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 RIN-generating 

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: 

(i) The RIN-generating 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 RIN-generating 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, 

standardized per § 80.1426(f)(8), except 

as specified in paragraph (e)(1)(ii) of this 

section. 

(ii) Where a vessel transporting RFS– 

FRRF offloads 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 ports of entry. 

(2)(i) If the temperature-corrected 

volumes, after accounting for tank 

bottoms, 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 acquire and retire that amount of 

RINs in accordance with paragraph 

(k)(3) of this section. 

(f) Foreign producer commitments. 

Any RIN-generating 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) EPA inspectors and auditors may 

be 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 may 

include review and copying of any 

documents related to the following: 

(A) The volume of RFS–FRRF. 

(B) The proper classification of 

renewable fuel 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 

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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 for 

actions performed within the scope of 

EPA employment or contract 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 production 

facility 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 

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 RIN-generating 

foreign producer shall meet the 

requirements of this paragraph (h) as a 

condition to approval as a foreign 

producer under this subpart. 

(1) The RIN-generating 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 greater of: the largest volume of 

renewable fuel produced by the foreign 

producer and exported to the United 

States, in gallons, during a single 

calendar year among the five preceding 

calendar years, or the largest volume of 

renewable fuel that the foreign producers 

expects to export to the Unites States 

during any calendar year identified in 

the Production Outlook Report required 

by § 80.1449. If the volume of renewable 

fuel exported to the United States 

increases above the largest volume 

identified in the Production Outlook 

Report during any calendar year, the 

foreign producer shall increase the bond 

to cover the shortfall within 90 days. 

(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. 

(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 person may combine RFS– 

FRRF with any Non-RFS–FRRF, and no 

person may combine RFS–FRRF with 

any RFS–FRRF produced at a different 

production facility, until the importer 

has met all the requirements of 

paragraph (k) of this section. 

(2) No foreign producer or other 

person may cause another person to 

commit an action prohibited in 

paragraph (j)(1) of this section, or that 

otherwise violates the requirements of 

this section. 

(3) No foreign producer and importer 

may generate RINs for the same volume 

of renewable fuel. 

(4) A foreign producer of renewable 

fuel is prohibited from generating RINs 

in excess of the number for which the 

bond requirements of this section have 

been satisfied. 

(k) Requirements for United States 

importers of RFS–FRRF. Any United 

States importers of RFS–FRRF shall 

meet all the following requirements: 

(1) 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 

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foreign producer as required in 

paragraph (c) of this section. 

(2) 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 renewable 

fuel, standardized per § 80.1426(f)(8), 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. 

(3) 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 § 80.1451. 

(4) 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)(2) of this section. 

(ii) The foreign producer, containing 

the information determined under 

paragraph (k)(2)(i) of this section, and 

including identification of the port at 

which the product was offloaded, and 

any RINs retired under paragraph (e)(2) 

of this section. 

(5) Any United States importer shall 

meet all other requirements of this 

subpart for any imported renewable fuel 

that is not classified as RFS–FRRF 

under paragraph (k)(1) 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)(2) 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 all of 

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 

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 § 80.1451 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–FRRF 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 

offloaded for the selected vessels. 

Determine and report as a finding the 

country where the renewable fuel was 

offloaded 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. 

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(2) A foreign government fails to 

allow EPA inspections or audits 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 (h) 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 person’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 person 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. 

(c) Foreign RIN owner commitments. 

Any person 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 

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Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 14903 

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 

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 

person 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 

person may cause another person 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. 

(1) The attest auditor must be 

independent of the foreign RIN owner. 

(2) 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. 

(3) 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 person’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 Incorporation by reference. 

(a) Certain material is incorporated by 

reference into this part with the 

approval of the Director of the Federal 

Register under 5 U.S.C. 552(a) and 1 

CFR part 51. To enforce any edition 

other than that specified in this section, 

the Environmental Protection Agency 

(EPA) must publish notice of change in 

the Federal Register and the material 

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14904 Federal Register / Vol. 75, No. 58 / Friday, March 26, 2010 / Rules and Regulations 

must be available to the public. All 

approved material is available for 

inspection at the National Archives and 

Records Administration (NARA). For 

information on the availability of this 

material at NARA, call 202–741–6030 or 

go to: http://www/archives.gov/

federal_register/code_of

_federal_regulations/ibr_locations.html. 

This material is also available for 

inspection at the EPA Docket Center, 

Docket No. EPA–HQ–OAR–2005–0161, 

EPA/DC, EPA West, Room 3334, 1301 

Constitution Ave., NW., Washington 

DC. The telephone number for the Air 

Docket is (202) 566–1742. Also, this 

material is available from the source 

listed in paragraph (b) of this section. 

(b) American Society for Testing and 

Materials, 100 Barr Harbor Drive, P.O. 

Box C–700, West Conshohocken, 

Pennsylvania 19428 (1–800–262–1373, 

www.astm.org). 

(1) ASTM D 1250–08 (‘‘ASTM D 

1250’’), Standard Guide for Use of the 

Petroleum Measurement Tables, 

Approved 2008; IBR approved for 

§ 80.1426(f)(8)(ii)(B). 

(2) ASTM D 4442–07 (‘‘ASTM D 

4442’’), Standard Test Methods for 

Direct Moisture Content Measurement 

of Wood and Wood-Base Materials, 

Approved 2007; IBR approved for 

§ 80.1426(f)(7)(v)(B). 

(3) ASTM D 4444–08 (‘‘ASTM D 

4444’’), Standard Test Method for 

Laboratory Standardization and 

Calibration of Hand-Held Moisture 

Meters, Approved 2008; IBR approved 

for § 80.1426(f)(7)(v)(B). 

(4) ASTM D 6751–09 (‘‘ASTM D 

6751’’), Standard Specification for 

Biodiesel Fuel Blend Stock (B100) for 

Middle Distillate Fuels, Approved 2009; 

IBR approved for § 80.1401. 

(5) ASTM D 6866–08 (‘‘ASTM D 

6866’’), Standard Test Methods for 

Determining the Biobased Content of 

Solid, Liquid, and Gaseous Samples 

Using Radiocarbon Analysis, Approved 

2008; IBR approved for 

§§ 80.1426(f)(9)(ii) and 80.1430(e)(2). 

(6) ASTM E 711–87 (‘‘ASTM E 711’’), 

Standard Test Method for Gross 

Calorific Value of Refuse-Derived Fuel 

by the Bomb Calorimeter, Reapproved 

2004; IBR approved for 

§ 80.1426(f)(7)(v)(A). 

(7) ASTM E 870–82 (‘‘ASTM E 870’’), 

Standard Test Methods for Analysis of 

Wood Fuels, Reapproved 2006); IBR 

approved for § 80.1426(f)(7)(v)(A). 

[FR Doc. 2010–3851 Filed 3–25–10; 8:45 am] 

BILLING CODE 6560–50–P 

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