55552 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 80 

[EPA–OAR–2005–0161; FRL–8218–8] 

RIN 2060–AN76 

Regulation of Fuels and Fuel 

Additives: Renewable Fuel Standard 

Program 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Notice of proposed rulemaking. 

SUMMARY: Under the Clean Air Act, as 

amended by Section 1501 of the Energy 

Policy Act of 2005, the Environmental 

Protection Agency is required to 

promulgate regulations implementing a 

renewable fuel program. The statute 

specifies the total volume of renewable 

fuel that needs to be used in each year, 

with the total volume increasing over 

time. In this context, it is expected to 

simultaneously reduce dependence on 

foreign sources of petroleum, increase 

domestic sources of energy, and help us 

make progress in moving beyond a 

petroleum-based economy. The 

increased use of renewable fuels such as 

ethanol and biodiesel is also expected to 

have the added benefit of providing an 

expanded market for agricultural 

products such as corn and soybeans, 

expanding economic benefits for our 

nation’s agricultural sector. Based on 

our analysis, there is also reason to 

believe that the expanded use of 

renewable fuels will provide reductions 

in carbon dioxide emissions and some 

air toxics emissions, such as benzene, 

from the transportation sector, while 

other emissions may increase. 

This action proposes regulations 

designed to ensure that refiners, 

blenders, and importers of gasoline will 

use enough renewable fuel each year so 

that this total volume requirement is 

met. Our proposal describes the 

standard that will apply to these parties 

and the renewable fuels that qualify for 

compliance. The regulations would also 

establish a trading program that would 

be a critical aspect of the overall 

program, allowing renewable fuels to be 

used where they are most economical 

while providing a flexible means for 

obligated parties to comply with the 

standard. 

DATES: Comments: Comments must be 

received on or before November 12, 

2006. Under the Paperwork Reduction 

Act, comments on the information 

collection provisions must be received 

by OMB on or before October 30, 2006. 

Hearing: A public hearing will be 

held at 10 a.m. (Central) on October 13, 

2006 at the Sheraton Gateway Suites 

Chicago O’Hare in Rosemont, IL. To 

request to speak at a public hearing, 

send a request to the contact in FOR

FURTHER INFORMATION CONTACT by 

October 4, 2006. 

ADDRESSES: Comments: Submit your 

comments, identified by Docket ID No. 

EPA–OAR–2005–0161, by one of the 

following methods: 

• http://www.regulations.gov: Follow 

the on-line instructions for submitting 

comments. 

• E-mail: ASDinfo@epa.gov. 

• Mail: U.S. Environmental 

Protection Agency, EPA West (Air 

Docket), 1200 Pennsylvania Ave., NW., 

Room B108, Mail Code 6102T, 

Washington, DC 20460, Attention 

Docket ID No. OAR–2005–0161. Please 

include a total of 2 copies. In addition, 

please mail a copy of your comments on 

the information collection provisions to 

the Office of Information and Regulatory 

Affairs, Office of Management and 

Budget (OMB), Attn: Desk Officer for 

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

20503. 

• Hand Delivery: EPA Docket Center, 

EPA/DC, EPA West, Room B102, 1301 

Constitution Ave., NW., Washington 

DC. Such deliveries are only accepted 

during the Docket’s normal hours of 

operation, and special arrangements 

should be made for deliveries of boxed 

information. 

Instructions: Direct your comments to 

Docket ID No. EPA–OAR–2005–0161. 

EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through www.regulations.gov 

or e-mail. The www.regulations.gov Web 

site is an ‘‘anonymous access’’ system, 

which means EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an e-mail 

comment directly to EPA without going 

through www.regulations.gov your email address will be automatically 

captured and included as part of the 

comment that is placed in the public 

docket and made available on the 

Internet. If you submit an electronic 

comment, EPA recommends that you 

include your name and other contact 

information in the body of your 

comment and with any disk or CD–ROM 

you submit. If EPA cannot read your 

comment due to technical difficulties 

and cannot contact you for clarification, 

EPA may not be able to consider your 

comment. Electronic files should avoid 

the use of special characters, any form 

of encryption, and be free of any defects 

or viruses. 

Docket: All documents in the docket 

are listed in the www.regulations.gov 

index. Although listed in the index, 

some information is not publicly 

available, e.g., CBI or other information 

whose disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, will be publicly 

available only in hard copy. Publicly 

available docket materials are available 

either electronically in 

www.regulations.gov or in hard copy at 

the EPA Docket Center, EPA/DC, EPA 

West, Room B102, 1301 Constitution 

Ave., NW., Washington, DC. This 

Docket Facility is open from 8:30 a.m. 

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

excluding legal holidays. The Docket 

telephone number is (202) 566–1742. 

The telephone number for the Public 

Reading Room is (202) 566–1744. 

Note: The EPA Docket Center suffered 

damage due to flooding during the last week 

of June 2006. The Docket Center is 

continuing to operate. However, during the 

cleanup, there will be temporary changes to 

Docket Center telephone numbers, addresses, 

and hours of operation for people who wish 

to make hand deliveries or visit the Public 

Reading Room to view documents. Consult 

EPA’s Federal Register notice at 71 FR 38147 

(July 5, 2006) or the EPA Web site at 

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

for current information on docket operations, 

locations and telephone numbers. The 

Docket Center’s mailing address for U.S. mail 

and the procedure for submitting comments 

to www.regulations.gov are not affected by 

the flooding and will remain the same. 

Hearing: The hearing will be held at 

10 a.m. (Central) on October 13, 2006 at 

the Sheraton Gateway Suites Chicago 

O’Hare, 6501 North Mannheim Road, 

Rosemont, Illinois 60018. To request to 

speak at a public hearing, send a request 

to the contact in FOR FURTHER

INFORMATION CONTACT. 

FOR FURTHER INFORMATION CONTACT: Julia 

MacAllister, U.S. EPA, National Vehicle 

and Fuel Emissions Laboratory, 2000 

Traverwood, Ann Arbor, MI 48105; 

Telephone (734) 214–4131, FAX (734) 

214–4816, E-mail 

macallister.julia@epa.gov. 

SUPPLEMENTARY INFORMATION: 

I. General Information 

A. Does This Action Apply to Me? 

Entities potentially affected by this 

proposed action include those involved 


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with the production, distribution and 

sale of gasoline motor fuel or renewable 

fuels such as ethanol and biodiesel. 

Regulated categories and entities could 

include: 

Category 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 provides a guide for 

readers regarding entities likely to be 

regulated by this action. This table lists 

the types of entities that EPA is now 

aware could potentially be affected by 

this proposed action. Other types of 

entities not listed in the table could also 

be affected. To decide whether your 

organization might be affected if this 

proposed action is finalized, you should 

carefully examine today’s notice and the 

existing regulations in 40 CFR part 80. 

If you have any questions regarding the 

applicability of this action to a 

particular entity, consult the persons 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section. 

B. What Should I Consider as I Prepare 

my Comments for EPA? 

1. Submitting CBI. Do not submit this 

information to EPA through 

www.regulations.gov or e-mail. Clearly 

mark the part or all of the information 

that you claim to be CBI. For CBI 

information in a disk or CD ROM that 

you mail to EPA, mark the outside of the 

disk or CD ROM as CBI and then 

identify electronically within the disk or 

CD ROM the specific information that is 

claimed as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, a 

copy of the comment that does not 

contain the information claimed as CBI 

must be submitted for inclusion in the 

public docket. Information so marked 

will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. 

2. Tips for Preparing Your Comments. 

When submitting comments, remember 

to: 

• Identify the rulemaking by docket 

number and other identifying 

information (subject heading, Federal 

Register date and page number). 

• Follow directions—The agency may 

ask you to respond to specific questions 

or organize comments by referencing a 

Code of Federal Regulations (CFR) part 

or section number. 

• Explain why you agree or disagree; 

suggest alternatives and substitute 

language for your requested changes. 

• Describe any assumptions and 

provide any technical information and/ 

or data that you used. 

• If you estimate potential costs or 

burdens, explain how you arrived at 

your estimate in sufficient detail to 

allow for it to be reproduced. 

• Provide specific examples to 

illustrate your concerns, and suggest 

alternatives. 

• Explain your views as clearly as 

possible, avoiding the use of profanity 

or personal threats. 

• Make sure to submit your 

comments by the comment period 

deadline identified. 

3. Docket Copying Costs. A reasonable 

fee may be charged by EPA for copying 

docket materials, as provided in 40 CFR 

part 2. 

Table of Contents 

I. Background 

A. The Role of Renewable Fuels in the 

Transportation Sector 

B. Requirements in the Energy Policy Act 

C. Default Standard Applicable to 2006 

D. Development of the Proposal 

II. Overview of the Proposal 

A. Impacts of Increased Reliance on 

Renewable Fuels 

1. Renewable Fuel Volumes Scenarios 

Analyzed 

2. Emissions 

3. Economic Impacts 

4. Greenhouse Gases and Fossil Fuel 

Consumption 

5. Potential Water Quality Impacts 

B. Program Structure 

1. What is the RFS Program Standard? 

2. Who Must Meet the Standard? 

3. What Qualifies as a Renewable Fuel? 

4. Equivalence Values of Different 

Renewable Fuels 

5. How Will Compliance Be Determined? 

6. How Would the Trading Program Work? 

7. How Would the Program Be Enforced? 

C. Voluntary Labeling Program 

III. Complying With the Renewable Fuel 

Standard 

A. What Is the Standard That Must Be Met? 

1. How Is the Percentage Standard 

Calculated? 

2. What are the Applicable Standards? 

3. Compliance in 2007 

4. Renewable Volume Obligations 

B. What Counts as a Renewable Fuel in the 

RFS Program? 

1. What Is a Renewable Fuel That Can Be 

Used for Compliance? 

a. Ethanol Made From a Cellulosic 

Feedstock 

b. Ethanol Made From Any Feedstock in 

Facilities Run Mostly With BiomassBased Fuel 

c. Ethanol That Is Made From the NonCellulosic Portions of Animal, Other 

Waste, and Municipal Waste 

2. What Is Biodiesel? 

a. Biodiesel (Mono-Alkyl Esters) 

b. Non-Ester Renewable Diesel 

3. Is Motor Fuel That is Made From a 

Renewable Feedstock a Renewable Fuel? 

4. What Are ‘‘Equivalence Values’’ for 

Renewable Fuel? 

a. Authority Under the Act To Establish 

Equivalence Values 

b. Energy Content and Renewable Content 

as the Basis for Equivalence Values 

c. Lifecycle Analyses as the Basis for 

Equivalence Values 

C. What Gasoline Is Used To Calculate the 

Renewable Fuel Obligation and Who Is 

Required To Meet the Obligation? 

1. What Gasoline Is Used To Calculate the 

Volume of Renewable Fuel Required To 

Meet a Party’s Obligation? 

2. Who Is Required to Meet the Renewable 

Fuels Obligation? 

3. What Exemptions Are Available Under 

the RFS Program? 

a. Small Refinery and Small Refiner 

Exemption 

b. General Hardship Exemption 

c. Temporary Exemption Based on 

Unforeseen Circumstances 

4. What Are the Opt-in and State Waiver 

Provisions Under the RFS Program? 

a. Opt-in Provisions for Noncontiguous 

States and Territories 

b. State Waiver Provisions 

D. How Do Obligated Parties Comply With 

the Standard? 

1. Why Use Renewable Identification 

Numbers? 

a. RINs Serve the Purpose of a Credit 

Trading Program 


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b. Alternative Approach to Tracking 

Batches 

2. Generating RINs and Assigning Them to 

Batches 

a. Form of Renewable Identification 

Numbers 

b. Generating Extra-Value RINs 

c. Cases in Which RINs Are Not Generated 

3. Calculating and Reporting Compliance 

a. Using RINs To Meet the Standard 

b. Valid Life of RINs 

c. Cap on RIN Use To Address Rollover 

d. Deficit Carryovers 

4. Provisions for Exporters of Renewable 

Fuel 

5. How Would the Agency Verify 

Compliance? 

E. How Are RINs Distributed and Traded? 

1. Distribution of RINs With Batches of 

Renewable Fuel 

a. Responsibilities of Renewable Fuel 

Producers and Importers 

b. Responsibilities of Parties That Buy, 

Sell, or Handle Renewable Fuels 

i. Batch Splits 

ii. Batch Mergers 

2. Separation of RINs From Batches 

3. Distribution of Separated RINs 

4. Alternative Approaches to RIN 

Distribution 

a. Producer With Direct Transfer of RINs 

b. Producer With Open RIN Market 

c. First Purchaser 

d. Owner at Time of Blending 

e. Blender at Time of Blending 

IV. Registration, Recordkeeping, and 

Reporting Requirements 

A. Introduction 

B. Requirements for Obligated Parties and 

Exporters of Renewable Fuels 

1. Registration 

2. Reporting 

3. Recordkeeping 

C. Requirements for Producers and 

Importers of Renewable Fuel 

1. Registration 

2. Reporting 

3. Recordkeeping 

D. Requirements for Other Parties Who 

Own RINs 

1. Registration 

2. Reporting 

3. Recordkeeping 

V. What Acts Are Prohibited and Who Is 

Liable for Violations? 

VI. Current and Projected Renewable Fuel 

Production and Use 

A. Overview of U.S. Ethanol Industry and 

Future Production/Consumption 

1. Current Ethanol Production 

2. Expected Growth in Ethanol Production 

3. Current Ethanol and MTBE 

Consumption 

4. Expected Growth in Ethanol 

Consumption 

B. Overview of Biodiesel Industry and 

Future Production/Consumption 

1. Characterization of U.S. Biodiesel 

Production/Consumption 

2. Expected Growth in U.S. Biodiesel 

Production/Consumption 

C. Feasibility of the RFS Program Volume 

Obligations 

1. Production Capacity of Ethanol and 

Biodiesel 

2. Production Capacity of Cellulosic 

Ethanol 

3. Renewable Fuel Distribution System 

Capability 

VII. Impacts on Cost of Renewable Fuels and 

Gasoline 

A. Renewable Fuel Production and 

Blending Costs 

1. Ethanol Production Costs 

a. Corn Ethanol 

b. Cellulosic Ethanol 

c. Ethanol’s Blending Cost 

2. Biodiesel Production Costs 

3. Diesel Fuel Costs 

B. Distribution Costs 

1. Ethanol Distribution Costs 

a. Capital Costs To Upgrade Distribution 

System for Increased Ethanol Volume 

b. Ethanol Freight Costs 

2. Biodiesel Distribution Costs 

C. Estimated Costs to Gasoline 

1. RVP Cost for Blending Ethanol Into 

Summertime RFG 

2. Cost Savings for Phasing Out Methyl 

Tertiary Butyl Ether (MTBE) 

3. Production of Alkylate From MTBE 

Feedstocks 

4. Changes in Refinery Produced Gasoline 

Volume and Its Costs 

5. Overall Impact on Fuel Cost 

a. Cost Without Ethanol Subsidies 

b. Gasoline Costs Including Ethanol 

Consumption Tax Subsidies 

c. Cost Sensitivity Case Assuming $70 per 

Barrel Crude Oil 

VIII. What Are the Impacts of Increased 

Ethanol Use on Emissions and Air 

Quality? 

A. Effect of Renewable Fuel Use on 

Emissions 

1. Emissions From Gasoline Fueled Motor 

Vehicles and Equipment 

a. Gasoline Fuel Quality 

b. Emissions From Motor Vehicles 

c. Nonroad Equipment 

2. Diesel Fuel Quality: Biodiesel 

3. Renewable Fuel Production and 

Distribution 

B. Impact on Emission Inventories 

1. Primary Analysis 

2. Sensitivity Analysis 

3. Local and Regional VOC and NOX

Emission Impacts in July 

C. Impact on Air Quality 

1. Impact of 7.2 Billion Gallon Ethanol Use 

on Ozone 

2. Particulate Matter 

IX. Impacts on Fossil Fuel Consumption and 

Related Implications 

A. Lifecycle Modeling 

1. Modifications to GREET Assumptions 

a. Wet-Mill Versus Dry Mill Ethanol Plants 

b. Coal Versus Natural Gas in Ethanol 

Plants 

c. Ethanol Production Yield 

2. Controversy Concerning the Ethanol 

Energy Balance 

B. Overview of Methodology 

1. Amount of Conventional Fuel Replaced 

By Renewable Fuel (R) 

2. Lifecycle Impacts of Conventional Fuel 

Use (LC) 

3. Displacement Indexes (DI) 

C. Impacts of Increased Renewable Fuel 

Use 

1. Fossil Fuels and Petroleum 

2. Greenhouse Gases and Carbon Dioxide 

D. Implications of Reduced Imports of 

Petroleum Products 

X. Agricultural Sector Economic Impacts 

XI. Public Participation 

XII. Administrative Requirements 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

1. Overview 

2. Background—Small Refiners Versus 

Small Refineries 

3. Summary of Potentially Affected Small 

Entities 

4. Impact of the Regulations on Small 

Entities 

5. Small Refiner Outreach 

6. Conclusions 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer 

Advancement Act 

XIII. Statutory Authority 

I. Background 

This section describes the required 

elements of the renewable fuel program, 

also known as the Renewable Fuel 

Standard (RFS) program, as stipulated 

in Section 211(o) of the Clean Air Act 

(CAA) as amended by the Energy Policy 

Act of 2005 (the Energy Act or the Act). 

A. The Role of Renewable Fuels in the 

Transportation Sector 

Renewable fuels have been an 

important part of our nation’s 

transportation fuel supply for many 

years. Following the CAA amendments 

of 1990, the use of renewables fuels, 

particularly ethanol, increased 

dramatically. Several key clean fuel 

programs required by the CAA 

established new market opportunities 

for ethanol. A very successful mobile 

source control strategy, the reformulated 

gasoline (RFG) program, was 

implemented in 1995. This program set 

stringent new controls on the emissions 

performance of gasoline, which were 

designed to significantly reduce 

summertime ozone precursors and year 

round air toxics emissions. The RFG 

program also required that RFG meet an 

oxygen content standard. Several areas 

of the country began blending ethanol 

into gasoline to help meet this new 

standard, such as Chicago and St. Louis. 

Another successful clean fuel strategy 

required certain areas exceeding the 

national ambient air quality standard for 

carbon monoxide to also meet an 

oxygen content standard during the 

winter time to reduce harmful carbon 


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monoxide emissions. Many of these 

areas also blended ethanol during the 

winter months to help meet this new 

standard, such as Denver and Phoenix. 

As a result of these programs, and other 

factors, currently all areas requiring RFG 

or winter oxygenated fuels are blending 

ethanol at some level to support meeting 

the clean fuel requirements. 

Today, the role and importance of 

renewable fuels in the transportation 

sector continues to expand. In the past 

several years as crude oil prices have 

soared above the lower levels of the 

1990’s, the relative economics of 

renewable fuel use has improved 

dramatically. In addition, since the vast 

majority of crude oil produced in or 

imported into the U.S. is consumed as 

gasoline or diesel fuel in the U.S., 

concerns about our dependence on 

foreign sources of crude oil has renewed 

interest in renewable transportation 

fuels. The passage of the Energy Policy 

Act of 2005 demonstrated a strong 

commitment on the part of U.S. 

policymakers to consider additional 

means of supporting renewable fuels as 

a supplement to petroleum-based fuels 

in the transportation sector. The RFS 

program is such a program. 

The RFS program was debated by the 

U.S. Congress over several years before 

finally being enacted through passage of 

the Energy Policy Act of 2005. The RFS 

program is first and foremost designed 

to increase the use of renewable fuels in 

motor vehicle fuels consumed in the 

U.S. In this context, it is expected to 

simultaneously reduce dependence on 

foreign sources of petroleum, increase 

domestic sources of energy, and 

diversify our energy portfolio to help in 

moving beyond a petroleum-based 

economy. 

The increased use of renewable fuels 

such as ethanol and biodiesel is also 

expected to have the added benefit of 

providing an expanded market for 

agricultural products such as corn and 

soybeans. Based on our analysis, there 

is also an expectation that the expanded 

use of renewable fuels will provide 

reductions in carbon dioxide emissions 

and air toxics emissions such as 

benzene from the transportation sector, 

while other emissions such as 

hydrocarbons and oxides of nitrogen 

may increase. 

The level of the renewable fuels 

standard set forth by Congress works in 

conjunction with other provisions that 

were enacted as part of the Energy Act. 

In particular, the level of the renewable 

fuel standard more than offset the 

possible loss in demand for renewable 

fuels occasioned by the Act’s repeal of 

the oxygen content mandate in the 

reformulated gasoline program while 

allowing greater flexibility in how 

renewable fuels were blended into the 

nation’s fuel supply. The renewable fuel 

standard additionally created a specific 

annual level for minimum renewable 

fuel use which increases over time, 

ensuring overall growth in the demand 

and opportunity for renewable fuels. 

Because renewable fuels such as 

ethanol and biodiesel are not new to the 

U.S. transportation sector, the 

expansion of their use is expected to 

follow distribution and blending 

practices already in place. For instance, 

the market already has the necessary 

production and distribution 

mechanisms in place in many areas, and 

the ability to expand these mechanisms 

into new markets. Recent spikes in 

ethanol use resulting first from the state 

MTBE bans, and now the virtual 

elimination of MTBE from the 

marketplace, have tested the limits of 

the ethanol distribution system. 

However, future growth is expected to 

move in a more orderly fashion since 

the use of renewable fuels will not be 

geographically constrained and, given 

EIA volume projections, investment 

decisions can follow market forces 

rather than regulatory mandates. In 

addition, the increased production 

volumes of ethanol and the expanded 

penetration of ethanol in new markets 

may create new opportunities for 

blending of E85, a blend of 85 percent 

ethanol and 15 percent gasoline, in the 

long run. The increased availability of 

E85 will mean that more flexible fueled 

vehicles (FFV) can use this fuel. Of the 

approximately 5 million FFVs currently 

in use in the U.S, most are currently 

fueled with conventional gasoline rather 

than E85, in part due to the limited 

availability of E85. 

Given the ever-increasing demand for 

petroleum-based products in the 

transportation sector, the RFS program 

is an important first step in U.S. efforts 

to move toward energy independence. 

The RFS standard provides the certainty 

that at least a minimum amount of 

renewable fuel will be used in the U.S., 

which in turn provides investment 

certainty for the growth in production 

capacity of renewable fuels. However, 

the RFS program is not the only thing 

impacting demand for ethanol and other 

renewable fuels. As Congress was 

developing the RFS program in the 

Energy Act, several large states were 

adopting and implementing bans on the 

use of MTBE in gasoline. As a result, 

refiners were forced to switch to ethanol 

to satisfy the oxygen content mandate 

for their reformulated gasoline in the 

U.S., causing a large, quick increase in 

demand for ethanol. Even more 

importantly, with the removal of the 

oxygen content mandate for RFG, 

refiners elected to remove essentially all 

MTBE from the gasoline supply in the 

U.S. during the spring of 2006. In order 

to accomplish this transition quickly, 

while still maintaining gasoline volume, 

octane, and gasoline air toxics 

performance standards, refiners elected 

to blend ethanol into virtually all 

reformulated gasoline nationwide. This 

caused a second dramatic increase in 

demand for ethanol, which in the near 

term has been met by temporarily 

shifting large volumes of ethanol out of 

conventional gasoline and into the RFG 

areas. Perhaps the largest impact on 

renewable fuel demand, however, has 

been the dramatic increase in the cost of 

crude oil. In the last few years, both 

crude oil prices and crude oil price 

forecasts have increased dramatically. 

This has resulted in a large economic 

incentive for the use of ethanol and 

biodiesel. The Energy Information 

Administration (EIA) and others are 

currently projecting renewable fuel 

demand to exceed the minimum 

volumes required under the RFS 

program by a substantial margin. In this 

context, the statutory goal of the RFS 

program is to provide an important 

foundation for ongoing investment in 

renewable fuel production. However, 

market demand for renewable fuels is 

expected to exceed the statutory 

minimums. We believe we are 

proposing a program structure that 

could continue to operate effectively 

regardless of the level of renewable fuel 

use or market conditions in the energy 

sector. 

B. Requirements in the Energy Policy 

Act 

Section 1501 of the Energy Policy Act 

provides the statutory basis for the RFS 

program. This provision was added to 

the CAA as Section 211(o). It requires 

EPA to establish a program to ensure 

that the pool of gasoline sold in the 

contiguous 48 states contains specific 

volumes of renewable fuel for each 

calendar year starting with 2006. The 

required overall volumes for 2006 

through 2012 are shown in Table I.B–1 

below. 

TABLE I.B–1.—APPLICABLE VOLUMES

OF RENEWABLE FUEL UNDER THE

RFS PROGRAM

Calendar year Billion gallons 

2006 ...................................... 4.0 

2007 ...................................... 4.7 

2008 ...................................... 5.4 

2009 ...................................... 6.1 

2010 ...................................... 6.8 

2011 ...................................... 7.4 


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1The default standard of 2.78 percent represented 

approximately 4.0 billion gallons of renewable fuel. 2 70 FR 77325 (December 30, 2005). 

TABLE I.B–1.—APPLICABLE VOLUMES

OF RENEWABLE FUEL UNDER THE

RFS PROGRAM—Continued 

Calendar year Billion gallons 

2012 ...................................... 7.5 

In order to ensure the use of the total 

renewable fuel volume specified for 

each year, the Agency must set a 

standard for each year representing the 

amount of renewable fuel that a refiner, 

blender, or importer must use, 

expressed as a percentage of gasoline 

sold or introduced into commerce. This 

yearly percentage standard is to be set 

at a level that will ensure that the total 

renewable fuel volumes shown in Table 

I.B–1 will be used based on gasoline 

volume projections provided by the 

Energy Information Administration 

(EIA). The standard for each year must 

be published in the Federal Register by 

November 30 of the previous year. 

Starting with 2013, EPA is required to 

establish the applicable national 

volume, based on the criteria contained 

in the statute, which must require at 

least the same overall percentage of 

renewable fuel use as was required in 

2012. 

Renewable fuels are defined in the 

Act primarily on the basis of the 

feedstock. In general, renewable fuels 

must be a motor vehicle fuel that is 

produced from plant or animal products 

or wastes, as opposed to fossil fuel 

sources. The Act specifically identifies 

several types of motor vehicle fuels as 

renewable fuels, including cellulosic 

biomass ethanol, waste-derived ethanol, 

biogas, biodiesel, and blending 

components derived from renewable 

fuel. 

The standard set annually by EPA is 

to be a single percentage applicable to 

refiners, blenders, and importers, as 

appropriate. The percentage standard is 

used by obligated parties to determine a 

volume of renewable fuel that they are 

responsible for ensuring is introduced 

into the domestic gasoline pool for the 

given year. The percentage standard 

must be adjusted such that it does not 

apply to multiple parties for the same 

volume of gasoline. The standard must 

also take into account the fact that small 

refineries are exempted from the 

program until 2011, but must take into 

account the use of renewable fuel by 

those small refineries. 

Under the Act, the required volumes 

in Table I.B–1 apply to the contiguous 

48 states. However, Alaska and Hawaii 

can opt into the program, in which case 

the pool of gasoline used to calculate 

the standard, and the number of 

regulated parties, would change. In 

addition, other states can request a 

waiver of the RFS program under 

certain conditions, which would affect 

the national quantity of renewable fuel 

required under the program. 

The Act requires the Agency to 

promulgate a credit trading program for 

the RFS program whereby an obligated 

party may generate credits for over 

complying with their annual obligation. 

The obligated party can then use these 

credits or trade them for use by another 

obligated party. Thus the credit trading 

program allows obligated parties to 

comply in the most cost-effective 

manner by permitting them to generate, 

transfer, and use credits. The trading 

program also permits renewable fuels 

that are not blended into gasoline, such 

as biodiesel, to participate in the RFS 

program. 

The Agency must also determine who 

can generate credits and under what 

conditions, how credits may be 

transferred from one party to another, 

and in certain cases the appropriate 

value of credits for different types of 

renewable fuel. If a party is not able to 

generate or purchase sufficient credits to 

meet their annual obligation, they are 

allowed to carry over the deficit to the 

next annual compliance period, but 

must achieve full compliance in that 

following year. 

C. Default Standard Applicable to 2006 

The Energy Act was enacted in 

August of 2005 and included provisions 

for a renewable fuel program that was to 

begin in January of 2006. We recognized 

that a rulemaking implementing the full 

RFS program, including both program 

design and the various analyses 

necessary, would require a substantial 

effort involving many stakeholders. This 

process was expected to take longer 

than one year, and as a result we knew 

it would not be completed in time to be 

implemented by January of 2006. 

The Energy Act anticipated this 

possibility and specified a default 

standard applicable for just 2006. The 

default standard specified that the 

percentage of renewable fuel in gasoline 

sold or dispensed to consumers in the 

U.S. in calendar year 2006 must be 2.78 

volume percent.1 The default standard 

would be applicable if the Agency did 

not promulgate regulations to 

implement the full RFS program for 

2006. Since the full program could not 

be promulgated during 2006, the default 

standard of 2.78 percent applies to 

calendar year 2006. 

However, the provision for the default 

standard in the Act does not provide 

adequate specificity on how to 

implement the default standard. For 

instance, the Act’s default standard 

provision does not specify the liable 

parties and the specific nature of their 

obligation. It also does not discuss 

compliance mechanisms, reporting 

requirements, or credit generation and 

use. The resulting uncertainty 

associated with the default standard 

would have created confusion and 

risked a problematic initial 

implementation of the RFS program. 

As a result, the Agency published a 

rule on December 30, 2005 that 

interpreted and implemented the 

default provision, to provide certainty to 

parties involved in the production and 

distribution of gasoline and renewable 

fuels.2 In that action, the Agency 

clarified the default standard for 2006 

with regulations identifying the liable 

parties as refiners, importers, and 

blenders. The default standard was 

interpreted as establishing a collective 

obligation, rather than an individual 

obligation. Under this interpretation, 

refiners, blenders, and importers are 

responsible as a group for meeting the 

default 2.78 percent standard, and 

compliance with this standard is 

calculated over the pool of all gasoline 

sold to consumers. An individual 

refiner, blender, or importer is not 

responsible for meeting the 2.78 percent 

standard for the specific gasoline it 

produces. The regulations implementing 

the default standard for 2006 did not 

include any provisions for credit 

generation or trading, given the 

collective nature of the obligation. 

However, any shortfall in renewable 

fuel production in 2006 would be added 

as a deficit carryover to the standard for 

2007. Based on information available to 

date, this does not appear to be 

necessary. Total ethanol production in 

the U.S. exceeded 4.0 billion gallons in 

2005 by a small margin, and several 

hundred million gallons of additional 

ethanol production capacity has come 

online in 2006. Thus it is anticipated 

that the total ethanol production volume 

and ultimate use in 2006 will be more 

than sufficient to meet the default 

standard of 2.78 percent. 

Today’s proposal outlines the full RFS 

program, covering all of the provisions 

required in the Act. It applies in 

calendar year 2007 and beyond, since 

the direct final rule described above 

addresses RFS compliance for 2006 

only. 

D. Development of the Proposal 

The RFS program was prescribed in 

section 1501 of the Act, including the 


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required total volumes, the timing of the 

obligation, the parties who are obligated 

to comply, the definition of renewable 

fuel, and the general framework for a 

credit program. As with many 

legislative actions, various aspects of the 

program require additional development 

by the Agency beyond the specifications 

in the Act. The credit trading program 

and related compliance mechanisms are 

a central aspect of the program, and the 

Agency is responsible for developing 

regulations to ensure the successful 

implementation of the RFS program, 

based on the framework spelled out in 

the statute. 

Under the RFS program the credit 

trading provisions will comprise a 

critical element of compliance. Many 

obligated parties do not have easy 

access to renewable fuels or the ability 

to blend them, and so will rely on the 

use of credits to comply. The RFS credit 

program is also unique in that the 

parties liable for meeting the standard 

(refiners, importers, and blenders of 

gasoline) are not generally the parties 

who make the renewable fuels or blend 

them into gasoline. This creates the 

need for trading mechanisms that 

ensure that the means to demonstrate 

compliance will be readily available for 

use by obligated parties. 

Given these considerations, the first 

step we took in developing the proposed 

program was to seek input and 

recommendations from the affected 

stakeholders. There were initially a 

wide range of thoughts and views on 

how to design the program. However, 

there was broad consensus that in the 

end the program should satisfy a 

number of guiding principles, including 

for example that the compliance and 

trading program should provide 

certainty to the marketplace and 

minimize cost to the consumers; that the 

program should preserve existing 

business practices for the production, 

distribution, and use of both 

conventional and renewable fuels; that 

the program should be designed to 

accommodate all qualifying renewable 

fuels; that all renewable volumes 

produced are made available to 

obligated parties for compliance; and 

finally that the Agency should have the 

ability to easily verify compliance to 

ensure that the volume obligations are 

in fact met. Over the course of several 

months, these guiding principles helped 

to move us toward today’s proposal. 

II. Overview of the Proposal 

Today’s action describes our proposed 

requirements for the RFS program, as 

well as a preliminary assessment of the 

environmental and economic impacts of 

the nation’s transition to greater use of 

renewable fuels. This section provides 

an overview of our proposal and 

renewable fuel impacts assessment. 

Sections III through V provide the 

details of the proposed structure of the 

program, while Sections VI through X 

describe our preliminary assessment of 

the impacts on emissions, air quality, 

fossil fuel use, and cost resulting from 

expanded renewable fuel use. 

A. Impacts of Increased Reliance on 

Renewable Fuels 

In a typical major rulemaking, EPA 

would conduct a full assessment of the 

economic and environmental impacts of 

the program. However, as discussed in 

Section I.A., the replacement of MTBE 

with ethanol and the extremely 

favorable economics for renewable fuels 

brought on by the rise in crude oil 

prices are causing renewable fuel use to 

far exceed the RFS requirements. This 

makes an assessment of the program of 

limited if any utility, given that it is not 

currently driving real world impacts 

and future projections by the Energy 

Information Administration indicate 

that this favorable condition will 

continue. Consequently, it is of greater 

relevance and interest to assess the 

impacts of this larger increase in 

renewable use and the related changes 

occurring to gasoline. For this reason we 

have carried out an assessment of the 

economic and environmental impacts of 

the broader changes in fuel quality 

resulting from our nation’s transition to 

greater utilization of renewable fuels, as 

opposed to an assessment of the RFS 

program itself. 

In summary, depending on the 

volume of renewable fuel assumed to be 

used in 2012 (7.5 to 9.9 billion gallons), 

we estimate that this transition to 

renewable fuels will reduce petroleum 

consumption by 2.3 to 3.9 billion 

gallons or approximately 1.0 to 1.6 

percent of the petroleum that would 

otherwise be used by the transportation 

sector. Carbon monoxide emissions 

from gasoline powered vehicles and 

equipment will be reduced by 1.3 to 3.6 

percent while emissions of benzene (a 

mobile source air toxic) will be reduced 

by 1.7 to 6.2 percent. At the same time, 

other emissions may increase. 

Nationwide, we estimate between a 

28,000 and 97,000 ton increase in VOC 

+ NOX emissions. However, the effects 

will vary significantly by region with 

some major areas like New York City, 

Chicago and Los Angeles experiencing 

no increase while other areas may see 

an increase in VOC emissions from 3 to 

5 percent and an increase in NOX

emissions from 4 to 6 percent from 

gasoline powered vehicles and 

equipment. Furthermore, the use of 

renewable fuel will reduce CO2

equivalent greenhouse gas emissions by 

9 to 14 million tons, about 0.4 to 0.6 

percent of the anticipated greenhouse 

gas emissions from the transportation 

sector in the United States in 2012. On 

average, we estimate the cost of this 

increase in renewable fuel to range from 

0.3 cents per gallon to 1 cent per gallon 

of gasoline for the nation as a whole. We 

anticipate additional impacts that we 

intend to evaluate as part of the final 

rulemaking, including changes in 

renewable fuel feedstock market prices, 

decreased imports of petroleum, and 

effects on energy security. 

To carry out our analyses, we elected 

to use 2004 as the baseline from which 

to compare the impacts of expanded 

renewable use. We chose 2004 as a 

baseline primarily due to the fact that 

all the necessary refinery production 

data, renewable production data, and 

fuel quality data was already in hand at 

the time we needed to begin the 

analysis. We did not use 2005 as a 

baseline year because 2005 may not be 

an appropriate year for comparison due 

to the extraordinary impacts of 

hurricanes Katrina and Rita on gasoline 

production and use. To assess the 

impacts of anticipated increases in 

renewable fuels, we elected to look at 

what they would be in 2012, the year 

the statutorily-mandated renewable fuel 

volumes will be fully phased in. By 

conducting the analysis in this manner, 

the impacts include not just the impact 

of expanded renewable fuel use by 

itself, but also the corresponding 

decrease in the use of MTBE, and the 

potential for oxygenates to be removed 

from RFG due to the absence of the RFG 

oxygenate mandate. Since these three 

changes are all inextricably linked and 

are occurring simultaneously in the 

marketplace, evaluating the impacts in 

this manner is appropriate. 

We evaluated the impacts of 

expanded renewable use and the 

corresponding changes to the fuel 

supply on fuel costs, consumption of 

fossil fuels, and some of the economic 

impacts on the agricultural sector. We 

also evaluated the impacts on 

emissions, including greenhouse gas 

emissions, and the corresponding 

impacts on nationwide and regional air 

quality. Our preliminary analyses are 

summarized in this section. There are a 

number of uncertainties associated with 

this preliminary assessment. The 

analyses described here will be updated 

for the final rule including additional 

investigation into these uncertainties. 


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3Advanced emission controls include closecoupled, high density catalysts and their associated 

electronic control systems for light-duty vehicles, 

and NOX adsorbers and PM traps for heavy-duty 

engines. 

1. Renewable Fuel Volumes Scenarios 

Analyzed 

As shown in Table I.B–1, the Act 

stipulates that the nationwide volumes 

of renewable fuel required under the 

RFS program must be at least 4.0 billion 

gallons in 2006 and increase to 7.5 

billion gallons in 2012. However, we 

expect that the volume of renewable 

fuel will actually exceed the required 

volumes by a significant margin. Based 

on economic modeling, EIA projects 

renewable demand in 2012 of 9.6 billion 

gallons for ethanol, and 300 million 

gallons for biodiesel using crude oil 

prices forecast at $47 per barrel. 

Therefore, in assessing the impacts of 

expanded use of renewable fuels, we 

evaluated two comparative scenarios, 

one representing the statutorily required 

minimum, and one reflecting the higher 

levels projected by EIA. Although the 

actual renewable fuel volumes produced 

in 2012 may differ from both the 

required and projected volumes, we 

believe that these two volume scenarios 

together represent a reasonable range for 

analysis purposes. 

The Act also stipulates that at least 

250 million gallons out of the total 

volume required in 2013 and beyond 

must be cellulosic biomass ethanol. 

Because we anticipate a ramp-up in 

production of cellulosic biomass 

ethanol products in the coming years, 

we have assumed that 250 million 

gallons of ethanol in 2012 will come 

from a cellulosic biomass source. Also, 

EIA has projected in their economic 

modeling a biodiesel demand in 2012 of 

300 million gallons. Thus for both the 

required and projected volume 

scenarios that we evaluated for 2012, we 

assumed these same production 

volumes for cellulosic biomass ethanol 

and biodiesel. 

As discussed above, we chose 2004 as 

our baseline. However, a direct 

comparison of the fuel quality impacts 

on emissions and air quality required 

that changes in overall fuel volume, 

fleet characterization, and other factors 

be constant. Therefore, we developed a 

reference case which represents the fuel 

volume, fleet characterization, and other 

factors expected in 2012. Fuel quality 

was maintained by simply growing 

ethanol use in equal proportion to 

growth in gasoline demand through 

2012. 

A summary of the assumed renewable 

fuel volumes for the scenarios we 

compared is shown in Table II.A.1–1. 

TABLE II.A.1.–1—RENEWABLE FUEL VOLUME SCENARIOS

[billion gallons] 

2004 Base 

case 

2012 

Reference 

case 

RFS 

required 

volume 

Projected volume 

Corn-ethanol ............................................................................................................ 3 .5 3 .9 6 .95 9 .35 

Cellulosic ethanol ..................................................................................................... 0 0 0 .25 0 .25 

Biodiesel .................................................................................................................. 0 .025 0 .028 0 .3 0 .3 

Total volume ..................................................................................................... 3 .025 3 .928 7 .5 9 .9 

2. Emissions 

We evaluated the impacts of increased 

use of ethanol and biodiesel on 

emissions and air quality in the U.S. 

relative to the 2012 reference case. For 

the nation as a whole, we estimated that 

summertime VOC and NOX emissions 

from gasoline and diesel vehicles and 

equipment would each increase by 

about 0.5 percent for the 7.5 billion 

gallon scenario, and by about 1.0 

percent for the 9.9 billion gallon 

scenario. This would be equivalent to 

between 28,000 and 97,000 tons of VOC 

+ NOX nationwide. However, the effects 

will vary by region. For instance, for 

areas in which 10 percent ethanol 

blends already predominated in 2004, 

such as New York City, Chicago, and 

Los Angeles, if they continue to use 

ethanol at the same levels there will be 

no impact. However, for conventional 

gasoline areas in which no ethanol was 

used in 2004 but which are projected to 

transition to full use of ethanol in 2012, 

we estimated that VOC and NOX

emissions from gasoline vehicles and 

equipment would increase by 3–5 

percent and 4–6 percent, respectively. 

Unlike VOC and NOX, emissions of 

CO and benzene from gasoline and 

diesel vehicles and equipment were 

estimated to decrease when the use of 

renewable fuels increased. Reductions 

in emissions of CO varied from as low 

as 1.3 percent to as high as 3.6 percent 

for the nation as a whole, depending on 

both the renewable fuel volume scenario 

and assumptions regarding the amount 

of ethanol used in reformulated versus 

conventional gasoline. Benzene 

emissions from gasoline vehicles and 

equipment were estimated to be reduced 

from 1.7 to 6.2 percent. 

We do not have sufficient data to 

predict the effect of ethanol use on 

levels of either directly emitted 

particulate matter (PM) or secondarily 

formed PM, but do expect a net 

reduction in ambient PM levels to result 

due to the secondary PM impacts as 

discussed in section VIII.C. However, 

data on direct PM emission impacts is 

available for biodiesel. We estimate that 

reductions in emissions of direct PM 

from the projected increase in the use of 

biodiesel to be about 100 tons 

nationwide, equivalent to less than 0.5 

percent of the diesel PM inventory. 

The emission impact estimates 

described above are based on the best 

available data and models. However, it 

must be highlighted that most of the fuel 

effect estimates are based on very 

limited or old data which may no longer 

be reliable in estimating the emission 

impacts on vehicles in the 2012 fleet 

with advanced emission controls. 3 As 

such, these emission estimates should 

be viewed as preliminary. EPA hopes to 

conduct significant new testing in order 

to better estimate the impact of fuel 

changes on emissions from both 

highway vehicles and nonroad 

equipment, including those fuel changes 

brought about by the use of renewable 

fuels. We hope to be able to incorporate 

the data from such additional testing 

into the analyses for other studies 

required by the Energy Act in 2008 and 

2009, and into a subsequent rule to set 

the RFS program standard for 2013 and 

later. 

We used the Ozone Response Surface 

Model (RSM) to estimate the impacts of 

increased use of ethanol on ozone levels 

for the 7.5 billion gallon use scenario 

representing the required volumes 


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4Tax subsidies were subtracted out of the cost 

estimates, but consumer behavior in the absence of 

these tax subsidies was not modeled. 

under the RFS program. We did not 

evaluate other renewable fuel volumes 

scenarios due to the limited amount of 

time available for completing this 

NPRM. The ozone RSM approximates 

the effect of VOC and NOX emissions in 

a 37-state eastern area of the U.S. Using 

this model, we projected that the 

changes in VOC and NOX emissions 

could produce a very small increase in 

ambient ozone levels. On average, ozone 

levels increased by 0.06 ppb, which 

represents less than 0.1 percent of the 

standard. Even for areas expected to 

experience a significant increase in 

ethanol use, ozone levels increased by 

only 0.1–0.2 ppb, less than 0.2 percent 

of the standard. These ozone impacts do 

not consider the reductions in CO 

emissions mentioned above, or the 

change in the types of compounds 

comprising VOC emissions. 

Directionally, both of these effects may 

mitigate these already small ozone 

increases. The ozone impacts also do 

not consider the impact of increased 

emissions from ethanol and biodiesel 

production facilities or any 

corresponding decrease in emissions 

from refineries. 

We investigated several other issues 

related to emissions and air quality that 

could affect our estimates of the impacts 

of increased use of renewable fuels. 

These are discussed in section VIII and 

in greater detail in the draft Regulatory 

Impact Analysis (DRIA). For instance, 

our current models assume that recent 

model year vehicles are insensitive to 

many fuel changes. However, a limited 

amount of new test data suggests that 

newer vehicles may be just as sensitive 

as older model year vehicles. Our 

sensitivity analysis suggests that if this 

is the case VOC emissions could 

decrease slightly while NOX would still 

increase. We also evaluated the 

emissions from the production of both 

ethanol and biodiesel fuel and 

determined that they will also increase 

with increased use of these fuels. 

Nationwide, emissions related to the 

production and distribution of ethanol 

and biodiesel fuel are expected to be of 

the same order of magnitude as the 

emission impacts related to the use of 

these fuels in vehicles. Finally, a lack of 

emission data and atmospheric 

modeling tools prevented us from 

making specific projections of the 

impact of renewable fuels on ambient 

PM levels. However, ethanol use may 

have an affect on ambient PM levels. 

Emerging science indicates that 

aromatic VOC emissions react in the 

atmosphere to form PM. Increased 

ethanol use is expected to cause a 

corresponding reduction in the aromatic 

content of gasoline, which should 

reduce aromatic VOC emissions and 

therefore potentially also impact 

atmospheric PM levels. All of these 

issues will be the subject of further 

study and analysis in the future. 

3. Economic Impacts 

As discussed in more detail in Section 

X, for the final rule we also plan to 

assess a range of economic impacts that 

could result from the expanded use of 

renewable fuels. Due to the time 

required to complete these analyses, we 

only have preliminary data for some of 

these impacts available for this 

proposal. 

In Section VII of this preamble, we 

estimate the cost of producing the extra 

volumes of renewable fuel anticipated 

through 2012. For corn ethanol, we 

estimate the per gallon cost of ethanol 

to range from $1.20 per gallon in 2012 

(2004 dollars) in the case of the 7.2 

billion gallons per year case and $1.26 

per gallon in the case of the 9.6 billion 

gallon case. These costs take into 

account the cost of the feedstock (corn), 

plant equipment and operation and the 

value of any co-products (distiller’s 

dried grain and solubles, for example). 

For biodiesel, we estimate the per gallon 

cost to be between $1.89 and $2.11 per 

gallon if produced using soy bean oil, 

and less if using yellow grease or other 

relatively low cost or no-cost feedstocks. 

All of these fuel production costs are 

without accounting for tax subsidies for 

these renewable fuels.4 We also note 

that these costs represent the production 

cost of the fuel and not the market price. 

In recent years, the prices of ethanol and 

biodiesel have tended to track the prices 

of gasoline and diesel, in some cases 

even exceeding those prices. 

These renewable feedstocks are then 

used as blend fuels in gasoline and 

diesel. While biodiesel is typically just 

blended with petroleum diesel, 

additional efforts are sometimes 

necessary and/or economically 

advantageous at the refiner level when 

adding ethanol to gasoline. For example, 

ethanol’s high octane reduces the need 

for other octane enhancements by the 

refiner, whereas offsetting the volatility 

increase caused by ethanol may require 

removal of other highly volatile 

components. Section VII examines these 

fuel cost impacts and concludes that the 

net cost to society in 2012 in 

comparison to the reference case of the 

increased use of renewable fuels and 

their replacement of MTBE, will range 

from an estimate of 0.3 cent to 1 cent 

per gallon of gasoline. 

This fuel cost impact does not 

consider other societal benefits. For 

example, the petroleum-based fuel 

displaced by renewable fuel, largely 

produced in the United States, should 

reduce our use of imported oil and fuel. 

We estimate that 95 percent of the 

lifecycle petroleum reductions resulting 

from the use of renewable fuel will be 

met through reductions in net 

petroleum imports. In Section IX of this 

preamble we estimate the value of the 

decrease in imported petroleum at about 

$3.5 billion in 2012 for the 7.5 billion 

gallon case and $5.8 billion for the 9.6 

billion gallon case, in comparison to our 

2012 reference case. Total petroleum 

import expenditures in 2012 are 

projected to be about $698 billion. 

The above numbers only assess those 

impacts of increased production and use 

of renewable fuel that we can quantify 

at this time. The RFS program attempts 

to spur the increased use of renewable 

transportation fuels made principally 

from agricultural crops produced in the 

U.S. As a result, it is important to 

analyze the consequences of the 

transition to greater renewable fuel use 

in the U.S. agricultural sector. To 

analyze the impacts on the U.S. 

agricultural sector, EPA has selected the 

Forest and Agricultural Sector 

Optimization Model (FASOM) 

developed by Professor Bruce McCarl, 

Texas A&M University and others over 

the past thirty years. FASOM is a 

dynamic, nonlinear programming model 

of the agriculture and forestry sectors of 

the U.S. (For this analysis, we will be 

focusing upon the agriculture portion of 

the model.) The strength of this model 

is its consideration of the full direct and 

indirect impacts of a shift in production 

of an agricultural commodity. For 

example, increased ethanol use will 

increase the demand for corn. The 

model assesses not only the impacts of 

increased demand for corn on acres 

devoted to corn production but also 

where the incremental corn will be 

produced, what other crops will be 

displaced and how corn is allocated 

among competing uses. Shifts in corn 

production will likely impact the price 

of corn and other crop prices. The 

model can also estimate the impacts of 

increased renewable fuel use on animal 

feed costs, animal production, costs to 

consumers and U.S. agricultural 

exports. Similarly, FASOM can estimate 

effects on U.S. farm employment and 

income (broken down by region, and 

farm sector such as corn farmers versus 

soybean producers versus the livestock 

industry, for example). 


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55560 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

5Cellulosic ethanol is estimated to provide a 

comparable petroleum displacement as corn 

derived ethanol on a per gallon basis, though the 

impacts on total energy and greenhouse gas 

emissions differ. 

6 ‘‘USDA Agricultural Baseline Projections To 

2015,’’ February 2006, Economic Research Service. 

7For more discussion of agricultural sector 

effects, see Section IX. 

One of the effects of increased use of 

renewable fuel is that it diversifies the 

energy sources used in making 

transportation fuel. To the extent that 

diverse sources of fuel energy reduce 

the dependence on any one source, the 

risks, both financial as well as strategic, 

of potential disruption in supply or 

spike in cost of a particular energy 

source is reduced. As part of the RFS 

rulemaking, EPA is estimating the 

energy security effects of reduced oil 

use due to the expanded use of 

renewable fuel. However, these analyses 

will not be available until the final rule. 

4. Greenhouse Gases and Fossil Fuel 

Consumption 

There has been considerable interest 

in the impacts of fuel programs on 

greenhouse gases and fossil fuel 

consumption. Therefore, in this 

proposed rulemaking we have 

undertaken an analysis of the 

greenhouse gas and fossil fuel 

consumption impacts of a transition to 

greater renewable fuel use. This is the 

first analysis of its kind in a major rule, 

and as such it may guide future work in 

this area. 

As a result of the transition to greater 

renewable fuel use, some petroleumbased gasoline and diesel will be 

directly replaced by renewable fuels. 

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

be if no renewable fuels were used in 

transportation vehicles. However, a true 

measure of the impact of greater use of 

renewable fuels on petroleum use, and 

indeed on the use of all fossil fuels, 

accounts not only for the direct use and 

combustion of the finished fuel in a 

vehicle or engine, but also includes the 

petroleum use associated with 

production and transportation of that 

fuel. For instance, fossil fuels are used 

in producing and transporting 

renewable feedstocks such as plants or 

animal byproducts, in converting the 

renewable feedstocks into renewable 

fuel, and in transporting and blending 

the renewable fuels for consumption as 

motor vehicle fuel. Likewise, fossil fuels 

are used in the production and 

transportation of petroleum and its 

finished products. In order to estimate 

the true impacts of increases in 

renewable fuel use on fossil fuel use, we 

must take these steps into account. Such 

analyses are termed lifecycle analyses. 

We compared the lifecycle impacts of 

renewable fuels to the petroleum-based 

gasoline and diesel fuels that they 

replace. This analysis allowed us to 

estimate not only the overall impacts of 

renewable fuel use on petroleum use, 

but also on emissions of greenhouse 

gases such as carbon dioxide from all 

fossil fuels. Based on a comparison to 

the 2004 base fuel, we estimated that the 

increased use of renewable fuels will 

reduce petroleum consumption by about 

1.0 to 1.6 percent in the transportation 

sector in 2012. This is equivalent to 2.3–

3.9 billion gallons of petroleum in 2012. 

We also estimated that greenhouse gases 

from the transportation sector will be 

reduced by about 0.4–0.6 percent, 

equivalent to about 9–14 million tons. 

These reductions are projected to 

continue to increase in the future as 

crude oil prices are expected to 

continue to provide the stimulus for 

greater use of renewable fuels beyond 

2012. These greenhouse gas emission 

reductions are also dominated by the 

forecast that the majority of the future 

ethanol use will be produced from corn. 

If advances in cellulosic technology 

allow its use to exceed the levels 

assumed in our analysis, then even 

greater greenhouse gas reductions 

would result.5

5. Potential Water Quality Impacts 

Expansion in the use of renewable 

fuels will also have other important 

impacts which should be the focus of 

further study and evaluation. In 

particular, renewable fuels such as 

ethanol and biodiesel produced from 

agricultural feedstocks raise important 

issues with respect to the water quality 

impacts resulting from the increased 

production of corn and soybeans. Due to 

competing demand, which includes 

livestock producers, sweetener 

manufacturers, and foreign buyers 

among others, it is extremely unlikely 

that the current corn crop would be 

devoted to ethanol production. USDA’s 

Economic Research Service predicts that 

current demand for feed and exports are 

expected to stay constant or perhaps 

rise.6 Additional corn-based ethanol 

production would have to come from 

increased corn yields, increased acreage, 

and switching acreage to corn 

production from other crops like 

soybeans and cotton.7

Changes in agriculture as a result of 

increased use of renewable fuels can 

have significant adverse effects upon 

water quality, either locally or on a 

more broad basis. This has the potential 

to lead to increased runoff and delivery 

to water bodies of nutrients, pesticides 

and sediments, as well as increased 

salinity of farmland resulting from 

increased irrigation. The increased 

runoff of nutrients in turn can cause 

eutrophication of small water bodies as 

a result of localized runoff or large water 

bodies as a result of increased regional 

runoff such as currently occurs in the 

creation of the hypoxic zone in the Gulf 

of Mexico, or eutrophication in the 

Chesapeake Bay. Some lands have been 

retired (e.g., under the Farm Bill’s 

Conservation Reserve Program, or 

simply at the land-owner’s initiative) 

because those lands are highly erosive, 

steep, or adjacent to water bodies. 

Therefore, farming these lands without 

appropriate mitigation measures would 

pose a particularly great risk to water 

quality and threaten to erase some of the 

gains of the last 20 years of Farm Bill 

and Clean Water Act implementation. 

Note that there may be similar 

environmental implications in other 

countries depending on the extent that 

either imports of renewable fuels or 

exports of agricultural commodities 

such as corn are affected. 

We have not conducted an analysis 

for this proposal of the impacts on water 

quality that might result from the 

increased use of renewable fuels. 

However, this impact could present 

important public policy issues as 

renewable use expands, with 

examination required of both the 

possible benefits and detriments. 

B. Program Structure 

The RFS program proposed today 

requires refiners, importers, and 

blenders (other than oxygenate 

blenders) to show that a required 

volume of renewable fuel is used. The 

required volume is determined by 

multiplying their annual gasoline 

production by a percentage standard 

specified by EPA. Compliance is 

demonstrated through the acquisition of 

unique Renewable Identification 

Numbers (RINs) assigned by the 

producer to every batch of renewable 

fuel produced. The RIN shows that a 

certain volume of renewable fuel was 

produced. Each year, the refiners, 

blenders and importers obligated to 

meet the renewable volume requirement 

(referred to as ‘‘obligated parties’’) must 

acquire sufficient RINs to demonstrate 

compliance with their volume 

obligation. RINs can be traded in the 

same manner as the credits envisioned 

in the Act. A system of recordkeeping 

and electronic reporting for all parties 

that have RINs ensures the integrity of 

the RIN pool. This RIN-based system 

would both meet the requirements of 

the Act and provide several other 

important advantages: 


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• Renewable fuel production volumes 

can be easily verified. 

• RIN trading can occur in real time 

as soon as the renewable fuel is 

produced rather than waiting to the end 

of the year when an obligated party 

would determine if it had exceeded the 

standard. 

• Renewable fuel can continue to be 

produced, distributed, and blended in 

those markets where it is most 

economical to do so. 

• Instances of double-counting of 

renewable fuel claimed for compliance 

purposes can be identified based on 

electronically reported data. 

Our proposed RIN-based trading 

program will be an essential component 

of the RFS program, ensuring that every 

obligated party can comply with the 

standard while providing the flexibility 

for each obligated party to use 

renewable fuel in the most economical 

ways possible. 

1. What Is the RFS Program Standard? 

EPA is required to convert the 

aggregate national volumes of renewable 

fuel specified in the Act into 

corresponding renewable fuel standards 

expressed as a percent of gasoline 

production. The renewable volume 

obligation that would apply to an 

obligated party would then be 

determined based on this percentage 

and the total gasoline production or 

import volume in a calendar year, 

January 1 through December 31. EPA 

will publish the percentage standard in 

the Federal Register each November for 

the following year based on the most 

recent EIA gasoline demand projections. 

However, since this rulemaking will not 

be finalized prior to November, 2006, 

we are proposing in this notice that the 

standard for 2007 be 3.71 percent. 

Section III.A describes the calculation of 

the standard. 

2. Who Must Meet the Standard? 

Under our proposal, any party that 

produces gasoline for consumption in 

the U.S., including refiners, importers, 

and blenders (other than oxygenate 

blenders), would be subject to a 

renewable volume obligation that is 

based on the renewable fuel standard. 

These obligated parties would 

determine the level of their obligation 

by multiplying the percentage standard 

by their annual gasoline production 

volume. The result would be the 

renewable fuel volume which each 

party must ensure is blended into 

gasoline consumed in the U.S., with 

credit for certain other renewable fuels 

that are not blended into gasoline. EPA 

will publish the percentage standard for 

a year by November of the preceding 

year. 

For 2007, we are proposing that the 

renewable fuel volume obligation be 

etermined by multiplying the 

percentage standard by the volume of 

gasoline produced or imported 

prospectively from the effective date of 

the final rule until December 31, 2007. 

As discussed in Section III.A.3, we 

considered and are seeking comment on 

several other approaches for compliance 

in 2007, but believe this approach is 

most appropriate given the 

circumstances. We are also confident 

that the total volume of renewable fuel 

used in 2007 will still exceed the 

volume specified in the Act. 

In determining their annual gasoline 

production volume, obligated parties 

would include all of the finished 

gasoline which they produced or 

imported for use in the contiguous 48 

states, and would also include 

renewable blendstock for oxygenate 

blending (RBOB), and conventional 

blendstock for oxygenate blending 

(CBOB). Blenders would count as their 

gasoline production only the volumes of 

blendstocks added to finished or 

unfinished gasoline. Renewable fuels 

blended into gasoline by any party 

would not be counted as gasoline for the 

purposes of calculating the annual 

gasoline production volume. 

Small refiners and small refineries 

would be exempt from meeting the 

renewable fuel requirements through 

2010. All gasoline producers located in 

Alaska, Hawaii, and noncontiguous U.S. 

territories would be exempt indefinitely. 

However, if Alaska, Hawaii or a 

noncontiguous territory opted into the 

RFS program, all of the refiners (except 

for small refiners and refineries), 

importers, and blenders located in the 

state would be subject to the renewable 

fuel standard. 

Section III.A provides more details on 

the standard that must be met, while 

Section III.C describes the parties that 

are obligated to meet the standard. 

3. What Qualifies as a Renewable Fuel? 

We have designed the proposal 

flexibly to cover the range of renewable 

fuels produced today as well as any that 

might be produced in the future, so long 

as they meet the Act’s definition of 

renewable fuel and have been registered 

and approved for use in motor vehicles. 

In this manner, we believe that the 

proposed program will provide the 

greatest possible encouragement for the 

development, production, and use of 

renewable fuels to reduce our 

dependence on petroleum. In general, 

renewable fuels must be produced from 

plant or animal products or wastes, as 

opposed to fossil fuel sources. Valid 

renewable fuels would include ethanol 

made from starch seeds, sugar, or 

cellulosic materials, biodiesel (monoalkyl esters), non-ester renewable diesel, 

and a variety of other products. Both 

renewable fuels blended into 

conventional gasoline or diesel and 

those used in their neat (unblended) 

form as motor vehicle fuel would 

qualify. Section III.B provides more 

details on the renewable fuels that 

would be allowed to be used for 

compliance with the standard under our 

proposal. 

4. Equivalence Values of Different 

Renewable Fuels 

One question that EPA faced in 

developing the program was what value 

to place on different renewable fuels 

and on what basis should that value be 

determined. The Act specifies that each 

gallon of cellulosic ethanol be treated as 

if it were 2.5 gallons of renewable fuel, 

but does not specify the values for other 

renewable fuels. As discussed in 

Section III.B.4., we considered and are 

seeking comment on a range of options 

including straight volume, energy 

content, and life cycle energy or 

greenhouse gas emissions. However, we 

are proposing that the ‘‘Equivalence 

Values’’ for the different renewable fuels 

be based on their energy content in 

comparison to the energy content of 

ethanol, and adjusted as necessary for 

their renewable content. The result is an 

Equivalence Value for corn ethanol of 

1.0, for biobutanol of 1.3, for biodiesel 

(mono alkyl ester) of 1.5, for non-ester 

renewable diesel of 1.7, and for 

cellulosic ethanol of 2.5. The proposed 

methodology can be used to determine 

the appropriate Equivalence Value for 

any other potential renewable fuel as 

well. 

5. How Will Compliance Be 

Determined? 

Under our proposed program, every 

gallon of renewable fuel produced or 

imported into the U.S. would be 

assigned a unique renewable 

identification number (RIN). A block of 

RINs could be assigned to any batch of 

renewable fuel that is valid for 

compliance purposes under the RFS 

program. These RINs would be placed 

on product transfer documents (PTD) as 

a batch of renewable fuel is transferred 

through the distribution system. Once 

the renewable fuel is obtained by an 

obligated party or actually blended into 

a motor vehicle fuel, the RIN could be 

separated from the batch of renewable 

fuel to which it had been assigned, and 

then either used for compliance 

purposes or traded. For excess RINs 


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resulting from the production of 

renewable fuels with Equivalence 

Values greater than 1.0, the producer of 

the renewable fuel could retain them for 

marketing separately (they need not be 

assigned to a batch of renewable fuel 

and placed on PTDs). 

RINs would represent proof of 

production which is then taken as proof 

of consumption as well, since all 

renewable fuel produced or imported 

will be either consumed as fuel or 

exported. For instance, ethanol 

produced for use as motor vehicle fuel 

is denatured specifically so that it can 

only be used as fuel. Similarly, biodiesel 

is produced only for use as fuel and has 

no other potential uses. An obligated 

party would demonstrate compliance 

with the renewable fuel standard by 

accumulating sufficient RINs to cover 

their individual renewable fuel volume 

obligation. It would not matter whether 

the obligated party used the renewable 

fuel themselves. A party’s obligation 

would be to ensure that a certain 

amount of renewable fuel was used, 

whether by themselves or by someone 

else, and the RIN would be evidence 

that this occurred for a certain volume 

of renewable fuel. Exporters of 

renewable fuel would also be required 

to retire RINs in sufficient quantities to 

cover the volume of renewable fuel 

exported. RINs claimed for compliance 

purposes would thus represent 

renewable fuel actually consumed as 

motor vehicle fuel in the U.S. 

RINs would be valid for compliance 

purposes for the calendar year in which 

they were generated, or the following 

calendar year. This approach to RIN life 

would be consistent with the Act’s 

prescription that credits be valid for 

compliance purposes for 12 months as 

of the date of generation. An obligated 

party could either use RINs to 

demonstrate compliance, or could 

transfer RINs to any other party. If an 

obligated party was not able to 

accumulate sufficient RINs for 

compliance in a given year, it could 

carry a deficit over to the next year so 

long as the full deficit and obligation 

were covered in the next year. 

In order to ensure that previous year 

RINs are not used preferentially for 

compliance purposes in a manner that 

would effectively circumvent the 

limitation that RINs be valid for only 12 

months after the year generated, we are 

proposing to place a cap on the use of 

RINs generated the previous year when 

demonstrating compliance with the 

renewable volume obligation for the 

current year. The cap would mean that 

no more than 20% of the current year 

obligation could be satisfied using RINs 

from the previous year. In this manner 

there is no ability for excess renewable 

fuel use in successive years to cause an 

accumulation of RINs from excess 

compliance in prior years to 

significantly depress renewable fuel 

demand in any future year. In keeping 

with the Act, excess RINs not used 

would expire. 

Section III.D provides more details on 

how obligated parties would use RINs 

for compliance purposes. 

6. How Would the Trading Program 

Work? 

Renewable fuel producers and 

importers would be required to generate 

RINs when they produce or import a 

batch of renewable fuel. They would 

then be required to transfer those RINs 

along with the renewable fuel batches 

that they represent whenever they 

transfer the batch to another person. 

Likewise any other party that takes 

ownership or custody of the batch 

would be required to transfer the RIN 

with the batch. The RIN could be 

separated from the batch only by 

obligated parties (at the point when they 

take ownership of the batch) or a party 

that converts the renewable fuel into 

motor vehicle fuel (such as through 

blending with conventional gasoline or 

diesel). 

Once a RIN is separated from the 

batch of renewable fuel that it 

represents, it can be used for 

compliance purposes, banked, or traded 

to another party. Separated RINs could 

be transferred to any party any number 

of times. Recordkeeping and reporting 

requirements would apply to any party 

that holds RINs, whether through the 

ownership or custody of a batch of 

renewable fuel or through the transfer of 

separated RINs. 

Thus obligated parties could acquire 

RINs directly through the purchase of 

renewable fuel with assigned RINs, or 

through the open market for RINs that 

would be allowed under this proposal. 

Section III.E provides more details on 

how our proposed RIN trading program 

would work. 

7. How Would the Program be Enforced? 

As in all EPA fuel regulations, there 

would be a system of registration, 

recordkeeping, and reporting 

requirements for obligated parties, 

renewable producers (RIN generators), 

as well as any parties that procure or 

trade RINs either as part of their 

renewable purchases or separately. In 

most cases, the recordkeeping 

requirements are not expected to be 

significantly different from what these 

parties might be doing already as a part 

of normal business practices. The lynch 

pin to the compliance program, 

however, is the unique RIN number 

itself coupled with an electronic 

reporting system where RIN generation, 

RIN use, and RIN transactions would be 

reported and verified. Thus, EPA, as 

well as industry could have confidence 

that invalid RINs are not generated and 

that there is no double counting. 

C. Voluntary Labeling Program 

EPA is considering whether voluntary 

program options to encourage adoption 

and use of practices that minimize 

environmental concerns which may 

arise with the production of renewable 

fuels are appropriate. Renewable fuels 

present a number of environmental 

advantages as explained elsewhere in 

the rulemaking package. However, to 

assure maximum advantage we also 

need to acknowledge the potential 

adverse environmental impacts that 

could arise from the production of 

renewable fuel and invite consideration 

of ways of offsetting these potential 

adverse impacts. 

While in other areas of this document 

we focus on general impacts on air 

emissions, we also recognize that 

individual farming and fuel production 

operations can contribute to air and 

water pollution if appropriate practices 

and/or controls are not adopted. 

Increased production of renewable fuel 

may result in more intensive use of crop 

lands and perhaps the addition of crop 

land acres to meet the expanding need 

for renewable feed stocks. Such trends 

could have an adverse impact on, for 

example, local water quality. Similarly 

in the case of fuel production facilities, 

a range of design and operation options 

could result in varying levels of energy 

use and air and water pollution. 

EPA is considering what voluntary 

program(s) can be put into place that 

would encourage farming and fuel 

production practices to minimize 

concerns that expanded production of 

renewable fuel in the United States is 

likely to result in adverse environmental 

impacts such as those identified above. 

One option could be a voluntary 

labeling program which would make 

use of the RIN program proposed in this 

rulemaking. Under this concept, fuel 

producers which use best practices 

would have the option of adding a ‘‘G’’

(for ‘‘green’’) to the end of the RIN of a 

fuel to indicate that a gallon of 

renewable fuel was produced with the 

combination of best farming practices, 

and environmentally friendly 

production methods and facilities. The 

details of such a concept, including the 

points noted below, would need to be 

developed before it could be fully 

considered for adoption. 


jlentini on PROD1PC65 with PROPOSAL2
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8Under the Act, small refineries are those with 

75,000 bbls/day or less average aggregate daily 

crude oil throughput. 

9Small refiners are those entities who produced 

gasoline from crude oil in 2004, and who meet the 

crude processing capability (no more than 155,000 

barrels per calendar day, bpcd) and employee (no 

more than 1500 people) criteria as specified in 

previus EPA fuel regulations. 

At this time, we are requesting 

comments on voluntary programs that 

would recognize the efforts of farmers 

and renewable fuel producers that 

undertake the most environmentally 

sound practices and encourage others to 

adopt similar practices. In particular we 

are interested in comments on options 

for designs of potential voluntary 

programs including what criteria should 

be used to establish environmentally 

sound practices, how to verify that these 

environmental practices are indeed used 

in the production of renewable fuel, 

how this information could be used to 

promote expanded use of good 

practices, how the program could be 

most efficiently and effectively 

administered whether by EPA, some 

other Federal agencies, or perhaps a 

third-party, and finally how to assess 

effectiveness of such a voluntary 

program. 

III. Complying With the Renewable 

Fuel Standard 

According to the Energy Act, the RFS 

program places obligations on 

individual parties such that the 

renewable fuel volumes shown in Table 

I.B–1 are actually used as motor vehicle 

fuel in the U.S. each year. To 

accomplish this, the Agency must 

calculate and publish a standard by 

November 30 of each year which is 

applicable to every obligated party. On 

the basis of this standard each obligated 

party determines the volume of 

renewable fuel that it must ensure is 

consumed as motor vehicle fuel. In 

addition to setting the standard, we 

must clarify who the obligated parties 

are and what volumes of gasoline are 

subject to the standard. Obligated 

parties must also know which 

renewable fuels are valid for RFS 

compliance purposes, and how much 

credit each type of renewable fuel will 

receive. This section discusses how the 

annual standard is determined and 

which parties and volumes of gasoline 

would be subject to the proposed 

requirements. 

Because renewable fuels are not 

produced or distributed evenly around 

the country, some obligated parties will 

have easier access to renewable fuels 

than others. As a result, compliance 

with the RFS program requirements will 

depend heavily on a credit trading 

program. This section also describes all 

the elements of our proposed credit 

trading program. 

A. What Is the Standard That Must Be 

Met? 

1. How Is the Percentage Standard 

Calculated? 

Table I.B–1 shows the required total 

volume of renewable fuel specified in 

the Act for 2007 through 2012. The 

renewable fuel standard is based 

primarily on (1) the 48-state gasoline 

consumption volumes projected by EIA 

as the Act exempts Hawaii and Alaska, 

subject to their right to opt-in, as 

discussed in Section III.C.4, and (2) the 

volume of renewable fuels required by 

the Act for the coming year. The 

renewable fuel standard will be 

expressed as a volume percentage of 

gasoline sold or introduced into 

commerce in the U.S., and would be 

used by each refiner, blender or 

importer to determine their renewable 

volume obligation. The applicable 

percentage is set so that if each 

regulated party meets the renewable 

volume obligation based on this 

percentage then the total amount of 

renewable fuel used is expected to meet 

the total renewable fuel volume 

specified in Table I.B–1. 

In determining the applicable 

percentage for a calendar year, the Act 

requires EPA to adjust the standard to 

prevent the imposition of redundant 

obligations on any person and to 

account for the use of renewable fuel 

during the previous calendar year by 

exempt small refineries, defined as 

refineries that process less than 75,000 

bpd of crude oil. As a result, in order 

to be assured that the percentage 

standard will in fact result in the 

volumes shown in Table I.B–1, several 

adjustments to what is otherwise a 

simple calculation must be made. 

As stated, the renewable fuel standard 

for a given year is basically the ratio of 

the amount of renewable fuel specified 

in the Act for that year to the projected 

48-state non-renewable gasoline volume 

for that year. While the required amount 

of total renewable fuel for a given year 

is provided by the Act, EPA is required 

to use an EIA estimate of the amount of 

gasoline that will be sold or introduced 

into commerce for that year. The level 

of the percentage standard would be 

further reduced if Alaska, Hawaii, or a 

U.S. territory chose to participate in the 

RFS program, as gasoline produced in or 

imported into those states or territories 

would then be subject to the standard. 

Should any of these states or territories 

choose to opt into the RFS program, the 

projected gasoline volume would 

increase above that consumed in the 48 

contiguous states. EIA has indicated that 

the best estimation of the coming year’s 

gasoline consumption is found in Table 

5a (U.S. Petroleum Supply and Demand: 

Base Case) of the October issue of the 

monthly EIA publication Short-Term 

Energy Outlook which publishes 

quarterly energy projections. Since the 

October 2006 document is not currently 

available for the purpose of proposing 

the 2007 standard and projecting the 

2008 and later standards, we have used 

the gasoline volume projections in EIA’s 

2006 Annual Energy Outlook (AEO), 

Table A2 ‘‘Energy Consumption by 

Sector and Source.’’ We intend to use 

the October 2006 Short-Term Energy 

Outlook values for the final rule. 

However, these gasoline volumes 

include renewable fuel use, which in 

the coming years is expected to be 

mostly ethanol. As discussed below in 

Section III.C.1, the renewable fuel 

obligation will not apply to renewable 

blenders. Thus, the gasoline volume 

used to determine the standard must be 

the non-renewable portion of the 

gasoline pool, in order to achieve the 

volumes of renewables specified in the 

Act. In order to get a total nonrenewable gasoline volume, the 

renewable fuel volume must be 

subtracted from the total gasoline 

volume. EIA has indicated that the best 

estimation of the coming year’s 

renewable fuel consumption is found in 

Table 11 (U.S. Renewable Energy Use by 

Sector: Base Case) of the October issue 

of the monthly EIA publication ShortTerm Energy Outlook. For the purpose 

of proposing the 2007 standard and 

projecting the 2008 and later standards, 

we have used the renewable (ethanol) 

volume projections in EIA’s 2006 

Annual Energy Outlook (AEO), Table 17 

‘‘Renewable Energy Consumption by 

Sector and Source.’’ As for the gasoline 

projections discussed above, we intend 

to use the October 2006 renewable fuel 

values for the final rule. 

The Act exempts small refineries 8

from the RFS requirements until the 

2011 compliance period. As discussed 

in Section III.C.3.a, EPA is proposing to 

also exempt small refiners 9 from the 

RFS requirements until 2011, and to 

treat small refiner gasoline volumes the 

same as small refinery gasoline 

volumes. Since small refineries and 

small refiners would be exempt from the 

program until 2011, EPA is proposing 

that their gasoline volumes be excluded 

from the overall non-renewable gasoline 


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55564 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

10 ‘‘Calculation of the Small Refiner/Small 

Refinery Fraction for the Renewable Fuel Program,’’

memo to the docket from Christine Brunner, ASD, 

OTAQ, EPA, September 2006. 

volume used to determine the 

applicable percentage. EPA believes this 

is appropriate because the percentage 

standard should be based only on the 

gasoline subject to the renewable 

volume obligation. This would only 

occur though the 2010 compliance 

period when the exemption ends. 

Calculation of the standard for calendar 

year 2011 and beyond would include 

small refinery and small refiner 

volumes. 

As discussed above, calculation of the 

standard requires projections of gasoline 

use for the upcoming compliance 

period. EIA does not project small 

refinery or small refiner gasoline 

volumes, so other methods of estimating 

these values are necessary. EPA receives 

gasoline production data as a part of its 

fuel programs’ reporting requirements 

that could be used for this purpose. 

However, since we do not receive the 

data until late February, the most recent 

complete annual data set available 

would be from two years earlier. Given 

this, the fact that this adjustment is only 

needed for 4 years, and because the total 

small refinery and small refiner gasoline 

production volume is expected to be 

fairly constant compared to total U.S. 

gasoline production during this period, 

we are proposing to estimate small 

refinery and small refiner gasoline 

volumes using a constant percentage of 

national consumption. This percentage 

would be based on the most recent 

small refinery and small refiner gasoline 

data available in time for the final rule. 

Using information from gasoline batch 

reports submitted to EPA, EIA data and 

input from the California Air Resources 

Board regarding California small 

refiners, we have estimated this 

percentage to be 13.5%.10 EPA requests 

comments on this method of estimating 

small refinery and small refiner gasoline 

volumes. 

The Act requires that the small 

refinery adjustment also account for 

renewable fuels used during the prior 

year by small refineries that are exempt 

and do not participate in the RFS 

program. Accounting for this volume of 

renewable fuel would reduce the total 

volume of renewable fuel use required, 

and thus directionally would reduce the 

percentage standard. However, there 

would be no available data on which to 

base such an adjustment. Furthermore, 

EPA believes that the amount of 

renewable fuel that would qualify (i.e., 

that was used by exempt small 

refineries and small refiners but not 

used as part of the RFS program) would 

be very small. In light of the total 

volume of renewable fuel required and 

the precision in which the statute 

specifies this total volume, the very 

small volume at issue here would not 

change the resulting percentage. Under 

the proposal, small refineries and small 

refiners are merely treated as any other 

renewable blender until 2011. 

Consequently, whatever renewables 

they blend will be reflected as RINs 

available in the market, and thus should 

not be accounted for in the equation 

used to determine the standard. 

Therefore, EPA is proposing to assume 

this value to be zero. 

We are proposing that the amount of 

renewable fuel used in Alaska, Hawaii, 

or U.S. territories would not affect the 

amount of renewable fuel required 

nationwide. We believe this approach is 

appropriate because the Act requires 

that the renewable fuel be consumed in 

the contiguous 48 states unless Alaska, 

Hawaii, or a U.S. territory opt-in. 

Additionally, renewable fuel produced 

in Alaska, Hawaii, and U.S. territories is 

unlikely to be transported to the 

contiguous 48 states, and vice versa. 

Thus, including their renewable fuel 

volumes in the calculation of the 

standard would not serve the purpose 

intended by the Act of ensuring that the 

statutorily required renewable fuel 

volumes are consumed in the 48 

contiguous States. 

A final issue that could affect the 

calculated value of the standard is any 

deficit carryover from 2006. Any deficit 

carryover from 2006 would increase the 

standard only for 2007. Since renewable 

fuel use in 2006 is expected to exceed 

the 2.78 percent default standard, we 

are proposing that no deficit be carried 

over to 2007. Beginning with the 2007 

compliance period, when annual 

individual party compliance replaces 

collective compliance, any deficit is 

calculated for an individual party and is 

included in the party’s Renewable 

Volume Obligation (RVO) 

determination, as discussed in Section 

III.A.4. 

In summary, in order to get the total 

projected non-renewable gasoline 

volumes from which to calculate the 

standard, EPA is proposing to use EIA 

projections of nationwide and state 

gasoline consumption, and small 

refinery and small refiner volumes 

estimated as a constant percentage of 

national gasoline volumes. 

Based on the discussion above, the 

formula which we are proposing to be 

used for calculating the percentage 

standard is shown below: 

RFStd RFV Cell

G R GS RS GE i

i i

ii i i i

= × −

( ) − + − ( ) − 100

Where: 

RFStdi = Renewable Fuel standard in year i, 

in percent 

RFVi = Nationwide annual volume of 

renewable fuels required by section 

211(o)(2)(B) of the Act for year i, in 

gallons 

Gi = Amount of gasoline projected to be used 

in the 48 contiguous states, in year i, in 

gallons 

Ri = Amount of renewable fuel blended into 

gasoline that is projected to be consumed 

in the 48 contiguous states, in year i, in 

gallons 

GSi = Amount of gasoline projected to be 

used in Alaska, Hawaii, or a U.S. 

territory in year i if the state or territory 

opts-in, in gallons 

RSi = Amount of renewable fuel blended into 

gasoline that is projected to be consumed 

in Alaska, Hawaii, or a U.S. territory in 

year i if the state or territory opts-in, in 

gallons 

GEi = Amount of gasoline projected to be 

produced by exempt small refineries and 

small refiners in year i, in gallons 

(through 2010 only) 

Celli = Beginning in 2013, the amount of 

renewable fuel that is required to come 

from cellulosic sources, in year i, in 

gallons (250,000,000 gallons minimum) 

As described in III.B.4.b, we are not 

proposing regulations that would 

specify the criteria under which a state 

could petition the EPA for a waiver of 

the RFS requirements, nor the 

ramifications of Agency approval of 

such a waiver in terms of the level or 

applicability of the standard. As a 

result, the proposed formula for the 

standard shown above does not include 

any components to account for Agency 

approval of a state petition for a waiver 

of the RFS requirements. 

EPA is proposing the following 

formula for calculating the cellulosic 


jlentini on PROD1PC65 with PROPOSAL2EP22SE06.000</MATH>
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55565 

11 ‘‘Calculation of the Renewable Fuel Standard,’’

memo to the docket from Christine Brunner, ASD, 

OTAQ, EPA, September 2006. 

standard that is required beginning in 

2013: 

RFCell Cell

G R GS RS i

i

ii i i

= × ( ) − + − ( ) 100

Where, except for RFCelli, the variable 

descriptions are as discussed above. The 

definition of RFCelli is proposed as: 

RFCelli = Renewable Fuel Cellulosic 

Standard in year i, in percent 

EPA requests comments on the 

components of both of the proposed 

formulas, and on how the values for the 

components should be obtained. 

2. What Are the Applicable Standards? 

EPA will set the percentage standard 

for each upcoming year based on the 

most recent EIA projections, and using 

the other sources of information as 

noted above. EPA will publish the 

standard in the Federal Register by 

November 30 of the preceding year. We 

are proposing the standard for 2007 and 

estimating the standard for later years 

based on current information using the 

formulas discussed above. The 

standards would be used to determine 

the renewable volume obligation based 

on an obligated party’s total gasoline 

production or import volume in a 

calendar year, January 1 through 

December 31. The percentage standards 

do not apply on a per gallon basis. An 

obligated party will calculate its 

Renewable Volume Obligation 

(discussed in Section III.A.4) using the 

annual standard. 

For illustrative purposes, we have 

estimated the standards for 2007 and 

later based on current information using 

the formulas discussed above.11 These 

values are listed below in Table III.A.2–

1. The values of the variable RFV are the 

required renewable fuel volumes 

specified in the Act (and shown in 

Table I.B–1). The projected gasoline and 

renewable fuels volumes were 

determined from EIA’s energy 

projections. Variables related to state or 

territory opt-ins were set to zero since 

we do not have any information related 

to their participation at this time. Small 

refinery and small refiner gasoline 

volumes were calculated based on our 

proposed method of assuming a 

constant percentage relative to projected 

nationwide gasoline. As mentioned 

earlier, we estimate the small refinery 

and small refiner fraction to be 13.5%. 

The exemption for small refineries and 

small refiners ends at the end of the 

2010 compliance period. The deficit for 

2006 (applicable to the 2007 standard) 

was assumed to be zero. 

TABLE III.A.2–1.—PROJECTED STANDARDS

Year Standard Cellulosic standard 

2007 ................................................................... 3.71% ............................................................... Not applicable. 

2008 ................................................................... 4.22% ............................................................... Not applicable. 

2009 ................................................................... 4.72% ............................................................... Not applicable. 

2010 ................................................................... 5.21% ............................................................... Not applicable. 

2011 ................................................................... 4.82% ............................................................... Not applicable. 

2012 ................................................................... 4.85% ............................................................... Not applicable. 

2013+ ................................................................. 4.70% min. (non-cellulosic) .............................. 0.16% min. 

For calendar year 2013 and thereafter, 

the applicable volumes are to be 

determined in accordance with separate 

statutory provisions that include EPA 

coordination with the Departments of 

Agriculture and Energy, and a review of 

the program during calendar years 2006 

through 2012. The Act specifies that this 

review consider the impact of the use of 

renewable fuels on the environment, air 

quality, energy security, job creation, 

and rural economic development, and 

the expected annual rate of future 

production of renewable fuels, 

including cellulosic ethanol. We intend 

to conduct another rulemaking as we 

approach the 2013 timeframe that 

would include our review of these 

factors. This rulemaking would present 

our conclusions regarding the 

appropriate applicable volume of 

renewable fuel for use in calculating the 

renewable fuel standard for 2013 and 

beyond. However, at a minimum we 

expect that the sum of the cellulosic and 

non-cellulosic standards for 2013 will 

be no lower than the 2012 standard. 

Until such time as we conduct that 

rulemaking, the program proposed by 

this rule would continue to apply after 

2012. 

Prior to 2013, the Act specifies that 

cellulosic biomass ethanol or waste 

derived ethanol will be considered 

equivalent to 2.5 gallons of renewable 

fuel when determining compliance with 

the renewable volume obligation. As 

discussed in Section III.D below, a 

batch’s RIN would indicate whether it 

was cellulosic or non-cellulosic ethanol. 

Beginning in 2013, the 2.5 to 1 ratio no 

longer applies for cellulosic biomass 

ethanol. In its place, the Act requires 

that the applicable volume of required 

renewable fuel specified in Table I.B–1 

include a minimum of 250 million 

gallons that are derived from cellulosic 

biomass. As shown in Table III.A.2–1 

above, we have estimated this value 

(250 million gallons) as a percent of an 

obligated party’s production for 2013. 

Thus, an obligated party would be 

subject to two standards in 2013 and 

beyond, a non-cellulosic standard and a 

cellulosic standard. 

3. Compliance in 2007 

The Energy Act requires that EPA 

promulgate regulations to implement 

the RFS program, and if EPA did not 

issue such regulations then a default 

standard for renewable fuel use would 

apply in 2006. As described in Section 

I.C, we promulgated a direct final rule 

to interpret and implement the 

application of the statutory default 

standard of 2.78 percent in calendar 

year 2006. However, the Act provides 

no default standard for any other year. 

Instead, the regulations we promulgate 

are required to address renewable fuel 

usage, including calendar year 2007. 

The program we are proposing today 

will therefore apply in 2007. While we 

plan to promulgate the final rule as soon 

after today’s proposal as possible, it will 

likely not be effective by January 1, 

2007. Therefore, our proposal must 

address how, and for what time periods, 

the applicable standard and other 

program requirements will apply to 

regulated parties for gasoline produced 

during 2007. 

We have identified several options for 

2007 compliance. One option would be 

to extend the collective compliance 

approach used for 2006 to 2007. 

Although the Act contains no default 


jlentini on PROD1PC65 with PROPOSAL2EP22SE06.001</MATH>
55566 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

12The statutory default standard for 2006 is the 

one exception to this, since it directly establishes 

a renewable fuel obligation applicable to refiners 

and importers in the event that EPA does 

promulgate regulations. 

standard applicable to 2007, under this 

approach we would apply the 

renewable fuel standard that we 

calculate for 2007 to obligated parties on 

a collective basis rather than on an 

individual basis. Under this approach, 

no individual facility or company 

would be liable for meeting the 

applicable standard. At the end of 2007 

we would determine if the industry as 

a whole had met the standard on 

average, and any deficit would be 

carried over into 2008. This approach 

would be essentially equivalent to 

deferring the start of the program to 

2008, but with the addition of an 

industry-wide deficit carryover 

provision. Current projections from the 

Energy Information Administration 

(EIA) on the volume of renewable fuel 

expected to be produced in 2007 

indicate that an industry-wide deficit 

carryover would most likely be 

unnecessary under this collective 

compliance approach. 

However, given the requirements of 

the Act, we do not believe that a 

collective compliance approach is 

appropriate for 2007. The Energy Act 

requires us to promulgate regulations 

that provide for the generation of credits 

by any person who overcomplies with 

their obligation. It also stipulates that a 

person who generates credits must be 

permitted to use them for compliance 

purposes, or to transfer them to another 

party. These credit provisions have 

meaning only in the context of an 

individual obligation to meet the 

applicable standard. Delaying a credit 

program until 2008 would mean the 

credit provisions have no meaning at all 

for 2007. 

A variation of the collective 

compliance approach would add a 

credit carryover provision in which any 

excess renewable fuel produced on an 

industry-wide basis in 2007 would be 

subtracted from the required volume in 

the calculation of the applicable 2008 

standard. However, under a collective 

compliance approach, such a credit 

carryover provision would not meet the 

statutory requirement since no 

individual companies could generate, 

bank, or trade credits. Therefore we do 

not believe that a collective compliance 

approach is appropriate. 

Another option for 2007 compliance 

would be for obligated parties to 

calculate their renewable fuel obligation 

based on all gasoline volumes produced 

at any time during the calendar year, 

regardless of when in 2007 the final rule 

is published or becomes effective (i.e., 

the calculation of the renewable volume 

obligation looks back retroactively to the 

beginning of the year for gasoline 

production). Compliance would be 

determined based on a whole calendar 

year’s production of gasoline, and the 

compliance determination would not be 

required until calendar year 2007 was 

over, after the final rule was published. 

Obligated parties would know the 

proposed standard based on today’s 

action, and all regulated parties would 

likewise know the proposed provisions 

for recordkeeping, RIN generation and 

assignment, etc. On this basis they 

could begin the process of generating 

RINs and tracking batches of renewable 

fuel prior to the publication of the final 

rule. However, it might not be 

appropriate to apply the standard to all 

gasoline produced in 2007 unless the 

regulatory provisions in today’s 

proposal are very similar to those in the 

final rule. Otherwise, obligated parties 

and renewable fuel producers would not 

have adequate lead-time. 

For this approach to be effective, 

renewable producers would have to 

begin placing RINs on their PTDs at the 

start of the year 2007 even though the 

regulations are not yet final. If they do 

not, then there could be a shortage of 

RINs available for obligated parties to 

use for compliance by the end of the 

year. Since there is no guarantee that 

renewable fuel producers would 

generate RINs appropriate prior to 

adoption of the regulations, another 

option would be for the Agency to 

finalize just those RIN-related 

provisions prior to the end of 2006 that 

are critical to measuring and tracking 

batches of renewable fuel and the 

assignment of RINs to those batches. 

However, in practice this approach 

would be little different than finalizing 

the full rulemaking. As a result we do 

not believe that this would be a viable 

option given the time available. 

Finally, given the challenges and 

shortcomings inherent in the other 

options, we could simply apply the 

renewable fuel standard to only those 

volumes of gasoline produced after the 

effective date of the final rule. 

Essentially the renewable volume 

obligation for 2007 would be based on 

only those volumes of gasoline 

produced or imported by an obligated 

party prospectively from the effective 

date of the rulemaking forward, and 

renewable producers would not have to 

begin generating RINs and maintaining 

the necessary records until this same 

date. As a result, such an approach 

would be relatively straightforward to 

implement, provide the industry with 

the certainty they need to comply, and 

give them time to put in place their 

compliance plans and actions. It also 

would be unlikely to have any negative 

impacts on renewable fuel use given the 

expectations that total volumes in 2007 

will exceed the national volume 

required for 2007. This is the approach 

we are proposing today. 

This ‘‘prospective’’ approach would 

not formally apply the standard to all of 

the gasoline produced in the 2007 

calendar year. As a result, it would not 

formally ensure that the total volume of 

renewable fuel required to be used in 

2007 would actually be used. However, 

given the present circumstances, we 

believe this is an appropriate way to 

implement the Act’s provisions. We are 

confident that the combined effect of the 

proposed regulatory requirements for 

2007 and the expected market demand 

for renewable fuels will lead to greater 

renewable fuel use in 2007 than is 

called for under the Act. Furthermore, 

refiners and importers are not required 

to meet any requirements under the Act 

until EPA adopts the regulations, and 

EPA is authorized to consider 

appropriate lead time in establishing the 

regulatory requirements.12 Under this 

option we believe there would be 

reasonable lead-time for regulated 

parties to meet their 2007 compliance 

obligations. 

While we are proposing to apply the 

renewable fuel standard for 2007 

prospectively only from the effective 

date of the final rule, we nevertheless 

request comment on all these options 

for addressing compliance in calendar 

year 2007. 

4. Renewable Volume Obligations 

In order for an obligated party to 

demonstrate compliance, the percentage 

standards described in Section III.A.2 

which are applicable to all obligated 

parties must be converted into the 

volume of renewable fuel each obligated 

party is required to satisfy. This volume 

of renewable fuel is the volume for 

which the obligated party is responsible 

under the RFS program, and is referred 

to here as its Renewable Volume 

Obligation (RVO). 

The calculation of the RVO requires 

that the standard shown in Table 

III.A.2–1 for a particular compliance 

year be multiplied by the gasoline 

volume produced by an obligated party 

in that year. To the degree that an 

obligated party did not demonstrate full 

compliance with its RVO for the 

previous year, the shortfall is included 

as a deficit carryover in the calculation. 

The equation used to calculate the RVO 

for a particular year is shown below: 

RVOi = Stdi x GVi + Di¥1 


jlentini on PROD1PC65 with PROPOSAL2
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55567 

13As discussed below, for purposes of this 

rulemaking, the regulations separate ‘‘biodiesel’’ as 

defined in the Energy Act, into biodiesel (diesels 

that meet the Energy Act’s definition and are a 

mono aklyl ester) and renewable diesel (other 

diesels that meet the Energy Act’s definition but are 

not mono akly esters. 

Where 

RVOi = The Renewable Volume Obligation 

for the obligated party for year i, in 

gallons. 

Stdi = The RFS program standard for year i, 

in percent. 

GVi = The non-renewable gasoline volume 

produced by an obligated party in year 

i, in gallons. 

Di–1 = Renewable fuel deficit carryover from 

the previous year, in gallons. 

The Energy Act only permits a deficit 

carryover from one year to the next if 

the obligated party achieves full 

compliance with its RVO including the 

deficit carryover in the second year. 

Thus deficit carryovers could not occur 

two years in succession. They could, 

however, occur as frequently as every 

other year for a given obligated party. 

The calculation of an obligated party’s 

RVO is necessarily retrospective, since 

the total gasoline volume that it 

produces in a calendar year will not be 

known until the year has ended. 

However, the obligated party will have 

an incentive to project gasoline 

volumes, and thus the RVO, throughout 

the year so that it can spread its efforts 

to comply across the entire year. Most 

refiners and importers will be able to 

project their annual gasoline production 

volumes with a minimum of uncertainty 

based on their historical operations, 

capacity, plans for facility downtimes, 

knowledge of gasoline markets, etc. 

Even if unforeseen circumstances (e.g., 

hurricane, unit failure, etc) significantly 

reduced the production volumes in 

comparison to their projections, their 

RVO would likewise be reduced 

proportionally and their ability to 

comply with the RFS requirements 

would be only minimally affected. Each 

obligated party’s projected RVO for a 

given year becomes more accurate as 

that year progresses, but the obligated 

party should nevertheless have a 

sufficiently accurate estimate of its RVO 

at the beginning of the year to allow it 

to begin its efforts to comply. 

B. What Counts as a Renewable Fuel in 

the RFS Program? 

Section 211(o) of the Clean Air Act 

defines ‘‘renewable fuel’’ and specifies 

many of the details of the renewable 

fuel program. The following section 

provides EPA’s views and 

interpretations on issues related to what 

fuels may be counted towards 

compliance with the RVO, and how 

they are counted. 

1. What Is a Renewable Fuel That Can 

Be Used for Compliance? 

The statutory definition of renewable 

fuel includes cellulosic ethanol and 

waste derived ethanol. It includes 

biodiesel, as defined in the Energy 

Act.13 It also includes all motor vehicle 

fuels that are produced from biomass 

material such as grain, starch, oilseeds, 

animal, or fish materials including fats, 

greases and oils, sugarcane, sugar beets, 

tobacco, potatoes or other biomass. In 

addition, it includes motor vehicle fuels 

made using a feedstock of natural gas if 

produced from a biogas source such as 

a landfill, sewage waste treatment plant, 

feedlot, or other place where decaying 

organic material is found. 

According to the Act, the motor 

vehicle fuels must be used ‘‘to replace 

or reduce the quantity of fossil fuel 

present in a fuel mixture used to operate 

a motor vehicle.’’ Some motor vehicle 

fuels can be used in both motor vehicles 

or nonroad engines or equipment. For 

example, highway gasoline and diesel 

fuel are often used in both highway and 

off-highway applications. Compressed 

natural gas can likewise be used in 

either highway or nonroad applications. 

For purposes of the renewable fuel 

program, EPA intends to consider a fuel 

to be a ‘‘motor vehicle fuel’’ and to be 

a ‘‘fuel mixture used to operate a motor 

vehicle,’’ based on its potential for use 

in highway vehicles, without regard to 

whether it in fact is used in a highway 

or nonroad vehicle. If it is a fuel that 

could be used in highway vehicles, it 

will satisfy these parts of the definition 

of renewable fuel, whether it is later 

used in highway or nonroad 

applications. This will allow a motor 

vehicle fuel that otherwise meets the 

definition to be counted towards an 

RVO without the need to track it to 

determine its actual application in a 

highway vehicle. This is also consistent 

with the requirement that EPA base the 

renewable fuel obligation on estimates 

of the entire volume of gasoline 

consumed, without regard to whether it 

is used in highway or nonroad 

applications. Fuels that otherwise meet 

this definition but are designated by the 

producer for use in boilers, or heaters, 

or any use other than highway or 

nonroad use, would not meet the 

definition of renewable fuel. 

Renewable fuel, as defined, may be 

made from a number of different types 

of feedstocks. For example, the FisherTropsch process can use methane gas 

from landfills as a feedstock, to produce 

diesel or gasoline. Vegetable oil made 

from oilseeds such as rapeseed or 

soybeans can be used to make biodiesel 

or renewable diesel. Methane, made 

from landfill gas (biogas) can be used to 

make methanol. Also, some vegetable 

oils or animal fats can be processed in 

distillation columns in refineries to 

make gasoline; as such, the renewable 

feedstock serves as a ‘‘biocrude,’’ and 

the resulting gasoline or diesel product 

would be a renewable fuel. This last 

example is discussed in further detail in 

Section III.B.3 below. 

As this discussion shows, the 

definition of renewable fuel in the Act 

is broad in scope, and covers a wide 

range of fuels. While ethanol is used 

primarily in combination with gasoline, 

other fuels that meet the definition of 

renewable fuel include biodiesel and 

various alternative fuels that can be 

used in their neat form, such as ethanol, 

methanol or natural gas, without 

blending into gasoline and without 

being used to produce a gasoline 

blending component (such as ETBE). 

The definition of renewable fuel in the 

Act is not limited to fuels that can be 

blended with gasoline. At the same 

time, the RFS regulatory program is to 

‘‘ensure that gasoline sold or introduced 

into commerce * * * contains the 

applicable volume of renewable fuel.’’

This applicable volume is specified as a 

total volume of renewable fuel, in the 

billions of gallons on an aggregate basis. 

Congress also clearly specified that one 

renewable fuel, biodiesel, could be 

counted towards compliance even 

though it is not a gasoline component, 

and does not directly displace or replace 

gasoline. The Act is unclear on whether 

other fuels that meet the definition of 

renewable fuel, but are not used in 

gasoline, could also be used to 

demonstrate compliance towards the 

aggregate national use of renewable 

fuels. 

EPA interprets the Act as allowing 

regulated parties to demonstrate 

compliance based on any fuel that meets 

the statutory definition for renewable 

fuel, whether it is directly blended with 

gasoline or not. This would include neat 

alternative fuels such as ethanol, 

methanol, and natural gas that meet the 

definition of renewable fuel. This is 

appropriate for several reasons. First, it 

promotes the use of all renewable fuels, 

which will further the achievement of 

the purposes behind this provision. 

Congress did not intend to limit the 

program to only gasoline components, 

as evidenced by the provision for biodiesel, and the broad definition of 

renewable fuel evidences an intention to 

address more renewable fuels than those 

used with gasoline. Second, in practice 

EPA expects that the overwhelming 

volume of renewable fuel used to 

demonstrate compliance with the 


jlentini on PROD1PC65 with PROPOSAL2
55568 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

14On the other hand, wood from plants or trees 

that are grown as an energy crop may not qualify 

as a waste-derived fuel in an ethanol facility 

because such wood would not qualify as waste 

materials under this portion of the definition. 

Under the definition of renewable fuels and 

cellulosic biomass ethanol, however, such wood 

material could serve as a feedstock in a cellulosic 

ethanol plant, since these definitions do not restrict 

such feedstock to waste materials only. 

renewable fuel obligation would still be 

ethanol blended with gasoline. Whether 

one counts or does not count these 

additional renewable fuels would not in 

practice change whether the total 

national goal for renewable fuel use was 

met, given the size of the goal specified 

in the Act and the form in which the 

total is expressed. Finally, as discussed 

later, EPA’s compliance program is 

based on assigning volumes at the point 

of production, and not at the point of 

blending into motor vehicle fuel. This 

interpretation would avoid the need to 

track renewable fuels downstream to 

ensure they are blended with gasoline 

and not used in their neat form; the 

gasoline that is used in motor vehicles 

is reduced by the presence of renewable 

fuels in the gasoline pool whether they 

are blended with gasoline or not EPA 

believes its proposal is consistent with 

the intent of Congress and is a 

reasonable interpretation of the Act. 

We are therefore proposing that in 

addition to any renewable fuels that are 

actually blended into gasoline and are 

designated for use in a highway vehicle, 

we would also count any renewable 

fuels falling into the following 

categories as being valid for RFS 

compliance purposes: 

1. Any renewable fuels used in 

nonroad applications; 

2. Any renewable fuels used in their 

neat (unblended) form in onroad and 

nonroad applications; and 

3. Any renewable fuel used in a motor 

vehicle that does not normally run on 

gasoline. For instance, biogas used in a 

CNG vehicle, or biogenic methanol used 

in a dedicated methanol vehicle. 

The Agency solicits comment on this 

approach. 

Under the Act, renewable fuel 

includes ‘‘cellulosic biomass ethanol’’

and ‘‘waste derived ethanol’’, each of 

which is defined separately. Ethanol can 

be cellulosic biomass ethanol in one of 

two ways, as described below. 

a. Ethanol Made From a Cellulosic 

Feedstock. The simplest process of 

producing ethanol is by fermenting 

sugar in sugar cane, but can also be 

produced from carbohydrates in corn 

and other feedstocks. This process is 

accomplished by first converting the 

carbohydrates to sugar. Ethanol can also 

be produced from complex 

carbohydrates, such as the cellulosic 

portion of plants or plant products. The 

cellulose is first converted to sugars (by 

hydrolysis); then the same fermentation 

process is used as for carbohydrates to 

make ethanol. Cellulosic feedstocks 

(composed of cellulose and 

hemicellulose) are currently more 

difficult and costly to convert to sugar 

than are carbohydrates because of this 

intermediate conversion step. While the 

cost and difficulty are a disadvantage, 

the cellulosic process offers the 

advantage that more feedstocks can be 

used and more volume of ethanol can be 

produced. 

The Act provides the definition of 

cellulosic biomass ethanol, which 

states: 

‘‘The term ‘cellulosic biomass 

ethanol’ means ethanol derived from 

any lignocellulosic or hemicellulosic 

matter that is available on a renewable 

or recurring basis, including: 

(i) Dedicated energy crops and trees; 

(ii) Wood and wood residues; 

(iii) Plants; 

(iv) Grasses; 

(v) Agricultural residues; 

(vi) Animal wastes and other waste 

materials, and 

(viii) Municipal solid waste’’

Examples of cellulosic biomass source 

material include rice straw, switch 

grass, and wood chips. Ethanol made 

from these materials would qualify 

under the definition as cellulosic 

ethanol. In addition to the above sources 

of feedstocks for cellulosic biomass 

ethanol, the Act’s definition also 

includes animal waste, municipal solid 

wastes, and other waste materials While 

these materials may or may not contain 

cellulosic material, their inclusion in 

the definition requires that ethanol 

made from such sources be treated as 

cellulosic biomass ethanol under the 

regulations. ‘‘Other waste materials’’

generally includes waste material such 

as sewage sludge, waste candy, and 

waste starches from food production, 

but for purposes of the definition of 

cellulosic ethanol discussed in III.B.1.b 

below, it can also mean waste heat 

obtained from an off-site combustion 

process. 

Although the definitions of 

‘‘cellulosic biomass ethanol’’ and 

‘‘waste derived ethanol’’ both include 

animal wastes and municipal solid 

waste in their respective lists of covered 

feedstocks, there remains a distinction 

between these types of ethanol. If the 

animal wastes or municipal solid wastes 

contain cellulose or hemicellulose, the 

resulting ethanol can be termed 

‘‘cellulosic biomass ethanol.’’ If the 

animal wastes or municipal solid wastes 

do not contain cellulose or 

hemicellulose, then the resulting 

ethanol is labeled ‘‘waste derived 

ethanol.’’

b. Ethanol Made From Any Feedstock 

in Facilities Run Mostly With BiomassBased Fuel. The definition of cellulosic 

biomass ethanol in the Act also provides 

that ethanol made at any facility—

regardless of whether cellulosic 

feedstock is used or not—may be 

defined as cellulosic if at such facility 

‘‘animal wastes or other waste materials 

are digested or otherwise used to 

displace 90 percent or more of the fossil 

fuel normally used in the production of 

ethanol.’’ The statutory language 

suggests that there are two methods 

through which ‘‘animal and other waste 

materials’’ may be considered for 

displacing fossil fuel. The first method 

is the digestion of animal wastes or 

other waste materials. EPA proposes to 

interpret the term ‘‘digestion’’ to mean 

the conversion of animal or other wastes 

into methane, which can then be 

combusted as fuel. We base our 

interpretation on the practice in 

industry of using anaerobic digesters to 

break down waste products such as 

manure into methane. Anaerobic 

digestion refers to the breakdown of 

organic matter by bacteria in the 

absence of oxygen, and is used to treat 

waste to produce renewable fuels. We 

note also that the digestion of animal 

wastes or other waste materials to 

produce the fuel used at the ethanol 

plant does not have to occur at the plant 

itself. Methane made from animal or 

other wastes offsite and then purchased 

and used at the ethanol plant would 

also qualify. 

The second method is suggested by 

the term ‘‘otherwise used’’ which we 

propose to interpret as meaning (1) the 

direct combustion of the waste materials 

as fuel at an ethanol plant, or (2) the use 

of thermal energy that itself is a waste 

product; e.g., waste heat that is obtained 

from an off-site combustion process 

such as a neighboring plant that has a 

furnace or boiler from which the waste 

heat is captured. With respect to the 

first meaning, waste materials from tree 

farms (tops, branches, limbs, etc), or 

waste materials from saw mills 

(sawdust, shavings and bark) as well as 

other vegetative waste materials such as 

corn stover, or sugar cane bagasse, could 

be used as fuel for gasifier/boiler units 

at ethanol plants, since they are waste 

materials and would not be used as a 

feedstock to carbohydrate-based ethanol 

plants. Although such waste materials 

conceivably could be feedstocks to a 

cellulosic ethanol plant, its use as a fuel 

at a carbohydrate based ethanol plant 

does not subvert the intent of the 

definition.14


jlentini on PROD1PC65 with PROPOSAL2
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55569 

15 In Section IX of today’s preamble we discuss 

our analysis of the lifecycle fuel impacts of the RFS 

rule, with respect to greenhouse gas (GHG) 

emissions. While we do account for fuel used in 

hauling materials to ethanol plant in our analysis, 

we are using average nationwide values, rather than 

data collected for individual plants. 

16 In the event that the ASTM specification D–

6751 is succeeded with a different number in the 

future, EPA may revise the regulations accordingly 

at such time. 

Today’s regulations will require 

owners of ethanol plants to keep records 

of fuel use to ensure compliance with 

and enforcement of this provision of the 

definition of cellulosic ethanol. Due to 

potential enforcement-related problems 

associated with application of this 

component of the definition of 

cellulosic ethanol to foreign facilities, 

we intend for the final rule to develop 

compliance and enforcement related 

safeguards similar to those set forth in 

proposed 80.1165(f), (g), (h) and (j), and 

with additional inspection, audit, 

recordkeeping and reporting safeguards 

to verify compliance with the 

requirements on fuel use at foreign 

facilities. We seek comment on the most 

effective means of doing this. Because of 

the difficulty of implementing these 

safeguards, however, we also solicit 

comment on a provision that would 

limit the application of this definition of 

cellulosic ethanol only to ethanol plants 

in the U.S. 

Regarding the use of waste heat as a 

source of thermal energy, we note that 

there may be situations in which an offsite furnace, boiler or heater creates 

excess or waste heat that is not used in 

the process for which the thermal 

energy is employed. For example, a 

glass furnace generates a significant 

amount of waste heat that often goes 

unused. We are proposing to include 

waste heat in the definition of ‘‘other 

waste materials’’, and also that waste 

heat captured and used as a source of 

thermal energy in an ethanol plant 

would satisfy the requirement of other 

waste materials being ‘‘otherwise used’’

to make ethanol. Although the source of 

the waste heat is ultimately a fossil fuel 

in most cases, we recognize that without 

the capture of the heat and subsequent 

use in the ethanol plant, that energy 

would be unused, and the ethanol plant 

would consume the equivalent amount 

of fossil fuel. Thus, for the same amount 

of fossil fuel consumption at the off-site 

plant, heat energy capture would result 

in displacement of fossil fuel use at the 

ethanol plant. Because of potential 

confusion identifying thermal energy 

that is waste heat from fossil fuel 

combustion sources on site (i.e., at the 

ethanol plant itself), we are limiting this 

proposal to waste heat captured at offsite plants. The Agency solicits 

comment on our proposal to consider 

waste heat in the definition of ‘‘other 

waste materials’’. 

We propose to interpret the term 

‘‘fossil fuel normally used in the 

production of ethanol’’ to mean fossil 

fuel used at the facility in the ethanol 

production process itself, rather than 

other phases such as trucks transporting 

product, and fossil fuel used to grow 

and harvest the feedstock. Therefore the 

diesel fuel that trucks consume in 

hauling wood waste from sawmills to 

the ethanol facility would not be 

counted in determining whether the 

90% displacement criteria has been met. 

We are interpreting it in this way 

because we believe the accounting of 

fuel use associated with transportation 

and other life cycle activities would be 

extremely difficult and in many cases 

impossible.15 The Agency solicits 

comments on this aspect of our 

approach in accounting for fossil fuel 

displacement. 

Based on the operation of ethanol 

plants, we are viewing this definition to 

apply to waste materials used to 

produce thermal energy rather than 

electrical energy. Electrical usage at 

ethanol plants is used for lights and 

equipment not related to the production 

of ethanol. Also, the calculation of fossil 

fuel used to generate such electrical 

usage would be difficult because it is 

not always possible to track the source 

of electricity that is purchased off-site. 

We are therefore proposing that the 

displacement of 90 percent of fossil 

fuels at the ethanol plant means those 

fuels consumed on-site and that are 

used to generate thermal energy used to 

produce ethanol. The term ‘‘fossil fuel 

normally used in the production of 

ethanol’’ in today’s proposal means 

fossil fuel that is combusted at the 

facility itself to produce thermal energy. 

Owners are required to keep records of 

fuel (waste-derived and fossil fuel) used 

for thermal energy for verification of 

their claims. They will also be required 

to track the fossil fuel equivalent of the 

waste heat captured and used in the 

ethanol process. Since such waste heat 

would typically be purchased through 

agreement with the off-site owner, we 

do not feel it burdensome for owners to 

track such information. Owners would 

therefore calculate the amount of energy 

in Btu’s associated with waste-derived 

fuels (including the fossil fuel 

equivalent waste heat), and divided by 

the total energy in Btus used to produce 

ethanol in a given year. Holders of RINs 

associated with the sale or trade of such 

cellulosic ethanol would get the benefit 

of the 2.5 credit (through 2012 when 

such credit is valid). 

In the event that the requirements of 

90 percent displacement of fossil fuel 

are not met, the owner of a facility 

producing such ethanol would be 

required to obtain additional RINs to 

make up whatever deficit exists for 

those RINs sold or traded with a value 

of 2.5. Assuming this is made up, then 

holders of the RINs associated with the 

ethanol the plant produced in the 

previous year would not be affected. We 

solicit comment on this proposed 

approach. 

c. Ethanol that is made from the noncellulosic portions of animal, other 

waste, and municipal waste. ‘‘Waste 

derived ethanol’’ is defined in the Act 

as ethanol derived from ‘‘animal wastes, 

including poultry fats and poultry 

wastes, and other waste materials; 

* * * or municipal solid waste.’’ Both 

animal wastes and municipal solid 

waste are also listed as allowable 

feedstocks for the production of 

‘‘cellulosic biomass ethanol.’’ The 

determination of the appropriate 

category of ethanol is based on whether 

the feedstocks on question contain 

cellulose or hemicellulose that is used 

to make the ethanol. Thus, if the ethanol 

is made from the non-cellulosic portions 

of animal, other waste, or municipal 

waste, it is labeled ‘‘waste derived 

ethanol.’’

2. What Is Biodiesel? 

The definition of renewable fuel in 

the Act includes corn-based and 

cellulosic biomass ethanol, waste 

derived ethanol, and the renewable fuel 

portion of blending components derived 

from renewable fuel. Biodiesel is also 

specifically named as being included in 

the Act’s definition of renewable fuel. 

The Act states that ‘‘The term 

‘renewable fuel’ includes * * * 

biodiesel (as defined in section 312(f) of 

the Energy Policy Act of 1992.’’ This 

definition, as modified by Section 1515 

of the Energy Act states: 

The term ‘‘biodiesel’’ means a diesel 

fuel substitute produced from 

nonpetroleum renewable resources that 

meets the registration requirements for 

fuels and fuel additives established by 

the Environmental Protection Agency 

under section 7545 of this title, and 

includes biodiesel derived from animal 

wastes, including poultry fats and 

poultry wastes, and other waste 

materials, or municipal solid waste and 

sludges and oils derived from 

wastewater and the treatment of 

wastewater. 

This definition of biodiesel would 

include both mono-alkyl esters which 

meet ASTM specification D–6751 16 (the 

most common meaning of the term 


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17Biocrude-based renewable fuels will need to be 

registered under the provisions contained in 40 CFR 

79 Part 4 before they can be sold commercially. 

18With respect to biodiesel, however, since such 

fuel is typically not made in a traditional 

petroleum-based refinery, it would not be a 

biocrude-based renewable fuel and would thus not 

be limited to the 1.0 Equivalence Value. 

‘‘biodiesel’’) that have been registered 

with EPA, and any non-esters that are 

intended for use in engines that are 

designed to run on conventional, 

petroleum-derived diesel fuel, have 

been registered with the EPA, and are 

made from any of the feedstocks listed 

above. 

To implement the above definition of 

biodiesel in the context of the RFS 

rulemaking while still recognizing the 

unique history and role of mono-alkyl 

esters meeting ASTM D–6751, we 

propose to divide the Act’s definition of 

biodiesel into two separate parts: 

biodiesel (mono-alkyl esters) and nonester renewable diesel. The combination 

of ‘‘biodiesel (mono-alkyl esters)’’ and 

‘‘non-ester renewable diesel’’ in the 

regulations would fulfill the Act’s 

definition of biodiesel. The Agency 

solicits comment on this approach and 

specifically asks whether the ‘‘non-ester 

renewable diesel’’ definition be 

referenced explicitly to ASTM D–975. 

a. Biodiesel (Mono-Alkyl Esters). 

Under this part, the term ‘‘biodiesel 

(mono-alkyl esters)’’ means a motor 

vehicle fuel which: (1) Meets the 

registration requirements for fuels and 

fuel additives established by the 

Environmental Protection Agency under 

section 7545 of this title (Clean Air Act 

Section 211); (2) is a mono-alkyl ester; 

(3) meets ASTM specification D–6751–

02a; (4) is intended for use in engines 

that are designed to run on 

conventional, petroleum-derived diesel 

fuel, and (5) is derived from 

nonpetroleum renewable resources 

including, but not limited to, animal 

wastes, including poultry fats and 

poultry wastes, and other waste 

materials, or municipal solid waste and 

sludges and oils derived from 

wastewater and the treatment of 

wastewater. 

b. Non-Ester Renewable Diesel. The 

term ‘‘non-ester renewable diesel’’

means a motor vehicle fuel which: (1) 

Meets the registration requirements for 

fuels and fuel additives established by 

the Environmental Protection Agency 

under section 7545 of this title (Clean 

Air Act Section 211); (2) is not a monoalkyl ester; (3) is intended for use in 

engines that are designed to run on 

conventional, petroleum-derived diesel 

fuel, and (4) is derived from 

nonpetroleum renewable resources 

including, but not limited to, animal 

wastes, including poultry fats and 

poultry wastes, and other waste 

materials, or municipal solid waste and 

sludges and oils derived from 

wastewater and the treatment of 

wastewater. Current examples of a nonester renewable diesel include: 

‘‘renewable diesel’’ produced by the 

Neste process, or diesel fuel produced 

by processing fats and oils through a 

refinery hydrotreating process. 

3. Is Motor Fuel That Is Made From a 

Renewable Feedstock a Renewable 

Fuel? 

We interpret the statutory definition 

of renewable fuels to include all 

gasoline or diesel that is made from a 

class of feedstocks called ‘‘biocrudes’’, 

which are defined as biologically 

derived feedstocks (such as fats and 

greases). We are providing a definition 

of ‘‘biocrude-based renewable fuels’’ to 

mean gasoline or diesel products 

resulting from the processing of 

biocrudes in production units within 

refineries that process crude oil and 

other petroleum based feedstocks and 

which make gasoline and diesel fuel.17

A particular batch of biocrude used as 

feedstock to a production unit would 

replace crude oil or other petroleum 

based feedstocks which ordinarily 

would be the feedstock in that process 

unit. The non-ester renewable diesel 

defined in Section III.B.2.b above could 

be one such type. 

We are assuming that all of the 

biocrude used as a feedstock in a 

refinery unit will end up as a biocrudebased renewable fuel. Rather than 

requiring the refiner to document what 

portion of the biocrude-based renewable 

fuel is other than diesel or gasoline (e.g., 

jet fuel), we are proposing to have the 

volume of the biocrude itself count as 

the volume of renewable fuel produced 

for the purposes of determining the 

volume block codes that are in the RIN 

(discussed in further detail in Section 

III.D). While this approach may result in 

some products such as jet fuel being 

counted as renewable fuel, we believe 

the majority of the products produced 

will be motor vehicle fuel because we 

assume refiners who elect to use 

biocrudes would do so to help meet the 

requirements of this rule. Furthermore, 

both diesel and gasoline presently make 

up about 85 percent of the product slate 

of refineries on average. This amount 

that has been steadily increasing for 

over time, and we expect that the 

percentage will continue to increase as 

demand for gasoline and diesel 

increases. 

We are also proposing that the 

Equivalence Value assigned to biocrudebased renewable fuels be designated as 

1.0, despite the fact that they might 

warrant a higher value based on their 

energy content as described in the next 

section.18 This approach should balance 

out the likelihood that some of the 

biocrude-based renewable fuel is not a 

motor vehicle fuel. 

4. What Are ‘‘Equivalence Values’’ for 

Renewable Fuel? 

One question that EPA must address 

is how to count volumes of renewable 

fuel in determining compliance with the 

renewable volume obligation. For 

instance, the Act stipulates that every 

gallon of cellulosic ethanol should 

count as if it were 2.5 gallons for RFS 

compliance purposes. The Act does not 

stipulate similar values for other 

renewable fuels, but as described below 

we believe it is appropriate to do so. 

We are proposing that the 

‘‘Equivalence Values’’ for different 

renewable fuels be based on their energy 

content in comparison to the energy 

content of ethanol, and adjusted as 

necessary for their renewable content. 

The result is an Equivalence Value for 

corn ethanol of 1.0, for biobutanol of 

1.3, for biodiesel (mono alkyl ester) of 

1.5, and for cellulosic ethanol of 2.5. 

However, the methodology can be used 

to determine the appropriate 

equivalence value for any other 

potential renewable fuel as well. 

This section describes why we believe 

that the use of relative energy content is 

appropriate under the Act, and our 

investigation of the alternative use of 

lifecycle analyses as the basis of 

Equivalence Values. 

a. Authority Under The Act To 

Establish Equivalence Values. We are 

proposing that Equivalence Values be 

assigned to every renewable fuel to 

provide an indication of the number of 

gallons that can be claimed for 

compliance purposes for every physical 

gallon of renewable fuel. An 

Equivalence Value of 1.0 would mean 

that every physical gallon of renewable 

fuel would count as one gallon for RFS 

compliance purposes. An Equivalence 

Value greater than 1.0 would mean that 

every physical gallon of renewable fuel 

would count as more than one gallon for 

RFS compliance purposes, while a value 

less than 1.0 would count as less than 

one gallon. 

We are interpreting the Act as 

allowing EPA to develop Equivalence 

Values according to the methodology 

discussed below. We believe that the 

use of Equivalence Values is consistent 

with the intent of Congress to treat 

different renewable fuels differently in 

different circumstances, and to provide 


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19 ‘‘Calculation of equivalence values for 

renewable fuels under the RFS program’’, memo 

from David Korotney to EPA Air Docket OAR–

2005–0161. 

incentives for use of renewable fuels in 

certain circumstances, as evidenced by 

those specific circumstances addressed 

by Congress. The Act has several 

provisions that provide for mechanisms 

other than straight volume measurement 

to determine the value of a renewable 

fuel in terms of RFS compliance. For 

example, 1 gallon of cellulosic biomass 

or waste derived ethanol is to be treated 

as 2.5 gallons of renewable fuel. EPA is 

also required to establish an 

‘‘appropriate amount of credits’’ for 

biodiesel, and to provide for ‘‘an 

appropriate amount of credit’’ for using 

more renewable fuels than are required 

to meet your obligation. EPA is also to 

determine the ‘‘renewable fuel portion’’

of a blending component derived from 

a renewable fuel. All of these statutory 

provisions provide evidence that 

Congress did not limit this program 

solely to a straight volume measurement 

of gallons in the context of the RFS 

program for certain specified 

circumstances. 

The Act is unclear as to whether a 

straight gallon measurement is required 

in circumstances other than those 

specified by Congress. We believe the 

Act can and should be interpreted to 

allow the use of Equivalence Values in 

those circumstances. First, this is 

consistent with the way Congress 

treated the various specific 

circumstances noted above, and thus is 

basically a continuation of that process. 

Second, EPA does not believe that 

providing such an Equivalence Value 

for this small volume of renewable fuel 

will interfere in any way with meeting 

the total national volume goals for usage 

of renewable fuel. We are proposing to 

use an Equivalence Value of 1.0 for 

ethanol other than cellulosic biomass or 

waste derived ethanol, and we expect 

that there will only be very limited 

additional situations where an 

Equivalence Value other than 1.0 is 

used. As a result, this approach is a 

reasonable way for the RFS program to 

ensure that the total volume of 

renewable fuels will be used as required 

under the Act. 

b. Energy Content and Renewable 

Content as the Basis for Equivalence 

Values. We believe it is appropriate to 

base the Equivalence Value assigned to 

a particular renewable fuel on the 

degree to which the renewable fuel 

supplants the petroleum content of fuel 

used in a motor vehicle. This is 

consistent with the Act’s definition of 

renewable fuel, which refers to the 

degree to which it is directly used to 

replace or reduce the quantity of fossil 

fuel present in a fuel mixture used to 

operate a motor vehicle. The degree to 

which the fossil fuel is replaced is best 

represented by its relative energy 

content. To appropriately account for 

the different energy contents of different 

renewable fuels as well as the fact that 

some renewable fuels actually contain 

some non-renewable content, we 

propose to calculate Equivalence Values 

using both the renewable content of a 

renewable fuel and its energy content. 

This section describes our proposal for 

calculating the Equivalence Values. 

In order to take the energy content of 

a renewable fuel into account when 

calculating the Equivalence Values, we 

must identify an appropriate point of 

reference. Ethanol would be a 

reasonable point of reference as it is 

currently the most prominent renewable 

fuel in the transportation sector, and it 

is likely that the authors of the Act saw 

ethanol as the primary means through 

which the required volumes would be 

met in at least the first years of the RFS 

program. By comparing every renewable 

fuel to ethanol on an equivalent energy 

content basis, each renewable fuel could 

be assigned an Equivalence Value that 

precisely accounts for the amount of 

petroleum in motor vehicle fuel that is 

reduced or replaced by that renewable 

fuel in comparison to ethanol. To the 

degree that corn-based ethanol 

continues to dominate the pool of 

renewable fuel, this approach would 

allow actual volumes of renewable fuel 

to be consistent with the volumes 

required by the Act while still allowing 

some renewable fuels to be attributed a 

higher value in terms of RFS 

compliance to the extent that they have 

a higher energy content than ethanol. 

Equivalence Values should also 

account for the renewable content of 

renewable fuels, since the presence of 

any non-renewable content impairs the 

ability of the renewable fuel to replace 

or reduce the quantity of fossil fuel 

present in a fuel mixture used to operate 

a motor vehicle. The Act specifically 

states that only the renewable fuel 

portion of a blending component should 

be considered part of the applicable 

volume under the RFS program. We 

have interpreted this to mean that every 

renewable fuel should be evaluated at 

the molecular level to distinguish 

between those components that were 

derived from a renewable feedstock, 

versus those components that were 

derived from a fossil fuel feedstock. 

Along with energy content in 

comparison to ethanol, the relative 

amount of renewable versus nonrenewable content can then be used 

directly as the basis for the Equivalence 

Value. 

We propose that the calculation of 

Equivalence Values should 

simultaneously take into account both 

the renewable content of a renewable 

fuel and its energy content in 

comparison to ethanol. To accomplish 

this, we propose the following formula: 

EV = (RRF / REth) × (ECRF / ECEth) 

Where: 

EV = Equivalence Value for the renewable 

fuel. 

RRF = Renewable content of the renewable 

fuel, in percent. 

REth = Renewable content of ethanol, in 

percent. 

ECRF = Energy content of the renewable fuel, 

in Btu per gallon (LHV). 

ECEth = Energy content of ethanol, in Btu per 

gallon (LHV). 

R is a measure of that portion of a 

single renewable fuel molecule which 

can be considered to have come from a 

renewable source. Since R is being 

combined with relative energy content 

in the formula above, the value of R 

cannot be based on the weight fraction 

of the renewable atoms in the molecule, 

but rather must be based on the energy 

content of those atoms. As a result the 

calculation of R for any particular 

renewable fuel requires an analysis of 

the chemical process through which it 

was produced. A detailed explanation of 

calculations for R and several examples 

are given in a technical memorandum in 

the docket 19. 

In the case of ethanol, denaturants are 

added to preclude its use as food. 

Denaturants are generally a fossil-fuel 

based, gasoline-like hydrocarbon in 

concentrations of 2–5 volume percent, 

with 5 percent being the most common 

historical level. In general this would 

mean that the Equivalence Value of 

ethanol would be 0.95. However, we 

believe that the Equivalence Value for 

ethanol should be specified as 1.0 

despite the presence of a denaturant. 

First, as stated above, ethanol is 

expected to dominate the renewable fuel 

pool for at least the next several years, 

and it is likely that the authors of the 

Act recognized this fact. Thus it seems 

likely that it was the intent of the 

authors of the Act that each physical 

gallon of denatured ethanol be counted 

as one gallon for RFS compliance 

purposes. Second, the accounting of 

ethanol has historically ignored the 

presence of the denaturant. For 

instance, under Internal Revenue 

Service (IRS) regulations the denaturant 

can be counted as ethanol by parties 

filing claims to the IRS for the Federal 

excise tax credit. Also, EIA reporting 

requirements for ethanol producers 


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allow them to include the denaturant in 

their reported volumes. 

Since we are proposing that 

denatured ethanol be assigned an 

Equivalence Value of 1.0, this must be 

reflected in the values of REth and ECEth. 

We have calculated these values to be 

93.1 percent and 77,550 Btu/gal, 

respectively. Details of these 

calculations can be found in the 

aforementioned technical memorandum 

to the docket. 

The calculation of the Equivalence 

Value for a particular renewable fuel 

can lead to values that deviate only 

slightly from 1.0, and/or can have 

varying degrees of precision depending 

on the uncertainty in the value of R or 

ECRF. We are therefore proposing three 

simplifications to streamline the 

application of Equivalence Values in the 

context of the RFS program. First, 

consistent with our approach to the R 

value for ethanol, we are proposing that 

all Equivalence Values calculated to be 

in the range of 0.9–1.2 be treated as if 

they were exactly 1.0. This approach 

would eliminate many of the 

complexities described in Section III.D.2 

that are associated with using renewable 

fuels for RFS compliance purposes that 

have an Equivalence Value other than 

1.0. Second, we propose that several 

bins be created for renewable fuels with 

Equivalence Values above 1.0. These 

bins would replace the calculated 

Equivalence Values with standardized 

ones to account for uncertainty in the 

calculations as well as to simplify their 

application. We propose that the bins be 

1.0, 1.3, 1.5, and 1.7. Each renewable 

fuel would be assigned to the bin that 

is closest to its calculated Equivalence 

Value. Finally, we propose that all 

Equivalence Values, if any, which are 

calculated to be less than 0.9 be 

rounded to the first decimal place. 

Using the methodology described 

above, we calculated the Equivalence 

Values for a number of different 

renewable fuels expected to be in use 

over the next few years, and modified 

them according to our proposed 

rounding protocols. These are shown in 

the table below. 

TABLE III.B.4–1.—PROPOSED EQUIVALENCE VALUES FOR SOME RENEWABLE FUELS

Equivalence 

Value (EV) 

Cellulosic biomass ethanol or 

waste-derived ethanol ....... 2.5 

Ethanol from corn, starches, 

or sugar ............................. 1.0 

Biodiesel (mono alkyl ester) 1.5 

Non-ester renewable diesel .. 1.7 

Butanol .................................. 1.3 

TABLE III.B.4–1.—PROPOSED EQUIVALENCE VALUES FOR SOME RENEWABLE FUELS—Continued 

Equivalence 

Value (EV) 

ETBE from corn ethanol ....... 0.4 

Since there are a wide variety of 

possible renewable fuels that could 

qualify under the RFS program, there 

may be cases in which a party produces 

a renewable fuel not shown in Table 

III.B.4–1. In such cases we propose to 

allow the producer to submit a petition 

to the Agency describing the renewable 

fuel, its feedstock and production 

process, and the calculation of its 

Equivalence Value. The Agency would 

review the petition and assign an 

appropriate Equivalence Value to the 

renewable fuel based on the proposed 

rounding protocols described above. 

Regarding publication of the newly 

assigned Equivalence Value, we could 

publish it in the Federal Register at the 

same time as the annual standard is 

published each November. We request 

comment on whether publishing new 

Equivalence Values in this manner is 

appropriate. 

Regarding biodiesel (mono alkyl 

esters), we also considered an additional 

approach in setting the Equivalence 

Value. Since ethanol derived from waste 

products such as animal wastes and 

municipal solid waste will be assigned 

an Equivalence Value of 2.5 based on a 

requirement in the Act, it might be 

appropriate to create a parallel 

provision for biodiesel made from 

wastes. Under this approach, biodiesel 

made from waste products would be 

assigned an Equivalence Value of 2.5 

through 2012. Currently, waste products 

(for example, poultry fats and poultry 

wastes, municipal solid waste, or 

wastewater sludge) make up less than 

10 percent of biodiesel feedstocks. This 

approach would have the effect of 

incentivizing the use of waste products 

and recycled biomass to make biodiesel. 

Beyond the RFS program, it could also 

set a precedent to promote recycling and 

waste conservation. While we are not 

proposing to set the Equivalence Value 

for waste-derived biodiesel at 2.5 in 

today’s action, we nevertheless believe 

that this approach has merit and request 

comment on it. 

c. Lifecycle Analyses as The Basis for 

Equivalence Values. Although we are 

proposing that Equivalence Values be 

based on energy content relative to 

ethanol and renewable content, some 

stakeholders have suggested that 

Equivalence Values should be based on 

lifecycle analyses. Such an approach 

may have merit, but it would also raise 

a number of challenges. Consequently, 

we are inviting comment here not only 

on the merit and basis for setting 

equivalence values on a lifecycle basis, 

but also the appropriate means of doing 

so. 

Lifecycle analyses involve an 

examination of fossil fuel used, and 

emissions generated, at all stages of a 

renewable fuel’s life. A typical lifecycle 

analysis examines production of the 

feedstock, its transport to a conversion 

facility, the conversion of the feedstock 

into renewable motor vehicle fuel, and 

the transport of the renewable fuel to 

the consumer. At each stage, every 

activity that consumes fossil fuels or 

results in emissions is quantified, and 

these energy consumption and emission 

estimates are then summed over all 

stages. By accounting for every activity 

associated with renewable fuels over 

their entire life, we can assess 

renewable fuels in terms of not just their 

impact within the transportation sector, 

but across all sectors, and thus for the 

nation as a whole. In this way they 

provide a more complete picture of the 

potential impacts of different fuels or 

different fuel sources. 

Advocates for using lifecycle analyses 

for setting the Equivalence Values for 

different renewable fuels indicate that 

there could be several advantages to this 

approach. First, doing so could create an 

incentive for obligated parties to choose 

renewable fuels having a greater ability 

to reduce fossil fuel use or resulting 

emissions, since such renewable fuels 

would have higher Equivalence Values 

and thus greater value in terms of 

compliance with the RFS requirements. 

The preferential demand for renewable 

fuels having higher Equivalence Values 

could in turn spur additional growth in 

production of these renewable fuels. 

Second, using lifecycle analyses as the 

basis for Equivalence Values could 

orient the RFS program more explicitly 

towards reducing fossil fuel use or 

emissions. 

At the same time, the use of lifecycle 

analyses to establish the Equivalence 

Values for different renewable fuels also 

raises a number of issues. For instance, 

lifecycle analyses can be conducted 

using several different metrics, 

including total fossil fuel consumed, 

petroleum energy consumed, criteria 

pollutant emissions (e.g., VOC, NOX, 

PM) carbon dioxide emissions, or 

greenhouse gas emissions. Each metric 

would result in a different Equivalence 

Value for the same renewable fuel. At 

the present time there is no consensus 

on which metric would be most 

appropriate for this purpose. 


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20CAA Section 211(o)(2)(A)(i), as added by 

Section 1501(a) of the Energy Policy Act of 2005. 

21 ‘‘Gasoline treated as blendstock,’’ or ‘‘GTAB,’’

would be treated as any other blendstock with 

regard to the RFS rule; i.e., where the GTAB is 

blended with other blendstock to produce gasoline, 

the total volume of the gasoline blend, including 

the GTAB, would be included in the volume 

gasoline used to determine the renewable fuel 

obligation for the blender. Where the GTAB is 

blended with finished gasoline, only the GTAB 

volume would be included. 

22The noncontiguous states are Alaska and 

Hawaii. The territories are the Commonwealth of 

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

American Samoa, and the Commonwealth of the 

Northern Marianas. 

23CAA Section 211(o)(3)(B), as added by Section 

1501(a) of the Energy Policy Act of 2005. 

There is also no consensus on the 

approach to lifecycle analyses 

themselves. Although we have chosen 

to base our lifecycle analyses on 

Argonne National Laboratory’s GREET 

model for the reasons described in 

Section IX, there are a variety of other 

lifecycle models and analyses available. 

The choice of model inputs and 

assumptions all have a bearing on the 

results of lifecycle analyses, and many 

of these assumptions remain the subject 

of debate among researchers. Lifecycle 

analyses must also contend with the fact 

that the inputs and assumptions 

generally represent industry-wide 

averages even though energy consumed 

and emissions generated can vary 

widely from one facility or process to 

another. There currently exists no single 

body, governmental or otherwise, that 

has organized a comprehensive dialogue 

among stakeholders about the 

appropriate tools and assumptions 

behind any lifecycle analyses with the 

goal of coming to agreement. 

Another issue to using lifecycle 

analyses as the basis for Equivalence 

Values pertains to the ultimate impact 

that the RFS program would have on 

petroleum use, fossil fuel use, criteria 

pollutant emissions, and/or emissions of 

GHGs. With a fixed volume of 

renewable fuel required under the RFS 

program, any renewable fuel with an 

Equivalence Value greater than 1.0 

would necessarily mean that fewer 

actual gallons would be needed to meet 

the RFS standard. Thus, the advantage 

per gallon may be offset with fewer 

overall gallons, resulting in no overall 

additional benefit unless the RFS 

standard was simultaneously adjusted. 

Finally, lifecycle analyses of different 

renewable fuels are likely to change 

over time as farming practices and 

process technologies evolve. Significant 

changes would necessitate 

corresponding changes in the RFS 

program to adjust the Equivalence 

Values on an ongoing basis which 

would add uncertainty into the longterm RIN market. 

We request comment on all issues 

associated with the use of lifecycle 

analyses in establishing the Equivalence 

Values for different renewable fuels for 

the RFS program. 

C. What Gasoline Is Used To Calculate 

the Renewable Fuel Obligation and Who 

Is Required To Meet the Obligation? 

1. What Gasoline Is Used to Calculate 

the Volume of Renewable Fuel Required 

To Meet a Party’s Obligation? 

The Act requires EPA to promulgate 

regulations designed to ensure that 

‘‘gasoline sold or introduced into 

commerce in the United States (except 

in noncontiguous states or territories)’’

contains on an annual average basis, the 

applicable aggregate volumes of 

renewable fuels as prescribed in the 

Act.20 To implement this provision, we 

are proposing that the volume of 

gasoline used to determined the 

renewable fuel obligation include all 

finished gasoline, RFG and 

conventional, produced or imported for 

use in the contiguous United States 

during the annual averaging period. We 

are also proposing to include in the 

volume of gasoline used to determine 

the renewable fuel obligation all 

unfinished gasoline that becomes 

finished gasoline upon the addition of 

oxygenate blended downstream from 

the refinery or importer. This would 

include both unfinished reformulated 

gasoline, called ‘‘reformulated gasoline 

blendstock for oxygenate blending,’’ or 

‘‘RBOB,’’ and unfinished conventional 

gasoline (e.g. sub-octane conventional 

gasoline), called ‘‘CBOB.’’

Under the proposed rule, the volume 

of any other unfinished gasoline or 

blendstock, such as butane, would not 

be included in the volume used to 

determine the renewable fuel obligation, 

except where the blendstock is 

combined with other blendstock or 

finished gasoline to produce finished 

gasoline. Where a blendstock is blended 

with other blendstock to produce 

finished gasoline, RBOB, or CBOB, the 

total volume of the gasoline blend 

would be included in the volume used 

to determine the renewable fuels 

obligation for the blender. Where a 

blendstock is added to finished 

gasoline, only the volume of the 

blendstock would be included, since the 

finished gasoline would have been 

included in the compliance 

determinations of the refiner or importer 

of the gasoline.21 Gasoline produced or 

imported for use in a noncontiguous 

state or U.S. territory 22 would not be 

included in the volume used to 

determine the renewable fuels 

obligation (unless the noncontiguous 

state or territory has opted-in to the RFS 

program), nor would gasoline, RBOB or 

CBOB exported for use outside the 

United States. 

For purposes of this preamble, the 

various gasoline products (as described 

above) that we are proposing to include 

in the volume of gasoline used to 

determine the renewable fuel obligation 

are collectively called ‘‘gasoline.’’

Generally, ethanol and other 

renewable fuels would typically be used 

in gasoline, increasing the volume of the 

entire gasoline blend. We are proposing 

to exclude the volume of renewable 

fuels contained in gasoline from the 

volume of gasoline used to determine 

the renewable fuels obligation. In 

implementing the Act’s renewable fuels 

requirement, our primary goal is to 

design a program that is simple, flexible 

and enforceable. If the program were to 

include renewable fuels in the volume 

of gasoline used to determine the 

renewable fuel obligation, then every 

blender that blends ethanol downstream 

from the refinery or importer would be 

subject to the renewable fuel obligation 

for the volume of ethanol that they 

blend. There are currently 

approximately 1,200 such ethanol 

blenders. Of these blenders, only those 

who blend ethanol into RBOB are 

regulated parties under current fuels 

regulations. Designating all of these 

ethanol blenders as obligated parties 

under the RFS program would greatly 

expand the number of regulated parties 

and increase the complexity of the RFS 

program beyond that which is necessary 

to carry out the renewable fuels 

mandate under the Act. 

The Act provides that the renewable 

fuel obligation shall be ‘‘applicable to 

refiners, blenders, and importers, as 

appropriate.’’ 23 For the reasons 

discussed above, we believe it is 

appropriate to exclude downstream 

renewable fuel blenders from the group 

of parties subject to the renewable fuel 

obligation, and to exclude renewable 

fuels from the volume of gasoline used 

to determine the renewable fuel 

obligation. This exclusion would apply 

to any renewable fuels that are blended 

into gasoline at a refinery, contained in 

imported gasoline, or added at a 

downstream blending facility. Thus, for 

example, any ethanol added to RBOB or 

CBOB downstream from the refinery or 

importer would be excluded from the 

volume of gasoline used to determine 

the obligation. Any non-renewable fuel 

added downstream, however, would be 

included in the volume of gasoline used 

to determine the obligation. This 

approach has no impact on the total 


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24CAA Section 211(o)(a)(9), as added by Section 

1501(a) of the Energy Policy Act of 2005. 

volume of renewable fuels required, 

merely on the number of obligated 

parties. We invite comment on the 

proposal to exclude renewable fuels in 

the volume of gasoline subject to the 

renewable fuels obligation. As discussed 

earlier, in a similar manner this volume 

of renewable fuel would also be 

excluded from the calculation 

performed each year by EPA to 

determine the applicable percentage. 

2. Who Is Required To Meet the 

Renewable Fuels Obligation? 

Under the proposed rule, persons who 

meet the definition of refiner, which 

includes blenders who produce gasoline 

by combining blendstocks or blending 

blendstocks into finished gasoline, and 

persons who meet the definition of 

importer under the fuels regulations 

would be subject to the renewable fuel 

obligation. As noted above, blenders 

who only blend renewable fuels 

downstream from the refinery or 

importer would not be subject to the 

renewable fuel obligation. Any person 

that is required to meet the renewable 

fuels obligation is called an ‘‘obligated 

party.’’ We generally refer to all of the 

obligated parties as refiners and 

importers, as the covered blenders are 

all refiners under the regulations. 

A refiner or importer located in a 

noncontiguous state or U.S. territory 

would not be subject to the renewable 

fuel obligation and thus would not be an 

obligated party (unless the 

noncontiguous state or territory opts-in 

to the RFS program). A party located 

within the contiguous 48 states that 

‘‘imports’’ into the 48 states gasoline 

produced or imported by a refiner or 

importer located in a noncontiguous 

state or territory would be an obligated 

party and must meet the renewable fuel 

obligation for such gasoline. 

3. What Exemptions Are Available 

Under The RFS Program? 

a. Small Refinery and Small Refiner 

Exemption. The Act provides an 

exemption from the RFS standard for 

small refineries during the first five 

years of the program. The Act defines 

small refinery as ‘‘a refinery for which 

the average aggregate daily crude oil 

throughput for a calendar year (as 

determined by dividing the aggregate 

throughput for the calendar year by the 

number of days in the calendar year) 

does not exceed 75,000 barrels.’’ 24

Under the proposed rule, any gasoline 

produced at a refinery that qualifies as 

a small refinery under this definition is 

not counted in determining the 

renewable fuel obligation of a refiner 

until January 1, 2011. Where a refiner 

complies with the renewable fuel 

obligation on an aggregate basis for 

multiple refineries, the refiner may 

exclude from its compliance 

calculations gasoline produced at any 

refinery that qualifies as a small refinery 

under the RFS program. Beginning in 

2011, small refineries would be required 

to meet the same renewable fuel 

obligation as all other refineries. This 

exemption would apply to any refinery 

that meets the definition of small 

refinery stated above regardless of the 

size of the refining company that owns 

the refinery. Based on information 

currently available to us we expect 42 

small refineries to qualify for this 

exemption. 

In addition to small refineries as 

defined in the Act, we are proposing to 

extend this relief to refiners who meet 

the proposed criteria for small refiner 

status. Under the proposal, a small 

refiner is defined as any refiner who, 

during 2004: (1) Produces gasoline at a 

refinery by processing crude oil through 

refinery processing units; (2) employs 

an average of no more than 1,500 

people, including all employees of the 

small refiner, any parent company and 

its subsidiary companies; and (3) has a 

total crude oil processing capability for 

all of the small refiner’s refineries of 

155,000 barrels per calendar year 

(bpcd). These size requirements were 

established in prior rulemakings and 

were the result of our analysis of small 

refiner impacts. We do not believe that 

there are more than three gasoline 

refineries owned by small refiners that 

meet these criteria and that currently 

exceed the 75,000 bpcd crude oil 

processing capability defined by the 

Act. We request comment on whether a 

refiner who has a refinery which 

exceeds the 75,000 bpcd criteria should 

be eligible to apply for a small refiner 

exemption under the RFS program. EPA 

believes it has this discretion in 

determining an appropriate lead-time 

for the start-up of this program, as well 

as discretion to determine the regulated 

refiners, blenders and importers, ‘‘as 

appropriate.’’

We are also proposing to allow foreign 

refiners to apply for a small refinery or 

small refiner exemption under the RFS 

program. This would apply to foreign 

refiners that apply for refineries under 

the 75,000 bpcd criteria or foreign 

refiners that apply for small refiner 

status. Under the anti-dumping, MSAT 

and gasoline sulfur rules, foreign 

refiners are allowed to comply with 

certain regulations separately from any 

importer. Additional requirements 

applicable to such foreign refiners are 

included in these rules to ensure that 

enforcement of the regulations at the 

foreign refinery would not be 

compromised. We are proposing similar 

enforcement-related requirements that 

would apply to foreign refiners that 

apply for a small refinery or small 

refiner exemption. Under the existing 

fuels regulations, few foreign refiners 

have chosen to undertake these 

additional requirements, and almost all 

gasoline produced at foreign refineries 

is included in the importers’

compliance determinations. We invite 

comment on the value of extending the 

small refinery and small refiner 

exemptions to foreign refiners under the 

RFS program. 

Under the proposed rule, applications 

for a small refinery exemption must be 

received by EPA by September 1, 2007 

for the exemption to be effective in 2007 

and subsequent calendar years. The 

application must include 

documentation that the small refinery’s 

average aggregate daily crude oil 

throughput for calendar year 2004 did 

not exceed 75,000 barrels. As long as the 

refinery met the criteria in 2004, it 

would have the exemption through 2010 

regardless of changes in crude 

throughput or ownership. A small 

refinery exemption would be effective 

60 days after receipt of the application 

by EPA unless EPA notifies the 

applicant that the application was not 

approved or that additional 

documentation is required. We are 

proposing to base eligibility on 2004 

data rather than on 2005 data, since it 

was the first full year prior to passage 

of the Energy Act. In addition, some 

refineries’ production may have been 

affected by Hurricane Katrina in 2005. 

We request comment on whether 

multiple-year average should be the 

basis for eligibility. 

As discussed above, refiners that do 

not qualify for a small refinery 

exemption under the 75,000 bpcd 

criteria, but nevertheless meet the 

criteria of a small refiner may apply for 

small refiner status under the RFS rule. 

The application must be received by 

EPA by September 1, 2007 for the 

exemption to be effective in 2007 and 

subsequent calendar years. Like the 

exemption for small refineries, small 

refiner status would be determined 

based on documentation submitted in 

the application which demonstrates that 

the refiner met the criteria for small 

refiner status during the calendar year 

2004. EPA will notify the refiner of 

approval or disapproval of small refiner 

status by letter. Unlike the case for small 

refineries, refiners that receive approved 

small refiner status and subsequently do 

not meet all of the criteria for small 


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25CAA Section 211(o)(2)(A)(ii), as added by 

Section 1501(a) of the Energy Policy Act of 2005. 

refiner status (i.e., cease producing 

gasoline from processing crude oil, 

employ more than 1,500 people or 

exceed the 155,000 bpcd crude oil 

capacity limit) as a result of a merger 

with or acquisition of or by another 

entity, are disqualified as small refiners, 

except in the case of a merger between 

two previously approved small refiners. 

As in other EPA programs, where such 

disqualification occurs, the refiner must 

notify EPA in writing no later than 20 

days following the disqualifying event. 

The Act provides that the Secretary of 

Energy must conduct a study for EPA to 

determine whether compliance with the 

renewable fuels requirement would 

impose a disproportionate economic 

hardship on small refineries. If the 

study finds that compliance with the 

renewable fuels requirements would 

impose a disproportionate economic 

hardship on a particular small refinery, 

EPA is required to extend the small 

refinery’s exemption for a period of not 

less than two additional years. The Act 

also provides that a refiner with a small 

refinery may at any time petition EPA 

for an extension of the exemption for 

the reason of disproportionate economic 

hardship. In accordance with these 

provisions of the Act, the proposed rule 

includes a process by which refiners 

with small refineries may petition EPA 

for an extension of the small refinery 

exemption. As provided in the Act, the 

proposed rule would require EPA to act 

on the petition not later than 90 days 

after the date of receipt of the petition. 

During the initial exemption period 

and any extended exemption periods, 

the gasoline produced by small 

refineries and refineries owned by 

approved small refiners would be 

subject to the renewable fuel standard. 

Under the proposed rule, the 

automatic five year exemption for small 

refineries, and any extended 

exemptions, may be waived upon 

notification to EPA. In waiving its 

exemption, gasoline produced at a small 

refinery would be included in the RFS 

program and would be included in the 

gasoline used to determine a refiner’s 

renewable fuel obligation. If a refiner 

waives the exemption for their small 

refinery or their exemption as a small 

refiner, the refiner would be able to 

separate and transfer RINs like any other 

obligated party. If a refiner does not 

waive the exemption, the refiner could 

still separate and transfer RINs, but only 

for the renewable fuel that the refiner 

itself blends into gasoline (i.e. the 

refiner operates as an oxygenate 

blender). 

b. General Hardship Exemption. In 

recent rulemakings, we have included a 

general hardship exemption for parties 

that could demonstrate severe economic 

hardship in complying with the 

standard. We are proposing not to 

include in the RFS program provisions 

for a general hardship exemption. 

Unlike most other fuels programs, the 

RFS program includes inherent 

flexibility since compliance with the 

renewable fuels standard is based on a 

nationwide trading program, without 

any per gallon requirements, and 

without any requirement that the refiner 

or importer produce the renewable fuel. 

By purchasing RINs, obligated parties 

would be able to fulfill their renewable 

fuel obligation without having to make 

capital investments that may otherwise 

be necessary in order to blend 

renewable fuels into gasoline. We 

believe that sufficient RINs would be 

available and at reasonable prices, given 

that EIA projects that far greater 

renewable fuels will be used than 

required. Given the flexibility provided 

in the RIN trading program, including 

the provisions for deficit carry-over, and 

the fact that the standard is proportional 

to the volume of gasoline actually 

produced, we believe that there likely 

would be no need for a general hardship 

exemption. We request comment on 

whether there is a need to include a 

general hardship exemption in the RFS 

program. 

c. Temporary Exemption Based On 

Unforeseen Circumstances. In recent 

rulemakings, we have also included a 

temporary exemption based on 

unforeseen circumstances. We are 

proposing not to include such an 

exemption in the RFS program. The 

need for such an exemption would 

primarily be based on the inability to 

comply with the renewable fuels 

standard due to a natural disaster, such 

as a hurricane. However, in the event of 

a natural disaster, we believe that the 

volume of gasoline produced by an 

obligated party would also drop, which 

would result in a reduction in the 

renewable fuel requirement. We believe, 

therefore, that unforeseen 

circumstances, such as a hurricane or 

other natural disaster, would not result 

in a party’s inability to obtain sufficient 

RINs to comply with the applicable 

renewable fuels standard. We request 

comment on whether there would be a 

need to include a temporary exemption 

based on unforeseen circumstances, 

and, in particular, circumstances that 

may affect ethanol producers. 

4. What Are the Opt-In and State Waiver 

Provisions Under the RFS Program? 

a. Opt-in Provisions for 

Noncontiguous States and Territories. 

The Act provides that, upon the petition 

of a noncontiguous state or U.S. 

territory, EPA may apply the renewable 

fuels requirements to gasoline produced 

in or imported into that noncontiguous 

state or U.S. territory at the same time 

as, or any time after the effective date of 

the RFS program.25 In granting such a 

petition, EPA may issue or revise the 

RFS regulations, establish applicable 

volume percentages, provide for 

generation of credits, and take other 

actions as necessary to allow for the 

application of the RFS program in a 

noncontiguous state or territory. 

Today’s proposed rule would 

implement this provision of the Act by 

providing a process wherein the 

governor of a noncontiguous state or 

territory may petition EPA to have the 

state or territory included in the RFS 

program. However, we believe that 

approval of the petition would not 

require a showing other than a request 

to be included in the program. The 

petition must be received by EPA on or 

before October 31 for the noncontiguous 

state or territory to be included in the 

RFS program in the next calendar year. 

A noncontiguous state or territory for 

which a petition is received after 

October 31 would not be included in the 

RFS program in the next calendar year, 

but would be included in the RFS 

program in the following year. For 

example, if EPA receives a petition on 

September 1, 2007, the noncontiguous 

state or territory would be included in 

the RFS program beginning on January 

1, 2008. If EPA receives a petition on 

December 1, 2007, the noncontiguous 

state or territory would be included in 

the RFS program beginning January 1, 

2009. We believe that requiring 

petitions to be received by October 31 

would be necessary to allow EPA time 

to make any adjustments in applicable 

standard. The method for recalculating 

the renewable fuels standard to reflect 

the addition of a state or territory that 

has opted into the RFS program is 

discussed in Section III.A. 

Where a noncontiguous state or 

territory opts-in to the RFS program, 

producers and importers of gasoline for 

that state or territory would be obligated 

parties subject to the renewable fuel 

requirements. All refiners, blenders and 

importers who produce or import 

gasoline for use in a state or territory 

that has opted-in to the RFS program 

would be required to count this volume 

of gasoline in determining their 

renewable fuel obligation, and would be 

able to separate RINs from batches of 

renewable fuels used in gasoline that is 

sold or introduced into commerce in the 


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26CAA Section 211(o)(7), as added by Section 

1501 of the Energy Policy Act of 2005. 

27Those blenders who add ethanol to RBOB are 

already regulated under our reformulated gasoline 

regulations. 

state or territory that has opted-in to the 

RFS program. 

Once a petition to opt-in to the RFS 

program is approved by EPA, the state 

or territory would remain in the RFS 

program and be treated as any of the 48 

contiguous states. We request comment 

on the opt-in provisions. 

b. State Waiver Provisions. The 

Energy Act provides that EPA, in 

consultation with the U.S. Department 

of Agriculture (USDA) and the 

Department of Energy (DOE), may waive 

the renewable fuels requirements in 

whole or in part upon a petition by one 

or more states by reducing the national 

quantity of renewable fuel required 

under the Act.26 The Act also outlines 

the basic requirements for such a 

waiver, such as a demonstration that 

implementation of the renewable fuels 

requirements would severely harm the 

economy or environment of a state, a 

region, or the United States, or that 

there is an inadequate domestic supply 

of renewable fuel. 

If EPA approves a state’s petition for 

a waiver of the RFS program, the Act 

stipulates that the national quantity of 

renewable fuel required (Table I.B–1) 

may be reduced in whole or in part. 

This reduction could reduce the 

standard applicable to all obligated 

parties. However, there is no provision 

in the Act that would permit EPA to 

reduce or eliminate any obligations 

under the RFS program specifically for 

parties located within the state that 

petitioned for the waiver. Thus all 

refiners, importers, and blenders located 

in the state would still be obligated 

parties if they produce gasoline. In 

addition, an approval of a state’s 

petition for a waiver may not have any 

impact on renewable fuel use in that 

state, since it would not be a prohibition 

on the sale or consumption of renewable 

fuels in that state. In fact the Act 

prohibits the regulations from restricting 

the geographic areas in which 

renewable fuels may be used. 

Renewable fuel use in the state in 

question would thus continue to be 

driven by natural market forces. 

Given that state petitions for a waiver 

of the RFS program are unlikely to affect 

renewable fuel use in that state, we are 

not proposing regulations providing 

more specificity regarding the criteria 

for a waiver, or the ramifications of 

Agency approval of such a waiver in 

terms of the level or applicability of the 

standard. However, states can still 

submit petitions to the Agency for a 

waiver of the RFS requirements under 

the provision in the Energy Act. We 

request comment on this approach. 

D. How Do Obligated Parties Comply 

With the Standard? 

Under the Act, EPA is to establish a 

renewable fuel standard annually, 

expressed as a percentage of gasoline 

sold or introduced into commerce, that 

will ensure that overall a specified total 

national volume of renewable fuels will 

be used in gasoline in the U.S. The Act 

does not require each obligated party to 

necessarily do the blending themselves 

in order to comply with this obligation. 

The Act envisions a regulatory program 

that would ensure the national volume 

is met as long as a refiner or importer 

ensured that someone used a certain 

volume of renewable fuel, whether it 

was themselves or another party. Under 

the credit trading program required by 

the Act, each obligated party is allowed 

to satisfy its obligations either through 

its own actions or through the transfer 

of credits from others who have more 

than satisfied their individual 

requirements. 

This section describes our proposed 

compliance program. It is based on the 

use of unique renewable identification 

numbers (RINs) assigned to batches of 

renewable fuel by renewable fuel 

producers. These numbers could then 

be sold or traded, and ultimately used 

by any obligated party to demonstrate 

compliance with the applicable 

standard. Excess RINs would be 

identical to the credits envisioned by 

the Act. As described below, we believe 

that our approach is consistent with the 

language and intent of the Act and 

preserves the natural market forces and 

blending practices that keep renewable 

fuel costs to a minimum. 

1. Why Use Renewable Identification 

Numbers? 

Once renewable fuels are produced or 

imported, there is very high confidence 

they will in fact be blended into 

gasoline or otherwise used as motor 

vehicle fuels, except for exports. 

Renewable fuels are not used for food, 

chemicals, or as feedstocks to other 

production processes. In fact the 

denaturant that must be added to 

ethanol is designed specifically to 

ensure that the ethanol can be used only 

as motor vehicle fuel. In discussions 

with stakeholders, it has become clear 

that other renewable fuels, including 

biodiesel and renewable fuels used in 

their neat (unblended) form, likewise 

are not used for anything other than 

fuel. Therefore if a refiner ensures that 

a certain volume of renewable fuel has 

been produced, in effect they have also 

ensured that this volume will be 

blended into gasoline or otherwise used 

as a motor vehicle fuel. It is therefore 

appropriate for EPA to establish the 

obligation for refiners and importers as 

an obligation to ensure that a certain 

volume of renewable fuel has been 

produced. This will ensure that the total 

required volume of renewable fuels will 

be used in the U.S., and as discussed 

below has many benefits as far as 

streamlining the program and 

minimizing disruptions to the current 

marketplace for production, 

distribution, and use of renewable fuels. 

Implementing a program that is based 

on ensuring production of a certain 

volume of renewable fuels requires a 

system of volume accounting and 

tracking of renewable fuels. We propose 

that this system be based on the 

assignment of unique numbers to each 

batch of renewable fuel. These numbers 

would be called Renewable 

Identification Numbers or RINs, and 

would be assigned to each batch by the 

renewable fuel producer or importer. 

The use of RINs would allow the 

Agency to measure and track renewable 

fuel volumes starting at the point of 

their production rather than at the point 

when they are blended into 

conventional fuels. Although an 

alternative approach would be to 

measure renewable fuel volumes as they 

are blended into conventional gasoline 

or diesel, measuring renewable fuel 

volumes at the point of production 

provides more accurate measurements 

that can be easily verified as described 

in Section III.D.1.b below. For instance, 

ethanol producers are already required 

to report their production volumes to 

EIA through Monthly Oxygenate 

Reports. This data would provide an 

independent source for verifying 

volumes. The total number of batches 

and parties involved is also minimized 

in this approach. The total number of 

batches is smallest at the point of 

production, since batches are commonly 

split into smaller ones as they proceed 

through the distribution system to the 

place where they are blended into 

conventional fuel. The number of 

renewable fuel producers is also far 

smaller than the number of blenders. 

Currently there are approximately 100 

ethanol plants and 40 biodiesel plants 

in the U.S., compared with 

approximately 1200 blenders.27

The assignment of RINs to batches of 

renewable fuel at the point of their 

production also allows those batches to 

be identified according to various 

categories important for compliance 


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purposes. For instance, the RIN will 

contain a component that specifies 

whether a batch of ethanol was made 

from cellulosic feedstocks. This RIN 

component will be of particular 

importance for 2013 and beyond when 

the Act specifies a national volume 

requirement for cellulosic biomass 

ethanol. The RIN can also identify the 

Equivalence Value of the renewable fuel 

which will often only be known at the 

point of its production. Finally, the RIN 

can identify the year in which the batch 

was produced, a critical element of 

determining the applicable time period 

within which RINs are valid for 

compliance purposes. 

Production volumes of renewable 

fuels intended for blending into gasoline 

are an accurate surrogate for volumes 

actually blended into gasoline. In 

addition, production volumes of 

renewable fuels capture those renewable 

fuels used as motor vehicle fuel in their 

neat (unblended) form. Thus we believe 

that this approach would allow us to 

account for all renewable fuels 

consumed in the U.S. because 

renewable fuels always end up being 

used as fuel in the U.S. or exported. 

There are also changes that can occur 

at various times throughout the year in 

the volumes of renewable fuel that are 

in storage. These stock changes involve 

the temporary storage of renewable fuel 

during times of excess. However, these 

stock changes always have a net change 

of zero over the long term since there is 

no economic benefit to stockpiling 

renewable fuels. 

Exports of renewable fuel represent 

the only distribution pathway that could 

impair the use of production as a 

surrogate for renewable fuel blending 

into gasoline or other use as a motor 

vehicle fuel. However, we believe that 

our proposed approach can account for 

exports through an explicit requirement 

placed upon exporters (discussed in 

Section III.D.4 below). As a result, we 

are confident that our proposed 

approach satisfies the statutory 

obligation that our regulations impose 

obligations on refiners and importers 

that will ensure that gasoline sold or 

introduced into commerce in the U.S. 

each year will contain the volumes of 

renewable fuel specified in the Act. By 

tracking the amount of renewable fuel 

produced or imported, and subtracting 

the amount exported, we will have an 

accurate accounting of the renewable 

fuel actually consumed as motor vehicle 

fuel in the U.S. Exports of renewable 

fuel are discussed in more detail in 

Section III.D.4. 

a. RINs Serve the Purpose of a Credit 

Trading Program. According to the Act, 

we must promulgate regulations that 

include provisions for a credit trading 

program. A credit trading program 

would allow a refiner that overcomplied 

with its annual RVO to generate credits 

representing the excess renewable fuel. 

The Act stipulates that those credits 

could then be used within the ensuing 

12 month period, or transferred to 

another refiner that had not blended 

sufficient renewable fuel into its 

gasoline to satisfy its RVO. In this way 

the credit trading program would permit 

current blending practices to continue 

wherein some refiners purchase a 

significant amount of renewable fuel for 

blending into their gasoline while others 

do little or none, thus providing a 

means for all refiners to comply with 

the standard. 

Our proposed RIN-based program 

would fulfill all the functions of a credit 

trading program, and thus would meet 

the Act’s requirements. If at the end of 

a compliance period, a party had more 

RINs than it needed to show compliance 

with its renewable volume obligation, 

these excess RINs would serve the 

function of credits, and could be used, 

banked, or traded in the next 

compliance period. RINs could be 

transferred to another party in an 

identical fashion to a credit. However, 

our proposed program provides 

additional flexibility in that it would 

permit all RINs to be transferred 

between parties before they were 

deemed to be in excess of a party’s 

annual RVO at the end of the year. This 

is because a RIN serves two functions: 

it is direct evidence of compliance, and 

after a compliance year is over excess 

RINs serve the function of credits for 

overcompliance. Thus the RIN approach 

has the advantage of allowing real-time 

trading without having to wait until the 

end of the year to determine excess. 

As in other motor vehicle fuels credit 

programs, we are also proposing that 

any renewable producer that generates 

RINs must use an independent auditor 

to conduct annual reviews of the party’s 

renewable production, RIN generation, 

and RIN transactions. These reviews are 

called ‘‘attest engagements,’’ because the 

auditor is asked to attest to the validity 

of the regulated party’s credit 

transactions. For example, the 

reformulated gasoline program requires 

attest engagements for refiners and 

importers, and downstream oxygenate 

blenders to verify the underlying 

documentation forming the basis of the 

required reports (40 CFR part 80, 

subpart F). In the case of RIN 

generation, the auditor would be 

required to verify that the number of 

RINs generated matched the volume 

renewables produced, that any extra 

value RINs were appropriately 

generated, and that RINs numbers were 

properly assigned and documented on 

the renewable fuel PTDs as required by 

the regulations. 

b. Alternative Approach To Tracking 

Batches. If we did not implement a RINbased system for uniquely identifying, 

measuring, and tracking batches of 

renewable fuel, the RFS program would 

necessarily require that we measure 

renewable fuel volumes at the point in 

the distribution system where they are 

actually blended into conventional 

gasoline or diesel or used in their neat 

form as motor vehicle fuel. However, 

this alternative approach would create a 

number of significant problems. 

First, the parties obligated to meet the 

standard (refiners, importers, and 

blenders of gasoline) are often not the 

parties who produce renewable fuel or 

blend renewable fuels such as ethanol 

into gasoline. This separation would 

require a mechanism for obligated 

parties to obtain credit for renewable 

fuels blended by non-obligated parties. 

Generally, this would be done through 

contract management. Unfortunately, 

there might be an incentive to 

exaggerate the volumes of renewable 

fuel blended and thus exaggerate the 

number of credits generated. This 

alternative approach might also create 

opportunities for double-counting 

batches of renewable fuel, either 

intentionally or unintentionally. 

Second, as described in Section I, one 

of our guiding principles in designing 

the RFS compliance and trading 

program was to ensure that existing 

business practices could continue to the 

degree possible. With the alternative 

approach described above, some refiners 

might have to significantly change their 

business or production practices to take 

greater control of ethanol blending and, 

therefore, the mechanism for 

compliance with the RFS program. For 

instance, a refiner could establish a 

contract with an oxygenate blender, 

securing the rights to the credits that 

oxygenate blender creates. A refiner 

might also decide to take on more 

blending responsibilities itself. 

However, these approaches would run 

counter to the normal business practices 

that keep fuel costs to a minimum, and 

would thus have a tendency to increase 

fuel costs. 

Third, tracking renewable fuel 

volumes to identify the date, place, and 

volume of blending into gasoline would 

maximize the number of parties 

involved, overly complicating the 

compliance system. There are 

approximately 1200 blenders in the U.S. 

who blend ethanol into gasoline, in 

addition to those that blend biodiesel 

into conventional diesel fuel. Many of 


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28Mono-alkyl esters made from plant or animal 

oils or fats, and which have been registered with the 

EPA for use in highway motor vehicles. 

29RINs represent actual gallons in a batch when 

the RIN is a standard-value RIN. Extra-value RINs 

represent additional gallons in cases where the 

Equivalence Value is greater than Equivalence 

Value is greater than 1.0. See further discussion in 

Section III.D.2.b. 

these parties are small businesses that 

have not been regulated in an EPA fuel 

program before. Enforcement efforts 

would necessarily be placed on them, 

imposing upon them the primary 

burden of accurately documenting the 

volumes of renewable fuel that are 

blended into gasoline even though they 

are not obligated for meeting the 

standard. In contrast, under our 

proposed program blenders would only 

need to keep records of RINs acquired 

with batches. It is our expectation that 

in most cases obligated parties will 

separate the RINs from batches before 

those batches are transferred to 

blenders. Therefore, blenders will only 

have to keep records of RINs for a 

fraction of the renewable fuel produced. 

Fourth, a focus on the point of 

blending would not address renewable 

fuels that need not be blended into 

gasoline or diesel. For example, 

although biodiesel 28 is generally 

blended into conventional diesel before 

being used as fuel, it can be used in its 

neat form (B100). If volumes of 

renewable fuel were counted only when 

blending into conventional fuel 

occurred, then B100 could never be 

claimed by an obligated party for RFS 

compliance purposes. The same would 

be true of other renewable fuels which, 

although not produced in significant 

quantities today, could play a more 

substantial role in the renewable fuels 

market in the future. Examples of these 

other unblended renewable fuels could 

include renewable diesel made by 

hydrotreating plant oils instead of 

transesterifying them, or a renewable 

gasoline made from a Fischer-Tropsch 

process applied to biogas. 

Finally, a focus on the point of 

blending would not permit cellulose 

biomass ethanol to be distinguished 

from other forms of ethanol. Since the 

Act requires that 250 million gallons of 

cellulosic biomass ethanol be produced 

starting in 2013, this alternative 

approach would require tracking of 

batches of renewable fuel at the 

producer level. 

In a blender-based approach, then, 

special exceptions would need to be 

developed in order for these neat fuels 

to be available for RFS program 

compliance purposes. For instance, a 

system of measuring and tracking neat 

renewable fuel volumes at the point of 

production would likely be necessary. 

This would be no different from a RINbased program for such fuels. 

Our proposed RIN-based program 

would address all these concerns 

automatically by shifting the focus of 

accounting to the point of production 

rather than blending. As a result we 

believe that a blender-based alternative 

approach described above is inferior to 

our proposed program. We request 

comment on a RIN-based system for 

uniquely identifying, measuring, and 

tracking batches of renewable fuel for 

compliance purposes. 

2. Generating RINs and Assigning Them 

to Batches 

a. Form of Renewable Identification 

Numbers. Each RIN would be generated 

by the producer or importer of the 

renewable fuel and would uniquely 

identify not only a specific batch, but 

also every gallon in that batch. The RIN 

would consist of a 34-character code 

having the following form: 

RIN: YYYYCCCCFFFFFBBBBB 

RRDKSSSSSSEEEEEE 

Where: 

YYYY = Calendar year of production or 

import 

CCCC = Company ID 

FFFFF = Facility ID 

BBBBB = Serial batch number 

RR = Code identifying the Equivalence Value 

D = Code identifying cellulosic biomass 

ethanol or waste-derived ethanol 

K = Code identifying extra-value RINs 

SSSSSS = Start of volume block. 

EEEEEE = End of volume block. 

Some examples of RINs are given in 

Section III.E.1.b. 

The company and facility IDs would 

be assigned by the EPA as part of the 

registration process as described in 

Section IV.B. The serial batch number 

would be chosen by the producer and 

would generally be a sequential value 

starting with 000001 at the beginning of 

each year. We have chosen five digits 

for the serial batch number to allow for 

facilities that produce up to a hundred 

thousand batches per year. However, we 

request comment on whether four digits 

would be sufficient. 

The RR, D, and K codes would 

together describe the nature of the 

renewable fuel and the RINs that were 

generated to represent it. The RR code 

would simply represent the Equivalence 

Value for the renewable fuel, multiplied 

by 10 to eliminate the decimal place 

inherent in Equivalence Values. 

Equivalence Values form the basis for 

the total number of RINs that can be 

generated for a given volume of 

renewable fuel, and are described in 

Section III.B.4. 

The D code would identify cellulosic 

biomass ethanol batches as such. Since 

the Act requires that a minimum of 250 

million gallons of cellulosic biomass 

ethanol be consumed starting in 2013, 

obligated parties will need to be able to 

distinguish RINs representing cellulosic 

biomass ethanol from RINs representing 

other types of renewable fuel. This 

requirement is discussed in more detail 

in Section III.A. 

The K code would be used to specify 

whether the RIN represents actual 

gallons of renewable fuel, or instead 

represents extra-value RINs. Extra-value 

RINs arise only in cases where the 

Equivalence Value is greater than 1.0. 

Extra-value RINs are discussed in more 

detail in Section III.D.2.b below. 

The RIN also contains two values that 

together identify the total number of 

gallons in a batch as well as uniquely 

identifying each gallon in that batch.29

When RINs are first assigned to a batch 

of renewable fuel by its producer or 

importer, the volume start block for that 

batch will in general be 1 (i.e. SSSSSS 

will have a value of 000001). The 

volume block end is the total volume 

number of gallons in the batch (i.e. for 

a 10,000 gallon batch, EEEEEE would 

have a value of 010000). Thus the single 

RIN assigned to the batch is in effect 

shorthand for all the unique RINs 

assigned to every individual gallon in 

the batch. We propose that the number 

of gallons in a batch be standardized to 

60 °F to avoid RIN assignment problems 

associated with volume swell due to 

temperature changes. We have assigned 

six digits to the volume block codes to 

allow batches up to a million gallons in 

size. We request comment on whether a 

fewer number of digits for the SSSSSS 

and EEEEEE codes would be sufficient. 

Since ‘‘RIN’’ can refer to either the 

number assigned to the batch or the 

number representing each gallon in that 

batch, we propose distinguishing 

between a batch-RIN and a gallon-RIN. 

A batch-RIN would be the multicharacter code written on a product 

transfer document associated with a 

batch of renewable fuel. The batch-RIN 

would include SSSSSS and EEEEEE 

values identifying every (volumestandardized) gallon in the batch, each 

of which would be assigned its own 

gallon-RIN. A gallon-RIN would have 

identical SSSSSS and EEEEEE values 

identifying one gallon in a batch. 

Our approach to RINs permits the 

batch to be divided into smaller batches 

at any point in the distribution system 

while maintaining the assignment of 

unique RINs. For instance, if a 1000 

gallon batch of renewable fuel is 

divided into two 500 gallon batches, the 

volume block start and block end values 


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30As described in Section III.E below, we are 

proposing that standard-value RINs would be 

assigned to the batch of renewable fuel they 

represent and would be required to be transferred 

with the batch. 

in the original batch-RIN would change 

to reflect the batch split. The batch-RIN 

for the first 500 gallon batch would have 

an SSSSSS value of 000001 and an 

EEEEEE value of 000500, while the 

second 500 gallon batch would have an 

SSSSSS value of 000501 and an EEEEEE 

value of 001000. Additional batch splits 

would be handled similarly. More 

discussion of batch splits is provided in 

Section III.E.1.b.i. 

b. Generating Extra-Value RINs. In 

general, there is a one-to-one 

correspondence between gallon-RINs 

and physical gallons of renewable fuel 

in a batch. For instance, a 10,000 gallon 

batch of renewable fuel would be 

assigned 10,000 gallon-RINs, and the 

batch-RIN would contain volume block 

start and volume block end values 

summarizing the 10,000 gallon-RINs. 

However, under certain circumstances 

RINs may be generated in addition to 

those that represent the volume of 

renewable fuel actually produced. This 

would occur in cases where the 

Equivalence Value of the renewable fuel 

in question is greater than 1.0. 

Renewable fuel Equivalence Values are 

discussed in Section III.B.4. 

If a renewable fuel has an Equivalence 

Value greater than 1.0, the incremental 

value above 1.0 can be used to generate 

‘‘extra-value’’ RINs. For instance, the 

Equivalence Value for biodiesel shown 

in Table III.B.4–1 is 1.5. If a biodiesel 

producer made a 1000 gallon batch of 

biodiesel, 1000 standard-value gallonRINs would be assigned to the batch and 

an additional 500 extra-value gallonRINs could also be generated. 

All the RINs generated to represent a 

batch of renewable fuel would contain 

the same RR code representing the 

Equivalence Value of the renewable 

fuel. However, extra-value RINs would 

be treated differently from standardvalue RINs in two ways. First, the extravalue RINs would include a K code that 

identifies them as extra-value RINs, 

distinguishing them from standardvalue RINs that represent actual gallons 

of renewable fuel. Second, extra-value 

RINs would not be required to be 

transferred along with the batch of 

renewable fuel as it moves through the 

distribution system.30 Rather, an extravalue RINs could be transferred as an 

independent commodity by the 

producer. This approach would provide 

an incentive for producers to make 

renewable fuels that have a 

comparatively greater value in terms of 

meeting the volume requirements of the 

RFS program. Also, by not requiring 

extra-value RINs to be assigned to the 

batches of renewable fuel that they 

represent, batches of renewable fuel can 

continue to have a one-to-one 

correspondence between gallon-RINs 

assigned to the batch and the number of 

physical gallons in that batch. This 

approach can greatly simplify the 

transfer of RINs with batches 

particularly when batch splits occur. 

c. Cases in Which RINs Are Not 

Generated. Although in general every 

(temperature-standardized) gallon of 

renewable fuel produced or imported 

would be assigned a gallon-RIN, there 

are several cases in which a RIN may 

not be assigned. For instance, if a 

renewable fuel producer also operated 

as an exporter, any renewable fuel that 

it produced and exported would not 

need to be assigned a RIN. Since the 

gasoline that is blended with renewable 

fuels under the RFS program must be 

‘‘sold or introduced into commerce’’

within the U.S., renewable fuels that are 

exported cannot be claimed by an 

obligated party for compliance 

purposes, and therefore would not need 

to be assigned a RIN. Exports of 

renewable fuel are discussed further in 

Section III.D.4. 

Another case in which a RIN may not 

be assigned to a batch of renewable fuel 

would be if the renewable fuel was 

consumed within the confines of the 

production facility where it was made. 

RINs under today’s proposal would be 

assigned to renewable fuel when it 

leaves the production facility. So long as 

renewable fuel remained at the 

production facility, it would not need to 

be assigned a RIN. 

A third case in which some renewable 

fuel would not be assigned a RIN would 

occur for small volume producers. We 

are proposing that renewable fuel 

producers who produce less than 10,000 

gallons in a year would not be required 

to generate RINs or assign them to 

batches. If they chose to register as a 

renewable fuel producer under the RFS 

program, however, they would be 

subject to all the regulatory provisions 

that apply to all producers, including 

the requirement to assign RINs to 

batches. We request comment on the 

10,000 gallon threshold. 

A fourth case in which some 

renewable fuel would not be assigned a 

RIN could occur when a gasoline or 

diesel blending component is only 

partially derived from a renewable 

source. In such cases the Equivalence 

Value associated with the renewable 

fuel would be less than 1.0, indicating 

that it is produced by combining a 

renewable fuel with a non-renewable 

fossil fuel. For instance, ethyl tertiary 

butyl ether (ETBE) is made from 

combining ethanol with isobutylene. 

The ethanol is generally from corn, and 

the isobutylene is generally from 

petroleum. Equivalence Values are 

discussed in Section III.B.4. In this 

situation only a fraction of the gallons 

of renewable fuel produced would be 

assigned a RIN in proportion to its 

Equivalence Value, with the remaining 

gallons not being assigned a RIN. 

Finally, a renewable fuel whose 

energy content is less than that of 

ethanol might also be assigned an 

Equivalence Value less than 1.0, and as 

a result fewer gallon-RINs would be 

assigned to a batch than physical 

gallons in that batch. For example, 

methanol made from biogenic methane 

(biogas) for use in a methanol vehicle 

would have an energy content less than 

that for ethanol. Although methanol is 

currently used as a fuel in only very 

small quantities, if it was produced from 

renewable feedstocks it would have an 

Equivalence Value less than 1.0. 

If a renewable fuel has a Equivalence 

Value less than 1.0, then gallon-RINs 

could only be assigned to a portion of 

the batch. The number of gallons within 

a batch that could be assigned a RIN 

would be calculated from the following 

formula: 

Va = EV × Vs

Where: 

Va = Volume of the batch that is assigned a 

RIN, in gallons (rounded to the nearest 

whole gallon). 

EV = Equivalence Value for the renewable 

fuel in question (<1.0). 

Vs = Total volume of the batch standardized 

to 60 °F, in gallons. 

In such cases, the volume block start 

and volume block end values in the 

batch-RIN (i.e. SSSSSS and EEEEEE 

codes described in Section III.D.2.b) 

would not exactly correspond to the 

volume of the batch. Instead, they 

would cover the first portion of the 

batch. The remaining portion of the 

batch would not be assigned a RIN. For 

clarity in regards to batch splits, a party 

could assign the gallon-RINs to the firstout gallons of the batch. Thus if a batch 

split occurred, every gallon drawn out 

of the original batch to form a new, 

smaller batch would be assigned a 

gallon-RIN, up to the point when all the 

available gallon-RINs were assigned to 

the new batch. Any additional gallons 

drawn out of the original batch, or left 

with the original batch, would have no 

associated RINs. However, we are not 

requiring this approach but only offer it 

as one possibility. We propose that 

parties that have ownership or custody 

of batches of renewable fuel have the 

discretion to split batches and their 

associated RINs in any way, subject to 


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certain restrictions. Batch splits are 

discussed in more detail in Section 

III.E.1.b.i. 

3. Calculating and Reporting 

Compliance 

Under our proposed program, RINs 

would form the basis of the volume 

accounting and tracking system that 

would allow each obligated party to 

demonstrate that they had discharged 

their renewable fuel obligation. This 

section describes how the compliance 

process using RINs would work. Our 

proposed approach to the distribution 

and trading of RINs is covered 

separately in Section III.E below. 

a. Using RINs to Meet the Standard. 

Under our proposed program, each 

obligated party would determine its 

Renewable Volume Obligation (RVO) 

based on the applicable percentage 

standard and its annual gasoline volume 

as described in Section III.A.4. The RVO 

represents the volume of renewable fuel 

that the obligated party must ensure is 

produced for use in the U.S. in a given 

calendar year. Since the nationwide 

renewable fuel volumes shown in Table 

I.B–1 are required by the Act to be 

consumed in whole calendar years, the 

RVO for each obligated party is likewise 

an obligation that is calculated on an 

annual basis. 

Since our proposed program uses 

RINs as a measure of the amount of 

renewable fuel used as motor vehicle 

fuel that is sold or introduced into 

commerce within the U.S., obligated 

parties would meet their RVO through 

the accumulation of RINs. In so doing, 

they would effectively be causing the 

renewable fuel represented by the RINs 

to be consumed as motor vehicle fuel. 

Obligated parties would not be required 

to physically blend the renewable fuel 

into gasoline or diesel fuel themselves. 

The accumulation of RINs would be the 

means through which each obligated 

party would show compliance with its 

RVO, and thus with the renewable fuel 

standard. 

For each calendar year, each obligated 

party would be required to submit a 

report to the Agency documenting the 

RINs it acquired, and showing that the 

sum of all gallon-RINs acquired were 

equal to or greater than its RVO. This 

reporting is discussed in more detail in 

Section IV. In the context of 

demonstrating compliance, all gallonRINs would have the same compliance 

value, i.e. there would be no distinction 

between standard-value RINs and extravalue RINs for compliance purposes. 

The Agency could then verify that the 

RINs used for compliance purposes 

were valid by simply comparing RINs 

reported by producers to RINs claimed 

by obligated parties. We could also 

verify simply that any given gallon-RIN 

was not double-counted, i.e., used by 

more than one obligated party for 

compliance purposes. In order to be able 

to identify the cause of any doublecounting, however, additional 

information would be needed on RIN 

transactions as discussed in Section IV. 

If an obligated party has acquired 

more RINs than it needs to meet its 

RVO, then in general it could retain the 

excess RINs for use in complying with 

its RVO in the following year, or transfer 

the excess RINs to another party. The 

conditions under which this would be 

allowed are determined by the valid life 

of a RIN, described in more detail in 

Sections III.D.3.b below. If alternatively 

an obligated party has not acquired 

sufficient RINs to meet its RVO, then 

under certain conditions it could 

carryover a deficit into the next year. 

Deficit carryovers are discussed in more 

detail in Section III.D.3.d. 

The regulations would prohibit any 

party from creating or transferring 

invalid RINs. Invalid RIN could not be 

used in demonstrating compliance 

regardless of the good faith belief of a 

party that the RINs were valid. These 

enforcement provisions are necessary to 

ensure the RFS program goals are not 

compromised by illegal conduct in the 

creation and transfer of RINs. 

As in other motor vehicle fuel credit 

programs, the regulations would address 

the consequences if an obligated party 

was found to have used invalid RINs to 

demonstrate compliance with its RVO. 

In this situation, the refiner or importer 

that used the invalid RINs would be 

required to deduct any invalid RINs 

from its compliance calculations. The 

refiner or importer would be liable for 

violating the standard if the remaining 

number of valid RINs was insufficient to 

meet its RVO, and the obligated party 

might be subject to monetary penalties 

if it used invalid RINs in its compliance 

demonstration. In determining what 

penalty was 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 punitive component. 

Although an obligated party would be 

liable under our proposed program for 

a violation if it used invalid RINs for 

compliance purposes, we would 

normally look first to the generator/ 

seller of the invalid RINs both for 

payment of penalty and to procure 

sufficient valid RINs to offset the invalid 

RINs. However, if that party was found 

to be out of business, then attention 

would turn to the obligated party who 

would have to obtain sufficient valid 

RINs to offset the invalid RINs. 

As for RIN generators, we are 

proposing that obligated parties be 

required to conduct attest engagements 

for the volume of gasoline they produce 

and the number of RINs procured to 

ensure compliance with their RVO. In 

most cases, this should amount to little 

more than is already required under 

existing EPA gasoline regulations. In the 

case of renewable fuel exporters, the 

attest engagement would verify the 

volume of renewable fuel exported and 

therefore the magnitude of their RVO. 

Attest engagement reports would be 

submitted to the party that 

commissioned the engagement, and to 

EPA. 

b. Valid Life of RINs. The Act requires 

that renewable fuel credits be valid to 

show compliance for 12 months as of 

the date of generation. This section 

describes our proposed interpretation of 

this provision in the context of a RINbased program. We also discuss some 

possible alternative interpretations that 

we have considered. 

As described in Section III.D.1.a, 

credits 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, compliance would be 

determined shortly after the end of the 

year, and credits would be identified at 

that time. Compliance is typically 

demonstrated by submitting a 

compliance demonstration to EPA. 

Given the 12-month life of a credit as 

stated in the Act, we interpret this 

provision as meaning that credits would 

only be valid for compliance purposes 

for the following compliance year. 

Hence if a refiner or importer 

overcomplied with their 2007 obligation 

they would generate credits that could 

be used to show compliance with the 

2008 compliance obligation, but the 

credits could not be used to show 

compliance for later years. 

The Act’s limit on credit life helps 

balance the risks between the needs of 

renewable fuel producers and obligated 

parties. Producers are currently making 

investments in expanded production 

capacity on the expectation of a 

statutorily guaranteed minimum market. 

Under the market conditions we are 

experiencing today that make ethanol 

use more economically attractive, the 

annual volume requirements in the RFS 

program will not drive consumption of 

renewable fuels. However, if the price of 


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31The use of previous-year RINs for current year 

compliance purposes would also be limited by the 

20 percent RIN rollover cap under today’s proposal. 

However, as discussed in the next section, we 

believe that this proposed cap will still provide a 

significant amount of flexibility to obligated parties. 

crude oil dropped significantly and the 

use of ethanol in gasoline became less 

economically attractive, obligated 

parties could use stockpiled credits to 

comply with the program requirements. 

As a result, demand for renewable fuel 

could fall well below the RFS program 

requirements, and many producers 

could find themselves with a stranded 

investment. The 12 month valid life 

limit for credits minimizes the potential 

for this type of result. 

For obligated parties, the 12 month 

valid life for credits provides a window 

within which parties who do not meet 

their renewable fuel obligation through 

their own physical use of renewable fuel 

can obtain credits from other parties 

who have excess. This critical aspect of 

the credit trading system allows the 

renewable fuels market to continue 

operating according to natural market 

forces, avoiding the possibility that 

every single refiner would need to 

purchase renewable fuel for blending 

into its own gasoline. But the 12 month 

life also provides a window within 

which banking and trading can be used 

to offset the negative effects of 

fluctuations in either supply of or 

demand for renewable fuels. For 

instance, if crude oil prices were to drop 

significantly and thus natural market 

demand for ethanol likewise fell, the 

RFS program would normally bring 

demand back up to the minimum 

required volumes shown in Table I.B–1. 

But in this circumstance, the use of 

ethanol in gasoline would be less 

economically attractive, since demand 

for ethanol would not be following price 

but rather the statutorily required 

minimum volumes. As a result, the 

price of RINs, and thus ethanol blends, 

could spike above the levels that would 

exist if no minimum required volumes 

existed. The 12 month valid life creates 

some flexibility in the market to help 

mitigate these potential price spikes. 

The renewable fuels market could also 

experience a significant drop in supply 

if, for instance, a drought were to limit 

the production of the feedstocks needed 

to produce renewable fuel. Obligated 

parties could use banked credits to 

comply rather than carry a deficit into 

the next year. 

In the context of our proposed RINbased program, we are able to 

accomplish the same objective as the 

Act’s 12 month life of credits 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 the 

following year. RINs not used for 

compliance purposes in the year in 

which they were generated would by 

definition be in excess of the RINs an 

obligated party needed in that year, 

making excess RINs equivalent to 

credits. Excess RINs would be valid for 

compliance purposes in the year 

following the one in which they initially 

came into existence.31 RINs not used 

within their valid life would expire. 

This would satisfy the Act’s 12 month 

duration for credits. 

Thus we propose that every RIN be 

valid for the calendar-year compliance 

period in which it was generated, or the 

following year. If a RIN was created in 

one year but was not used by an 

obligated party to meet its RVO for that 

year, the RIN could be used for 

compliance purposes in the next year 

(subject to certain provisions to address 

RIN rollover as discussed below). If, 

however, a RIN was created in one year 

and was not used for compliance 

purposes in that year or in the next year, 

it would expire. 

There are alternative approaches that 

could be taken to establishing the valid 

life of a RIN. For instance, excess RINs 

could be deemed to be generated not at 

the end of an annual compliance period, 

but rather on the date that an obligated 

party must submit its annual report to 

the Agency (February 28 as described in 

Section IV.A.2). In this case the 12- 

month valid life could extend into the 

following calendar year. As described 

above, the fact that compliance is 

determined on an annual basis means 

that RINs that are valid for any portion 

of a calendar year should be available 

for demonstrating compliance with that 

year’s compliance obligation. Under this 

alternative approach, RINs would be 

valid for three full compliance periods: 

the calendar year in which the original 

RIN came into existence, the following 

year during which it was deemed to be 

in excess of an obligated party’s RVO, 

and a third year within which the 12 

month valid life expired. We do not 

believe that this interpretation is most 

consistent with the Act’s purposes. This 

could allow a given year’s exceptional 

overcompliance to effectively reduce 

required renewable fuel volumes for two 

years in the future. We do not believe 

that this would promote the best 

balance between allowing flexibility for 

obligated parties while also increasing 

the use of renewable fuels annually. 

Another possible approach to RIN life 

would be to interpret the Energy Act’s 

12-month credit life provision as 

applying retrospectively, not 

prospectively. Under this approach, the 

12-month timeframe in the Act would 

be interpreted to refer to the calendar 

year within which a credit was 

generated. If excess RINs were deemed 

to be such on December 31, then under 

this alternative approach no RINs could 

be used for compliance purposes 

beyond the year in which they 

originally came into existence. 

However, the Act explicitly indicates 

that obligated parties may either use the 

credits they have generated or transfer 

them. For a party to be able to use 

credits generated, such credit use must 

necessarily occur in a compliance year 

other than the one in which the credit 

was generated. Thus we believe that it 

is appropriate for all RINs to be valid for 

the year in which they were generated 

and the following calendar year. In 

comparison to a single-year valid life for 

RINs, our proposed approach provides 

some additional compliance flexibility 

to obligated parties as they make efforts 

to acquire sufficient RINs to meet their 

RVOs each year. This flexibility will 

have the effect of keeping fuel costs to 

a minimum. 

We recognize that the language of the 

Act regarding credit valid life is not 

unequivocal. However, we believe that 

an interpretation leading to a valid life 

of one year after the year in which the 

RIN was generated is most consistent 

with the program as a whole. The record 

of the development of this legislation 

does not provide a clear indication to 

the contrary. In fact, while some 

stakeholders have argued that the 

Energy Act could have been written to 

explicitly allow a valid life of multiple 

years if that had been Congress’ intent, 

we believe it could likewise have been 

written to explicitly limit the valid life 

to the year in which the renewable fuel 

was produced if that had been its clear 

intent. Therefore, the interpretation of 

the valid life language in the Act must 

be established in the context of the 

statutory requirements for the full RFS 

program and the practical implications 

of its implementation. 

One possible objection to our 

proposed approach is that the use of 

RINs generated in one compliance 

period to satisfy obligations in a 

subsequent compliance period could 

result in less renewable fuel used in a 

given year than is set forth in the 

statute. However, the language in the 

Act shows that Congress clearly 

intended a credit program that provided 

a degree of implementation flexibility. 

For instance, the deficit carryover 

provision allows any obligated party to 

fail to meet its RVO in one year if it 

meets the deficit and its RVO in the next 

year. If many obligated parties took 

advantage of this provision, it could 


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result in the nationwide total volume 

obligation for a particular calendar year 

not being met. In a similar fashion, the 

statutory requirement that every gallon 

of cellulosic biomass ethanol be treated 

as 2.5 gallons for the purposes of 

compliance means that the annually 

required volumes of renewable fuel 

could be met in part by virtual, rather 

than actual, volumes. Finally, the 

calculation of the renewable fuel 

standard is based on projected 

nationwide gasoline volumes provided 

by EIA (see Section III.A). If the 

projected gasoline volume falls short of 

the actual gasoline volume in a given 

year, the standard will fail to create the 

demand for the full renewable fuel 

volume required by the Act for that 

year. The Act contains no provision for 

correcting for underestimated gasoline 

volumes. 

We request comment on the valid life 

of RINs, including our proposed 

approach in which RINs would be valid 

for the year generated or the following 

year, and the alternative approaches in 

which RINs would be valid for more or 

less time than under our proposal. 

c. Cap on RIN Use to Address 

Rollover. As described in Section 

III.D.3.b above, we are proposing that 

RINs be valid for compliance purposes 

for the calendar year in which they were 

generated or the following year. We 

believe that this approach is most 

consistent with the Act’s prescription 

that credits be valid for compliance 

purposes for 12 months as of the date of 

generation. Our proposed approach is 

intended to address both the risk taken 

by producers expecting a guaranteed 

demand to cover their expanded 

production capacity investments and 

the risk taken by obligated parties who 

need a guaranteed supply in order to 

meet their regulatory obligations under 

this program. 

However, the use of previous year 

RINs to meet current year compliance 

obligations does create an opportunity 

for effectively circumventing the valid 

life limit for RINs. 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 example below 

illustrates the issue. 

TABLE III.D.3.c–1.—Example of RIN Rollover Issue 

[Billion RINs] 

Available RINs Compliance Determination 

Required 

under RFSa

RINs generated b Excess Previous 

year RINs 

Additional 

RINs needed 

New excess 

RINs generated 

2007 ................................................................................. 4.7 5.2 0.5 0.0 4.7 0.5 

2008 ................................................................................. 5.4 6.0 0.6 0.5 4.9 1.1 

2009 ................................................................................. 6.1 6.9 0.8 1.1 5.0 1.9 

aEquivalent to the required volumes shown in Table I.B–1. bOne possible production volume scenario based on EIA projections in their Annual Energy Outlook 2006. 

In this example, there are 0.5 billion 

more RINs available for compliance year 

2007 than are needed to comply with 

the RFS program requirements. Since 

these RINs are not used in the year in 

which they are generated (2007), they 

can be used for compliance purposes in 

the following year (2008). If they are not 

used in 2008, they will expire. 

In 2008, 0.6 billion more RINs come 

into existence than are needed to meet 

the 2008 requirements. This should 

mean that there are 0.6 billion more 

RINs available than are needed to 

comply with the RFS program 

requirements for 2008, and thus 0.6 

billion RINs should be carried into 

2009. However, since there are also 0.5 

billion RINs available from the previous 

year which can be used for compliance 

purposes in 2008, this permits the 

generation of 0.5 new excess RINs in 

2008 if all the 2007 RINs are used to 

demonstrate compliance in 2008. Thus 

there are in fact 1.1 billion excess RINs 

generated in 2008 rather than only 0.6 

billion, and they can all be used for 

compliance purposes in 2009. In 

summary, the excess RINs from 2007 

were used to generate new excess RINs 

in 2008, and in effect (though not by 

record) the excess RINs from 2007 can 

be used for compliance purposes in 

2009, a year after they should have 

expired. Thus excess RINs have ‘‘rolled 

over’’ multiple years. 

The rollover issue essentially could 

make the applicable valid life for RINs 

virtually meaningless in practice. Even 

though individual RINs technically 

could only be used for compliance 

purposes for the year generated and the 

following year, in practice obligated 

parties could use previous-year RINs to 

generate new excess current-year RINs 

which could then be carried into the 

following year. This could continue for 

every year in which the volume of 

renewable fuel produced in a given year 

exceeds the RFS requirements for that 

year, up to limit of 100 percent of the 

standard for that year. The net result is 

that the RFS program could operate as 

if there was virtually no valid life limit 

for RINs at all. 

RIN rollover also undermines the 

ability of a limit on credit life to 

guarantee a market for renewable fuels. 

As described in Section III.D.3.b, if the 

natural market demand for ethanol was 

higher than the volumes required under 

the RFS program for several years in a 

row, as may occur in practice, obligated 

parties could amass RINs that, in the 

extreme, could be used entirely in lieu 

of actually demanding ethanol in some 

subsequent year. 

Some stakeholders do not perceive a 

problem with the RIN rollover issue. 

They point to the need for maximum 

flexibility in responding to fluctuations 

in the market, and they are primarily 

concerned about potential supply 

problems. For instance, if a drought 

were to reduce the availability of corn 

for ethanol production, there may 

simply not be sufficient RINs available 

for compliance purposes. A drought 

situation actually occurred in 1996, and 

as a result 1996 ethanol production was 

21% less than it had been in 1995. In 

1997, production had not even returned 

to the 1995 levels. Although the Agency 

has the authority to waive the required 

renewable fuel volumes in whole or in 

part in the event of inadequate domestic 

supply, this can occur only on petition 

by one or more states, and then only 

after consultation with both the 

Department of Agriculture and the 

Department of Energy. Obligated parties 

have expressed concern that such a 

waiver would not occur in a timely 

fashion. The availability of excess 

previous-year RINs would thus provide 

compliance certainty in the event that 

the supply of current-year RINs falls 

below the RFS program requirements 


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and the Agency does not waive any 

portion of the program requirements. 

We believe that the rollover issue can 

and should be addressed. The Act’s 

provision regarding the valid life of 

credits is clearly intended to obtain the 

benefits associated with a limited credit 

life. Any program structure in which 

some RINs have a de facto infinite life, 

regardless of the technical life of 

individual RINs, does not appropriately 

achieve the benefits expected from the 

Act’s provision regarding the 12-month 

life of credits. The authority to establish 

a credit program and to implement a 

limited life for credits includes the 

authority to limit actions that have the 

practical effect of circumventing this 

limited credit life. 

To be consistent with the Act, we 

believe that the rollover issue should be 

addressed in our regulations. However, 

we also believe that the limits to 

preclude such unhindered rollovers 

should not preclude all previous-year 

RINs from being used for current-year 

compliance. To accomplish this, we 

must restrict the number of previousyear RINs that can be used for current 

year compliance. We considered a 

number of possible approaches for 

accomplishing this, some of which are 

discussed below. After consultation 

with stakeholders, we decided that the 

best approach would be to place a 

percentage cap on the amount of an 

obligated party’s Renewable Volume 

Obligation (RVO) that can be met using 

previous-year RINs. We are proposing 

that this cap be set at 20 percent. Thus 

each obligated party would be required 

to use current-year RINs to meet at least 

80 percent of its RVO, with a maximum 

of 20 percent being derived from 

previous-year RINs. The cap would not 

be effective until compliance year 2009, 

since no rollover is possible in years 

2007 or 2008. 

Any previous-year RINs that an 

obligated party may have that are in 

excess of the 20 percent cap could be 

traded to other obligated parties that 

need them. If the previous-year RINs in 

excess of the 20 percent cap were not 

used by any obligated party for 

compliance, they would expire. The net 

result would be that, for the market as 

a whole, no more than 20 percent of a 

given year’s renewable fuel standard 

could be met with RINs from the 

previous year. 

Furthermore, we believe that the 20 

percent cap provides 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 the 

Act. We believe this approach also 

provides the certainty all parties desire 

in implementing the program. The same 

cap would apply equally to all obligated 

parties, and the cap would be the same 

for all years, providing certainty on 

exactly how obligated parties must 

comply with their RVO going out into 

the future. A 20 percent cap would be 

readily enforceable with minimal 

additional program complexity, as each 

obligated party’s annual report would 

simply provide separate listings of 

previous-year and current-year RINs to 

establish that the cap had not been 

exceeded. A 20 percent cap would have 

no impact on who would own RINs, 

their valid life, or any other regulatory 

provision regarding compliance. 

Rather than employing a fixed 20 

percent cap, we also considered an 

approach whereby we would set the cap 

annually based on the actual excess 

renewable fuel production. Table 

III.D.3.c–2 provides an example of how 

the caps would be calculated if the EIA 

projections for ethanol production prove 

accurate. 

TABLE III.D.3.C–2.—REQUIRED AND PROJECTED RENEWABLE FUEL VOLUMES

[Billion gallons] 

Required 

under RFSa

Ethanol produced b Excess d

Previous 

Year excess 

ethanol as a 

fraction of 

current year 

compliance 

(percent) 

2008 ................................................................................................................................. 5.4 6.0 0.6 ....................

2009 ................................................................................................................................. 6.1 6.9 0.8 9.8 

2010 ................................................................................................................................. 6.8 7.9 1.1 11.8 

2011 ................................................................................................................................. 7.4 8.8 1.4 14.9 

2012 ................................................................................................................................. 7.5 9.6 2.1 18.7 

2013 ................................................................................................................................. c 7.6 10.1 2.5 27.6 

2014 ................................................................................................................................. c 7.8 10.3 2.5 32.1 

2015 ................................................................................................................................. c 7.9 10.5 2.6 31.6 

aEquivalent to the required volumes shown in Table I.B–1 bProjected ethanol production volumes from EIA, Annual Energy Outlook 2006. 

cExample of possible increases in the required volumes. The Energy Act requires at minimum a constant percentage of renewable fuel in gasoline after 2012. d Does not include other renewable fuels such as biodiesel which would increase the excess even further. 

In 2009, for instance, the cap would 

be 9.8 percent, and by 2012 it would be 

18.7 percent. Under such an approach, 

the value of the cap might more 

precisely reflect the actual excess RINs 

and preclude their rollover. However, 

the annual calculation of the cap would 

require that the total renewable fuel 

volumes from the previous year be 

known. For compliance year 2009, 

information on 2008 renewable fuels 

production would not generally be 

known until spring of 2009. Therefore, 

obligated parties would not know until 

mid-year at the earliest what the exact 

cap would be for that year. The Agency 

could publish an estimate of the cap by 

the end of the previous year, but it 

would not provide obligated parties 

with the certainty they may need for 

establishing contracts and business 

relationships for RIN trading. In 

addition, such a variable cap may not 

ensure a smoothly functioning RIN 

market under all possible market 

conditions. Market flexibility is needed 

most when the RIN market is the 

tightest (i.e. when renewable fuel 

production volumes are closest to the 

volumes required under the RFS 

program). Yet under this alternative 

approach, the cap would be the smallest 

when supply was closest to demand for 


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RINs. The cap would approach zero as 

supply approached the volumes 

required under the RFS program, and 

thus an obligated party that had even a 

small number of excess RINs from the 

prior year could not use them, but rather 

would be forced to trade them to 

someone else. Conversely, when supply 

significantly exceeds demand and 

market flexibility is needed least, the 

cap would be the highest. Fixing the cap 

at 20 percent both provides certainty to 

the RIN market, and ensures that some 

minimum level of flexibility exists for 

individual obligated parties even in a 

market without excess RINs. 

The level of 20 percent is also 

consistent with both past ethanol 

market fluctuations and future 

projections of excess ethanol. As 

described above, the largest single-year 

drop in ethanol supply occurred in 1996 

and resulted in 21% less ethanol being 

produced than in 1995. While future 

supply shortfalls may be larger or 

smaller, the circumstances of 1996 

provide one example of their potential 

magnitude. Furthermore, as illustrated 

in Table III.D.3.c–2, EIA projections 

indicate that previous year volumes will 

exceed current-year requirements by 

roughly 10 to 30 percent between 2009 

and 2015. Our proposed 20 percent cap 

lies in the midrange of these values. 

As a result, we believe that a cap of 

20 percent appears to be a reasonable 

way to limit RIN rollover and provide 

some assurances to renewable fuel 

producers regarding demand for 

renewable fuel. A cap of 20 percent 

would also ensure that many previousyear RINs can still be used for current 

year compliance, providing some 

flexibility in the event of market 

disruptions. 

Despite the flexibility it would 

provide, a cap of 20 percent would not 

be guaranteed to be sufficient to address 

every potential future supply shortfall 

or fluctuation in the renewable fuels 

market. Thus we request comment on 

whether a higher cap, such as 30 

percent, would be more appropriate. On 

the other hand, since EIA is projecting 

that a cap of 20 percent will be more 

than what is necessary in the first few 

years of the program to address rollover, 

we also request comment on whether a 

smaller cap, such as 10 percent, would 

be appropriate. 

We also request comment on whether 

the Agency should adopt a provision 

allowing the cap to be raised in the 

event that supply shortfalls 

overwhelmed the 20 percent cap. Under 

this conditional provision, the Agency 

would monitor standard indicators of 

agricultural production and renewable 

fuel supply to determine if sufficient 

volumes of renewable can be produced 

to meet the RFS program requirements 

in a given year. Prior to the end of a 

compliance period, if the Agency 

determined that a supply shortfall was 

imminent, it could raise the cap to 

permit a greater number of previousyear RINs to be used for current-year 

compliance. Although this approach 

would not change the required volumes, 

it could create some additional 

temporary flexibility. 

In addition to our proposed 20 

percent cap, we also evaluated an 

alternative approach for addressing the 

RIN rollover issue. Under this 

alternative, we would not employ a 

uniform cap at all, but rather would 

require current-year RINs to be applied 

towards an obligated party’s RVO before 

any previous-year RINs were 

considered. This ‘‘last-in, first-out’’

(LIFO) approach would eliminate the 

possibility that previous-year RINs 

could be used to generate new excess 

current-year RINs, forcing them to 

expire. Although it would focus the RIN 

rollover correction on obligated parties 

and would tailor it to the specific 

circumstances of each party, this 

alternative approach would also create 

the need for an additional regulatory 

prohibition. Under this approach, RINs 

held by non-obligated parties would not 

automatically expire. As a result, nonobligated parties could in essence serve 

as a bank of previous-year RINs, thus 

permitting the rollover to continue 

despite the imposition of a LIFO 

protocol. To prevent this, the LIFO 

approach would have to include a 

requirement that non-obligated parties 

be prohibited from owning previousyear RINs. If a non-obligated party were 

to own a current-year RIN on December 

31 and hold it until January 1, that RIN 

would automatically expire. In order to 

enforce this provision, the Agency 

would also need to keep track of and 

receive reports on all RIN transactions 

for non-obligated parties by their 

transaction date. 

Given the additional uncertainty and 

complexity caused by this alternative 

approach, we believe that our proposed 

20 percent cap provides the greatest 

degree of simplicity and flexibility 

while still addressing the RIN rollover 

issue. However, we request comment on 

any alternative approaches to 

addressing the RIN rollover issue. 

d. Deficit Carryovers. The Energy Act 

also contains a provision allowing an 

obligated party to carry a deficit forward 

from one year into the next if it cannot 

generate or purchase sufficient credits to 

meet its RVO. However, deficits cannot 

be carried over two years in a row. 

Deficit carryovers are measured in 

gallons of renewable fuel, just as for 

RINs and RVOs. If an obligated party 

has not acquired sufficient RINs to meet 

its RVO in a given year, the deficit is 

calculated by subtracting the total 

number of RINs an obligated party has 

acquired from its RVO. There are no 

volume penalties, discounts, or other 

factors included when calculating a 

deficit carryover. As described in 

Section III.D.1, the deficit is then added 

to the RVO for the next year. The 

calculation of the RVO as described in 

Section III.A.4 shows how a deficit 

would be carried over into the next year: 

RVOi = Stdi × GVi + Di¥1

Where: 

RVOi = The Renewable Volume Obligation 

for the obligated party for year i, in 

gallons 

Stdi = The RFS program standard for year i, 

in percent 

GVi = The non-renewable gasoline volume 

produced by an obligated party in year 

i, in gallons 

Di¥1 = Renewable fuel deficit carryover from 

the previous year, in gallons. 

If an obligated party does acquire 

sufficient RINs to meet its RVO in year 

i-1, the obligated party must procure 

sufficient RINs to cover the full RVO for 

year i including the deficit. There are no 

provisions allowing for another year of 

carryover. If the obligated party does not 

acquire sufficient RINs to meet its RVO 

for that year plus the deficit carryover 

from the previous year, it would be in 

noncompliance. 

The Act indicates that deficit 

carryovers are to occur due to 

‘‘inability’’ to generate or purchase 

sufficient credits. We believe that 

obligated parties will make a 

determined effort to satisfy their RVO 

on an annual basis, and that a deficit 

will demonstrate that they were unable 

to do so. Thus, we are not proposing 

that any particular demonstration of 

‘‘inability’’ be a prerequisite to the 

ability of obligated parties to carry 

deficits forward. However, we request 

comment on this issue. 

4. Provisions for Exporters of Renewable 

Fuel 

As described in Section III.D.2.a, we 

believe that U.S. consumption of 

renewable fuel as motor vehicle fuel can 

be measured with considerable accuracy 

through the tracking of renewable fuel 

production and importing records. This 

is the basis for our proposed RIN-based 

system of compliance. However, exports 

of renewable fuel must be accounted for 

under this approach. For instance, if a 

gallon of ethanol is produced in the U.S. 

but consumed outside of the U.S., the 

RIN associated with that gallon should 


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not be valid for RFS compliance 

purposes since the RFS program is 

intended to require a specific volume of 

renewable fuel to be consumed in the 

U.S. Exports of renewable fuel currently 

represent about 5 percent of U.S. 

production. 

To ensure that renewable fuels 

exported from the U.S. cannot be used 

by an obligated party for RFS 

compliance purposes, the RINs 

associated with that exported renewable 

fuel must be removed from circulation. 

Ideally the producer of the exported 

renewable fuel would simply not create 

RINs for those batches. However, in the 

fungible distribution system it is 

common for exportation of fuel to occur 

without the knowledge of the producer. 

As a result, we cannot rely on the 

producers to know which batches will 

be exported and to not generate RINs for 

those batches. Another approach would 

be to increase the obligation placed on 

refiners, importers, and blenders of 

gasoline based on the volume of 

renewable fuel exported. Obligated 

parties would thus acquire RINs to meet 

the standard described in Section III.A, 

and would also be required to acquire 

RINs to cover the volume of renewable 

fuel exported. However, this approach 

would not only require an estimate of 

the volume of renewable fuel exported 

in the next year, but would also mean 

that every obligated party would share 

in accumulating RINs to cover the 

exports. 

Given these drawbacks, we believe 

that these two approaches would be 

unworkable. As a result, we believe that 

it should be the exporter’s responsibility 

to account for exported renewable fuel. 

The most straightforward mechanism to 

accomplish this would be to assign an 

RVO to each exporter that is equal to the 

annual volume of renewable fuel it 

exported. Just as for obligated parties, 

then, the exporter would be required to 

acquire sufficient gallon-RINs to meet 

its RVO. If the exporter purchased 

renewable fuel directly from a producer, 

that renewable fuel would come with 

associated gallon-RINs which could 

then be applied to its RVO under our 

proposed program. In this circumstance, 

the exporter would not need to acquire 

RINs from any other source. If, however, 

the exporter received renewable fuel 

without the associated RINs, it would 

need to acquire RINs from some other 

source in order to meet its RVO. 

As discussed in Section III.D.2.c, it 

may be possible to eliminate the need 

for RINs altogether in specific 

circumstances involving exports of 

renewable fuels. For instance, if the 

exporter was wholly owned by a 

renewable fuel producer, there would be 

no need to generate RINs for the 

exported product. Likewise if a 

renewable fuel producer specifically 

and explicitly earmarked a batch of 

renewable fuel for export, there would 

be no need for a RIN to be generated. 

However, in both of these cases the 

producer would need to report the 

volumes that were not assigned a RIN to 

the EPA in its annual RFS report, along 

with the connection to exports, in order 

to demonstrate that RINs were 

legitimately not assigned to these 

batches. We request comment on these 

special-case approaches to exported 

renewable fuels. 

As described in Section III.D.2, there 

are cases in which there is not a one-toone correspondence between gallons in 

a batch of renewable fuel and the RINs 

generated for that batch. For instance, 

extra-value RINs can be generated in 

cases where the Equivalence Value is 

greater than 1.0. If the RVO assigned to 

the exporter were based strictly on the 

actual volume of the exported product, 

it would not capture the extra-value 

RINs which generally are not assigned 

to batches. Thus we propose that the 

RVO assigned to an exporter be based 

not on the actual volume of renewable 

fuel exported, but rather on a volume 

adjusted by the Equivalence Value 

assigned to each batch. The Equivalence 

Value is represented by the RR code 

within the RIN as described in Section 

III.D.2.a. Thus the exporter would 

multiply the actual volume of a batch by 

that batch’s Equivalence Value to obtain 

the volume used to calculate the RVO. 

In cases wherein an exporter obtains 

a batch of renewable fuel whose RIN has 

already been separated by an obligated 

party or blender, the exporter may not 

know the Equivalence Value. We 

propose that for such cases the exporter 

simply use the actual volume of the 

batch to calculate its RVO. This will 

introduce some small error into the 

calculation of the RVO for cases in 

which the renewable fuel had in fact 

been assigned an Equivalence Value 

greater than 1.0. However, we believe 

that the potential impact of this error 

would be exceedingly small. We request 

comment on our proposed approach to 

exporters of renewable fuel and any 

alternative approaches that could ensure 

that production volumes of renewable 

fuel can be used as an accurate surrogate 

for consumed volumes. 

5. How Would the Agency Verify 

Compliance? 

The primary means through which 

the Agency would verify an obligated 

party’s compliance with its RVO would 

be the annual reports. These reports 

would include a variety of information 

required for compliance and 

enforcement, including the 

demonstration of compliance with the 

previous calendar year’s RVO, a list all 

transactions involving RINs, and the 

tabulation of the total number of RINs 

owned, used for compliance, 

transferred, retired and expired. 

Reporting requirements for obligated 

and non-obligated parties are covered in 

detail in Section IV. 

In its annual reports, an obligated 

party would be required to include a list 

of all RINs held as of the reporting date, 

divided into a number of categories. For 

instance, a distinction would be made 

between current-year RINs and 

previous-year RINs as follows: 

Current-year RINs: RINs that came 

into existence during the calendar year 

for which the report is demonstrating 

compliance. 

Previous-year RINs: RINs that came 

into existence in the calendar year 

preceding the year for which the report 

is demonstrating compliance. 

The report would also indicate which 

RINs were used for compliance with the 

RVO including any potential deficit, 

which current-year RINs were not used 

for compliance and would therefore be 

valid for compliance the next year, and 

which previous-year RINs were not used 

for compliance and therefore expired. 

The report would also include a 

demonstration that the 20 percent cap to 

address RIN rollover had been met, as 

described in Section III.D.3.c. 

In order to verify compliance for each 

obligated party, the primary Agency 

activity would involve the validation of 

RINs. There are four basic elements of 

RIN validation: 

(1) RINs used by an obligated party to 

comply with its RVO would be checked 

to ensure that they are within their twoyear valid life. The RIN itself will 

contain the year of generation, so this 

check involves only an examination of 

the listed RINs. 

(2) All RINs owned by an obligated 

party would be cross-checked with 

annual reports from renewable fuel 

producers to verify that each RIN had in 

fact been generated. 

(3) All RINs used by an obligated 

party for compliance purposes would be 

cross-checked with annual reports from 

other obligated parties to ensure that no 

two parties used the same RIN to 

comply. 

(4) Previous-year RINs used for 

compliance purposes would be checked 

to ensure that they do not exceed 20 

percent of the obligated party’s RVO. 

In cases where a RIN was highlighted 

under suspicion of being invalid, the 

Agency would then need to take 

additional steps to resolve the issue. In 


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general this would involve a review of 

RIN transfer records submitted to the 

Agency by all parties in the distribution 

system that held the RINs. RIN transfers 

would be recorded through EPA’s 

Central Data Exchange as described in 

Section IV. These RIN transfer records 

would permit the Agency to identify all 

transaction(s) involving the RINs in 

question. Liable parties could then be 

contacted and appropriate steps taken to 

formally invalidate a RIN improperly 

claimed by a particular party. 

Additional details of the liabilities and 

prohibitions attributed to parties in the 

distribution system are discussed in 

Section V. 

E. How Are RINs Distributed and 

Traded? 

Under our proposed program 

structure, a Renewable Identification 

Number (RIN) would be generated for 

every gallon of renewable fuel produced 

or imported into the U.S., and would be 

acquired by obligated parties for use in 

demonstrating compliance with the RFS 

requirements. However, there are a 

variety of ways in which RINs could be 

transferred from the point of generation 

by renewable fuel producers to the 

obligated parties that need them. 

EPA’s proposal was developed in 

light of the somewhat unique aspects of 

the RFS program. As discussed earlier, 

under this program the refiners and 

importers are the parties obligated to 

comply with the renewable fuel 

requirements. At the same time, refiners 

and importers do not generally produce 

or blend renewable fuels at their 

facilities, and so are dependent on the 

actions of others for compliance. Unlike 

EPA’s other fuel programs, the actions 

needed for compliance largely center on 

the production, distribution, and use of 

a product by parties other than refiners 

and importers. In this context, EPA 

believes the RIN transfer mechanism 

should focus first on facilitating 

compliance by refiners and importers, 

and doing that in a way that imposes 

minimum burden on other parties and 

minimum disruption of current 

mechanisms for distribution of 

renewable fuels. 

Our proposal does this by relying on 

the current market structure for ethanol 

distribution and use, and avoiding the 

need for creation of new mechanisms 

for RIN distribution that are separate 

and apart from this current structure. 

EPA’s proposal would basically have 

the RIN follow with the ethanol until 

the point the ethanol is purchased by 

the obligated party, or is blended into 

gasoline by a blender. This approach 

would allow the RIN to be incorporated 

into the current market structure for sale 

and distribution of ethanol, and would 

avoid requiring refiners to develop and 

use wholly new market mechanisms. 

While the development of new market 

mechanisms to distribute RINs is not 

precluded under our proposed program, 

it is also not required. 

The Agency has also evaluated several 

other options for distributing RINs. We 

are not proposing these alternatives 

because they tend to require the 

development of new market 

mechanisms, as compared to relying on 

the current market structure for 

distribution of ethanol, and they are less 

focused on facilitating compliance for 

the obligated parties. At the same time, 

we recognize that all of the alternatives 

described below, as well as our 

proposal, have differing positive and 

negative aspects, and we invite 

comment on them, especially comments 

comparing and contrasting them with 

our proposed program. Our proposal is 

described in subsections 1 through 3 

below, and alternative approaches in 

subsection 4. 

1. Distribution of RINs With Batches of 

Renewable Fuel 

We are proposing that standard-value 

RINs be transferred with actual batches 

of renewable fuel as they move through 

the distribution system, until ownership 

of the batch is assumed by an obligated 

party or by a party that converts the 

renewable fuel into motor vehicle fuel. 

After such time, the RINs could be 

separated from the batch and freely 

traded. This approach would place 

certain requirements on anyone who 

takes ownership of renewable fuels, 

including renewable fuel producers, 

importers, marketers, distributors, 

blenders, and terminal operators. 

a. Responsibilities of Renewable Fuel 

Producers and Importers. The initial 

generation of RINs and their assignment 

to specific batches of renewable fuel 

would be the sole responsibility of 

renewable fuel producers and renewable 

fuel importers. As described in Section 

III.D.1, volumes of renewable fuel can 

be measured most accurately and be 

more readily verified at these 

originating locations. They would 

construct each batch-RIN based on the 

particular circumstances associated 

with each batch, including the creation 

of a unique serial number for the batch 

and specifying its Equivalence Value. 

The batch-RIN would also identify the 

specific number of gallons in the batch, 

thereby summarizing the gallon-RINs 

assigned to every gallon in the batch. 

See Section III.D.2.a for details on our 

proposed format for RINs. 

Only standard-value RINs would have 

to be assigned to batches. Extra-value 

RINs could be generated by the 

renewable fuel producer in cases where 

the renewable fuel in question has an 

Equivalence Value greater than 1.0 (see 

Section III.D.2.c for further discussion). 

However, the extra-value RINs would 

not need to be assigned to the batch. 

Instead, they could be transferred to 

another party independent of the batch. 

This requirement would in general 

result in a one-to-one correspondence 

between gallons in a batch and the 

volume block numbers in the batch-RIN 

assigned to that batch. As a result, the 

process of dividing and combining RINs 

during batch splits and mergers would 

be simplified, and the fungibility of 

RINs in the distribution system would 

be maintained. For example, a marketer 

who took custody of ethanol batches 

from several different producers, 

including a producer of cellulosic 

biomass ethanol, and combined them all 

in a single tank could then withdraw 

batches of any size from the tank, and 

assign a number of gallon-RINs to each 

batch that is equivalent to the number 

of actual gallons in that batch. This 

approach would also provide an 

incentive for producers to produce 

renewable fuels with higher 

Equivalence Values, since they could 

transfer the extra-value RINs to any 

party. 

However, we are also proposing that 

producers have the option of assigning 

even extra-value RINs to batches if they 

chose to do so. Under these 

circumstances, the extra-value RINs 

would be treated just like standardvalue RINs, and thus would be subject 

to the same limitations on who can 

separate the RIN from the batch. The 

assignment of extra-value RINs to 

batches would also mean that the 

number of gallon-RINs assigned to the 

batch would be greater than the number 

of gallons in the batch. As a result, care 

would have to be taken during batch 

splits and batch mergers to 

appropriately pass RINs assigned to a 

parent batch on to the daughter batches. 

We request comment on allowing extravalue RINs to be assigned to batches. 

There are two other cases in which 

the gallon-RINs assigned to a batch 

would not exactly correspond to the 

number of gallons in that batch. First, if 

a renewable fuel has an Equivalence 

Value less than 1.0, then RINs could 

only be assigned to a portion of the 

batch. Such potential circumstances are 

described in Section III.D.2.d. RINs may 

also not correspond exactly to gallons if 

the density of the batch changes due to 

changes in temperature. For instance, 

under extreme changes in temperature, 

the volume of a batch of ethanol can 

change by 5 percent or more. For this 


jlentini on PROD1PC65 with PROPOSAL2
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32An appropriate temperature correction for 

other renewable fuels should likewise be used. 

33 Derived from ‘‘Fuel Ethanol Technical 

Information,’’ Archer Daniels Midland Company, 

v1.2, 2003. 

34 Derived from R.E. Tate et al, ‘‘The densities of 

three biodiesel fuels at temperatures up to 300 °C’’, 

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

ester. 

reason we are proposing that all batch 

volumes be corrected to represent a 

standard condition of 60 °F prior to the 

assignment of a RIN. For ethanol,32 we 

propose that the correction be done as 

follows:33

Vs,e = Va,e × (¥0.0006301 × T + 

1.0378) 

Where: 

Vs,e = Standard volume of ethanol at 60 °F, 

in gallons. 

Va,e = Actual volume of ethanol, in gallons. 

T = Actual temperature of the batch, in °F. 

Since batches of ethanol are generally 

sold using standard volumes rather than 

actual volumes, this approach to 

assigning RINs to batches would be 

consistent with current practices and 

would maintain the one-to-one 

correspondence between the volume 

block in the batch-RIN and the 

standardized volume of the batch. We 

propose a similar approach to biodiesel, 

where the volume correction can be 

calculated using the following 

equation:34

Vs,b = Va,b × (¥0.0008008 × T + 

1.0480) 

Where: 

Vs,b = Standard volume of biodiesel at 60 °F, 

in gallons. 

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

T = Actual temperature of the batch, in °F. 

The RIN would have to be assigned to 

a batch no later than the point in time 

when the batch physically leaves the 

production or importing facility. 

Although ownership of the batch may 

be retained by the producer or importer, 

the RIN would nevertheless be required 

to be transferred along with the batch as 

it leaves the originating facility. This 

requirement would ensure that RINs 

could be verified against production or 

importing facility records and against 

mandated reports to the Energy 

Information Administration (EIA). It 

would also centralize the process of 

assigning RINs to batches. 

The means through which RINs 

would be transferred with batches 

would in some respects be left to the 

discretion of the renewable fuel 

producer or importer. The primary 

requirement would be that the RIN be 

included on a product transfer 

document (PTD). The PTD can be 

included in any form of standard 

documentation that is already 

associated with or used to identify title 

to the batch. The batch documentation 

must be of the sort that uniquely 

identifies the batch and is generally 

transferred from one party to another, in 

electronic or paper form, when 

ownership of the batch is transferred. In 

many cases a bill-of-lading could serve 

this purpose. The RIN must be 

displayed prominently on the document 

when the batch leaves the originating 

facility, so that parties taking ownership 

of the batch could make a record of this 

fact with specific reference to the RIN. 

The RIN must be included on a PTD 

whenever ownership or custody of the 

batch is transferred, until such time as 

the RIN may be separated from the batch 

as described in Section III.E.2. As in 

other fuels programs, we believe the 

PTD requirement can be met by 

including the required information 

generated and transferred in the normal 

course of business. 

RINs would be transferable in the 

context of the RFS program, and except 

as discussed above, must be transferred 

along with ownership or custody of the 

batch. The approach that a producer or 

importer takes to the transfer or sale of 

RINs and batches would be at their 

discretion, under the condition that the 

two be transferred or sold 

simultaneously and to the same party. 

b. Responsibilities of Parties That 

Buy, Sell, or Handle Renewable Fuels. 

Batches of renewable fuel can be 

transferred between many different 

types of parties as they make their way 

from the production or import facilities 

where they originated to the places 

where they are blended into 

conventional gasoline or diesel. Some of 

these parties take custody but not 

ownership of these batches, storing and 

transmitting them on behalf of those 

who retain ownership. Other parties 

take ownership but not custody, such as 

a refiner who purchases ethanol and has 

it delivered directly to a blending 

facility. Thus prior to blending, each 

batch of renewable fuel can be owned or 

held by any number of parties including 

marketers, distributors, terminal 

operators, and refiners. Under our 

proposed program, when any party 

takes ownership of a batch of renewable 

fuel prior to ownership of the batch of 

fuel by an obligated party or blender, 

the RINs associated with that batch 

must be transferred as well. The RINs 

would be included on PTDs that the 

party procures when taking ownership 

of a batch. 

We propose that in general all parties 

that assume ownership of any batch of 

renewable fuel be required to transfer all 

RINs assigned to that batch to another 

party to whom ownership of the batch 

is being transferred. Batch splits and 

batch mergers represent special cases of 

RIN transfers, and are described in more 

detail below. As described in Section 

III.E.2, the only exception to the 

requirement that RINs be transferred 

with batches would be parties who are 

obligated to meet the renewable fuel 

standard, and parties who convert the 

renewable fuel into motor vehicle fuel. 

Since our proposed program is designed 

to allow RIN transfer and 

documentation to occur as part of 

normal business practices in the context 

of renewable fuel distribution, the 

incremental costs of transferring RINs 

with batches should be minimal. 

Marketers and distributors would 

simply be adding the batch-RIN to 

transfer documents such as bills-oflading, and recording the batch-RINs in 

their records of batch purchases and 

sales. 

Under most other credit trading 

programs, parties obligated to meet a 

standard are also the parties that 

generate credits for trade. Under these 

systems, non-obligated parties can 

participate only to the degree that 

obligated parties explicitly include 

them. In the case of the RFS program, 

however, the production of renewable 

fuels and their conversion into motor 

vehicle fuel through blending is largely 

done by persons other than obligated 

parties. To the degree that our proposed 

program allowed the disparity between 

RFS obligations and the means of 

compliance to continue, stakeholders 

have expressed concerns about a variety 

of problems that could arise, such as 

market power by RIN sellers in the 

market where RINs are exchanged. 

Market power on the part of nonobligated parties could result in higher 

prices for RINs than prices that would 

arise in a competitive, well-functioning 

market setting. For instance, if a 

renewable fuel producer or marketer 

could separate the batch-RIN from the 

batch, he could in theory withhold the 

RIN from the marketplace temporarily. 

By the end of an annual compliance 

period, a scarcity of RINs could increase 

their price, at which point the 

renewable fuel producers or marketers 

could begin to sell the RINs at an 

inflated price. In the extreme such 

parties could potentially withhold a 

large number of RINs from the market, 

creating a scarcity of RINs that could 

compel obligated parties to purchase 

additional volumes of renewable fuel 

with associated RINs. These scenarios 

are of particular concern given that we 

expect there will be a relatively small 

number of renewable fuel producers and 

marketers selling RINs in the 


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marketplace. For instance, although 

there currently exist about 100 ethanol 

production facilities in the U.S., nearly 

half of the production volumes come 

from only seven companies. Likewise, 

only five companies manage the 

majority of ethanol marketing. 

We believe that the general 

prohibition against the separation of 

RINs from batches in the distribution 

system will place only a small 

additional burden on marketers and 

distributors of renewable fuel. 

According to several stakeholders, a 

large amount of ethanol is already 

purchased from renewable fuel 

producers directly by refiners. In these 

cases, the RIN would be transferred 

directly from the renewable fuel 

producer to an obligated party. For the 

remaining batches of ethanol that do 

experience multiple transfers before 

being blended into gasoline, the RIN 

itself would represent a small 

incremental item of information that 

must be recorded and transferred along 

with batches and could be included in 

normal business records. 

In addition to the recordkeeping 

responsibilities described in more detail 

in Section IV, parties that would be 

required to transfer RINs with batches 

under our proposed program would also 

have the primary responsibility of 

maintaining the integrity of RIN-batch 

pairing when batches are split or 

merged. Our proposed approach to these 

situations is described below. 

i. Batch splits 

As described in Section III.D.2, batchRINs assigned to batches of renewable 

fuel would be formatted such that the 

volume block codes (SSSSSS and 

EEEEEE) would identify every gallon in 

a batch, and thus every gallon-RIN. 

Thus in most cases there will be a oneto-one correspondence between gallons 

in a batch and the volume block codes 

for the batch-RIN assigned to that batch. 

If a batch of renewable fuel is split into 

two or more new batches, the gallonRINs assigned to the original batch can 

be split coincidentally with batch 

volumes. The following example shows 

how this would be done (volume blocks 

separated for clarity): 

Parent batch: 

1000 gallons, 

batch-RIN: 2007123412345000011021–

000001–001000. 

Daughter batch #1: 

600 gallons, 

batch-RIN: 2007123412345000011021–

000001–000600. 

Daughter batch #2: 

100 gallons, 

batch-RIN: 2007123412345000011021–

000601–000700. 

Daughter batch #3: 

300 gallons, 

batch-RIN: 2007123412345000011021–

000701–001000. 

In this example, the gallon-RINs 

remain both unique and paired on a 

one-to-one basis with actual gallons 

even after the parent batch is divided 

into smaller daughter batches. 

However, there will be some cases in 

which there is not a one-to-one 

correspondence between a RIN assigned 

to a batch and the actual gallons in that 

batch, and such cases could complicate 

the process of splitting batches. For 

instance, changes in temperature could 

cause batch volumes to swell or shrink. 

Renewable fuels with Equivalence 

Values less than 1.0, although currently 

unlikely to arise in appreciable 

volumes, will have more actual gallons 

in the original batch than RINs assigned 

to that batch. And some producers may 

choose to assign extra-value RINs to 

batches in cases wherein the 

Equivalence Value is greater than 1.0. 

To address such cases, we propose to 

allow parties in the distribution system 

the discretion to split batches and their 

assigned RINs following any protocol 

they choose, as long as that protocol 

preserves the requirement that gallonRINs that have been assigned to a batch 

by the producer are subsequently 

assigned to a batch after splitting has 

occurred. Thus regardless of the 

splitting protocol used, no gallon-RINs 

assigned to a batch could be retained by 

a party after every gallon in that batch 

has been transferred to another party. 

There are a variety of batch splitting 

protocols that a party could choose from 

for situations where there is not a oneto-one correspondence between the 

number of gallon-RINs assigned to a 

batch and the number of standardized 

gallons in that batch. However, we have 

identified two acceptable protocols that 

we expect most parties to use. These are 

described in Table III.E.1.b.i–1 below. 

Examples of batch splits using both 

types of splitting protocols are given in 

Tables III.E.1.b.i–2 and III.E.1.b.i–3. We 

propose that the Proportional Protocol 

be required for cases in which the 

Equivalence Value of a renewable fuel is 

less than 1.0. For cases in which the 

Equivalence Value is equal to or greater 

than 1.0, we propose to allow parties the 

flexibility to follow a batch splitting 

protocol of their own choosing so long 

as there is at least one gallon-RIN for 

every physical gallon in each of the 

daughter batches. We request comment 

on these batch splitting protocols, any 

alternative protocols, and the need to 

codify a protocol in the regulations for 

specific situations. 

TABLE III.E.1.B.I–1.—TWO BATCH SPLITTING PROTOCOLS

Proportional One-to-one alignment 

Description .......................................................... The gallon-RINs assigned to a parent batch 

are split proportionally with the volumes in 

the daughter batches.

The gallon-RINs assigned to a parent batch 

are split to ensure that some daughter 

batches have a one-to-one correspondence 

between physical gallons and gallon-RINs. 

Remaining gallon-RINs are assigned to remaining gallons. 

Impacts for EVa < 1.0 ........................................ Ratio of actual gallons to gallon-RINs in the 

parent batch is preserved in all daughter 

batches.

Some daughter batches may have no assigned RIN. 

Impacts for EV > 1.0 .......................................... Ratio of actual gallons to gallon-RINs in the 

parent batch is preserved in all daughter 

batches.

Ratio of actual gallons to gallon-RINs in some 

daughter batches will be different than the 

ratio for the parent batch. 

aEquivalence Value. 


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TABLE III.E.1.B.I–2.—EXAMPLE OF PROPORTIONAL BATCH SPLITTING

EV < 1.0 EV > 1.0 

Parent batch: 

Actual volume (gal) ........................................................................................................................................................... 1 1000 1 1000 

Batch-RIN SSSSSS code ................................................................................................................................................. 000001 000001 

Batch-RIN EEEEEE code ................................................................................................................................................. 000800 002500 

Number of gallon-RINs ..................................................................................................................................................... 800 2500 

Daughter batch #1: 

Actual volume (gal) ........................................................................................................................................................... 1 600 1 600 

Batch-RIN SSSSSS code ................................................................................................................................................. 000001 000001 

Batch-RIN EEEEEE code ................................................................................................................................................. 000480 001500 

Number of gallon-RINs ..................................................................................................................................................... 480 1500 

Daughter batch #2: 

Actual volume (gal) ........................................................................................................................................................... 1 400 1 400 

RIN volume block start (SSSSSS) ................................................................................................................................... 000481 001501 

RIN volume block end (EEEEEE) .................................................................................................................................... 000800 002500 

Number of gallon-RINs ..................................................................................................................................................... 320 1000 

1gal. 

TABLE III.E.1.B.I–3—EXAMPLE OF BATCH SPLITTING WITH ONE-TO-ONE ALIGNMENT

EV < 1.0 EV > 1.0 

Parent batch: 

Actual volume (gal) ........................................................................................................................................................... 1 1000 1 1000 

Batch-RIN SSSSSS code ................................................................................................................................................. 000001 000001 

Batch-RIN EEEEEE code ................................................................................................................................................. 000800 002500 

Number of gallon-RINs ..................................................................................................................................................... 800 2500 

Daughter batch #1: 

Actual volume (gal) ........................................................................................................................................................... 1 600 1 600 

Batch-RIN SSSSSS code ................................................................................................................................................. 000001 000001 

Batch-RIN EEEEEE code ................................................................................................................................................. 000600 000600 

Number of gallon-RINs ..................................................................................................................................................... 600 600 

Daughter batch #2: 

Actual volume (gal) ........................................................................................................................................................... 1 400 1 400 

Batch-RIN SSSSSS code ................................................................................................................................................. 000601 000601 

Batch-RIN EEEEEE code ................................................................................................................................................. 000800 002500 

Number of gallon-RINs ..................................................................................................................................................... 200 1900 

1gal. 

ii. Batch mergers. 

In general batch mergers will begin 

with at least two parent batches having 

different RINs. After the merger of the 

two parent batches, the RINs from the 

two parents would simply need to be 

listed separately on any product transfer 

documents such as bills-of-lading, since 

they differ not just in the volume block 

codes but also in other aspects of the 

RIN. We are not proposing any 

mechanism for simplifying the RIN in 

the case of a batch merger, such as 

combining two different RINs into a 

single RIN or replacing a collection of 

different RINs with a new single RIN. 

We believe that such approaches would 

be likely to create significant difficulties 

in tracking RINs and verifying their 

validity. 

Parties that have two or more batches 

of renewable fuel that have been merged 

into a single batch will be free to 

determine how the RINs will be 

subsequently split and assigned to new 

daughter batches during a batch split. 

We are not proposing a specific protocol 

for such cases, beyond the general 

requirement that RINs that have been 

assigned to parent batches remain 

assigned to a daughter batch after 

splitting has occurred. However, it may 

be helpful for RINs to be ordered on 

PTDs in the order in which the batches 

were combined, and then assigned to 

daughter batches on a first-in, first-out 

basis. Thus as individual parent batches 

are added to, for instance, a tank already 

containing renewable fuel, the RINs 

associated with the newly added batch 

could be added below the existing RINs 

on the documentation. As product was 

drawn back out of the tank, the RINs 

assigned to the removed product would 

be those at the top of the list of RINs on 

the tank documentation. This FIFO 

approach would ensure that RINs 

assigned to parent batches continue to 

move through the distribution system, 

and batch splits could occur 

straightforwardly even in cases that 

begin with merged batches. We request 

comment on whether this FIFO 

approach should remain guidance or 

whether instead it should be a 

regulatory requirement. 

2. Separation of RINs From Batches 

Separation of a RIN from a batch 

means that the RIN would no longer be 

included on the PTD, and could be 

traded independently from the batch to 

which it had originally been assigned. 

We believe that the regulatory 

program should be structured around 

facilitating compliance by obligated 

parties with their renewable fuel 

obligation. This means that obligated 

parties should have the right to market 

the renewable fuel separately from the 

RIN originally assigned to it. We are 

therefore proposing that a refiner or 

importer would have the right to 

separate the RIN from the batch as soon 

as he assumes ownership of that batch. 

In the case of ethanol blended into 

gasoline at low concentrations (≤ 10 

volume percent), stakeholders have 

informed us that a large volume of the 

ethanol is purchased by refiners directly 

from ethanol producers, and is then 

passed to blenders who carry out the 


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blending with gasoline. Therefore, in 

many cases RINs assigned to batches 

will pass directly from the producers 

who generated them to the obligated 

parties who need them. 

However, significant volumes of 

ethanol are also blended into gasoline 

without first being purchased by a 

refiner. In some cases, the blender itself 

purchases the ethanol. In other cases, a 

downstream customer purchases the 

ethanol and contracts with the blender 

to carry out the blending. Regardless, 

the ethanol may never be held or owned 

by an obligated party before it is 

blended into gasoline. Thus we believe 

that a blender should also have the right 

to separate the RIN from the batch if he 

actually blends the ethanol into 

gasoline. This would only apply to 

batches where the RIN had not already 

been separated by an obligated party. 

Since blenders would in general not be 

obligated parties under our proposed 

program, blenders who separate RINs 

from batches would have no need to 

hold onto those RINs and thus could 

transfer them to an obligated party for 

compliance purposes, or to any other 

party. 

There may be occasions in which a 

downstream customer actually owns the 

batch of ethanol when it is blended into 

gasoline. In such cases the blender will 

have custody but not ownership of the 

batch. We propose that the RIN can be 

separated from the batch of ethanol 

when the batch is blended into gasoline, 

but the RIN could only be separated by 

the party that owns that batch of 

renewable fuel at the time of blending. 

Once a RIN is separated from a batch 

of renewable fuel, the PTDs associated 

with that batch could no longer list the 

RIN. Parties who subsequently take 

ownership of the batch may not know 

if the RIN had been separated, or if a 

RIN had never been assigned to the 

batch in the first place, contrary to 

regulatory requirements. To avoid 

concerns about whether RINs assigned 

to batches have not been appropriately 

transferred with the batch, we request 

comment on whether PTDs should 

include some notation indicating that 

the assigned RIN has been removed. 

As described in Section III.B, many 

different types of renewable fuel can be 

used to meet the RFS volume 

obligations placed upon refineries and 

importers. Currently, ethanol is the most 

prominent renewable fuel, and is most 

commonly used as a low level blend in 

gasoline at concentrations of 10 volume 

percent or less. However, some 

renewable fuels can be used in neat 

form (i.e. not blended with conventional 

gasoline or diesel). The two RIN 

separation situations described above 

would capture any renewable fuel for 

which ownership is assumed by an 

obligated party or a party that blends the 

renewable fuel into gasoline or diesel. 

However, renewable fuels which are 

used in their neat (unblended) form as 

motor vehicle fuel may not be captured. 

This would include such renewable 

fuels as neat biodiesel (B100), methanol 

for use in a dedicated methanol vehicle, 

biogas for use in a CNG vehicle, or 

renewable diesel used in its neat form. 

As for ethanol and biodiesel, neat 

renewable fuels would be assigned a 

RIN by the producer. However, in cases 

where the neat renewable fuel is never 

owned by an obligated party or blended 

into gasoline or diesel before being used 

as a motor vehicle fuel, no party would 

have the right to separate the RIN from 

the batch. The RIN would therefore 

never become available to an obligated 

party for RFS compliance purposes. 

Although the current use of these neat 

renewable fuels is minor in comparison 

to the volumes of ethanol and lower 

blend levels of biodiesel, we 

nevertheless believe that they should be 

allowed to help meet the volume 

requirements of the RFS program. 

To address this issue, we propose to 

more broadly define the right to separate 

a RIN from a batch. In addition to 

obligated parties and blenders, we 

believe that any party holding a batch of 

renewable fuel for which the RIN has 

not been separated could separate the 

RIN from the batch if the party 

designates it for use only as a motor 

vehicle fuel in its neat form and it is in 

fact only used as such. Given the lack 

of any significant use of ethanol in its 

neat (but denatured) form as a motor 

vehicle fuel, RINs for neat ethanol could 

only be separated by an obligated party 

or a party that blends it with gasoline. 

This would include a party that blended 

ethanol with a small amount of gasoline 

to form E85, since there are millions of 

vehicles in the fleet that can operate on 

E85. In this case, E85 would be treated 

like any other ethanol/gasoline blend. 

Under our proposed approach, 

therefore, any party that holds a batch 

of renewable fuel that is typically used 

in its neat form and was designated by 

the producer for use in its neat form as 

a motor vehicle fuel would be given the 

right to separate the RIN from the batch. 

This approach would recognize that the 

neat form of the renewable fuel is valid 

for compliance purposes under the RFS 

program, as described in Section III.B. 

Biodiesel (mono alkyl esters) is one 

type of renewable fuel that can under 

certain conditions be used in its neat 

form. However, in the vast majority of 

cases it is blended with conventional 

diesel fuel before use, typically in 

concentrations of 20 volume percent or 

less. This approach is taken for a variety 

of reasons, including the following: 

• To reduce impacts on fuel 

economy. 

• To mitigate cold temperature 

operability issues. 

• To market biodiesel as an additive 

rather than an alternative fuel. 

• To address concerns of some engine 

owners or manufacturers regarding the 

impacts of biodiesel on engine 

durability or drivability. 

• To reduce the cost of the resulting 

fuel. 

Biodiesel is also used in low 

concentrations as a lubricity additive 

and as a means for complying with the 

ultra-low sulfur requirements for 

highway diesel fuel. Biodiesel is 

occasionally used in its neat form. 

However, this approach is the exception 

rather than the rule. Consequently, we 

propose that the RIN assigned to a batch 

of biodiesel could only be separated 

from that batch if and when the 

biodiesel is blended with conventional 

diesel. To avoid claims that very high 

concentrations of biodiesel count as a 

blended product, we also propose that 

biodiesel must be blended into 

conventional diesel at a concentration of 

80 volume percent or less before the RIN 

can be separated from the batch. 

Our proposed approach to biodiesel 

would mean that biodiesel used in its 

neat form would not be valid for 

compliance purposes under the RFS 

program. To address this issue, we 

request comment on additionally 

allowing a biodiesel producer to 

separate the RIN from the batch if it 

could establish that it produced the 

batch of biodiesel specifically for use as 

motor vehicle fuel in its neat form, and 

that the biodiesel was in fact used in its 

neat form. 

3. Distribution of Separated RINs 

Once a RIN is separated from a batch 

of renewable fuel, it would become 

freely transferable. Each RIN could be 

held by any party, and transferred 

between parties any number of times. 

This approach would apply to extravalue RINs (RINs generated based on 

Equivalence Values greater than 1.0) as 

well as standard-value RINs. 

We are not proposing to limit the 

number of times that a RIN could be 

transferred, nor the types of parties that 

could receive or transfer RINs. However, 

this approach would be unique among 

EPA’s fuel regulations. For all previous 

motor vehicle fuel credit trading 

programs we have allowed only refiners 

and importers to transfer credits, and 

have limited the number of times credits 

could be transferred to one or two 


jlentini on PROD1PC65 with PROPOSAL2
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55591 

35Montgomery, David W., ‘‘Recommendations for 

a Trading Program Which Will Comply with the 

Renewable Fuel Standard,’’ CRA International, Inc. 

May 25, 2006. 

transfers. This includes, for example, 

the credit trading programs for 

reformulated gasoline and gasoline 

sulfur. These limitations were included 

to make the credit trading programs 

enforceable by making the transfer of 

credits, from the credit generator to the 

credit user, shorter, and populated only 

by the refiners and importers who were 

obligated to meet those standards. These 

approaches also helped to ensure the 

validity of credits by limiting the 

sources of credits to companies that the 

obligated parties know to be reliable 

business partners. A recent report 

provided to the Agency by the American 

Petroleum institute also provides 

support for limiting RIN trading to 

obligated parties.35 Therefore, we are 

seeking comment on limiting the 

number of trades and limiting the trades 

to only occur between obligated parties 

even though we are not proposing to do 

so here. 

For the RFS program, we believe that 

there is a need to provide for this more 

open trading, and that it can occur 

without unduly sacrificing the 

enforceability of the program or 

increasing its oversight burden. As 

described earlier, the RFS program is 

unique in that obligated parties are 

typically not the ones producing the 

renewable fuels and generating the 

RINs, so there is a need for trades to 

occur between obligated parties and 

non-obligated parties. By prohibiting 

anyone except obligated parties from 

holding RINs after they have been 

separated from a batch, we might be 

making it more difficult for those RINs 

to eventually be transferred to the 

obligated parties that need them. This is 

especially important in the case of the 

RFS program, because the program must 

work efficiently not only for a limited 

number of obligated parties, but a 

number of non-obligated parties as well. 

A potentially large number of oxygenate 

blenders, many of which will be small 

businesses, will be looking for ways to 

market their RINs. Furthermore, in some 

cases renewable fuel producers will also 

have RINs (in particular, extra-value 

RINs) that can be marketed. Allowing 

other parties, including brokers, to 

receive and transfer RINs may create a 

more fluid and free market that would 

increase the venues for RINs to be 

acquired by the obligated parties that 

need them. 

We believe we can ensure the 

enforceability of the program despite 

opening up trading to non-obligated 

parties and allowing multiple trades. 

The RIN number, along with the 

associated electronic reporting 

mechanism, should allow us the ability 

to verify the validity of RINs and the 

source of any invalid RINs. Since all 

RINs generated, traded, and used for 

compliance would be recorded 

electronically in an Agency database, 

these types of investigations would be 

straightforward. The number of RIN 

trades, and the parties between whom 

the RINs are being traded, would only 

have the effect of increasing the size of 

the database. 

As with other credit-trading programs, 

the business details of RIN transactions, 

such as the conditions of a sale or any 

other transfer, RIN price, role of 

mediators, etc. would be at the 

discretion of the parties involved. The 

Agency would be concerned only with 

information such as who holds a given 

RIN at any given moment, when 

transfers of RINs occur, who the party 

to the transfers are, and ultimately 

which obligated party relies on a given 

RIN for compliance purposes. This type 

of information would therefore be the 

subject of various recordkeeping and 

reporting requirements as described in 

Section IV, and these requirements 

would generally apply regardless of 

whether RIN has been separated from a 

batch. 

The means through which RIN trades 

would occur would also be at the 

discretion of the parties involved. For 

instance, parties with RINs could create 

open auctions, contract directly with 

those obligated parties who seek RINs, 

use brokers to identify potential 

transferees and negotiate terms, or just 

transfer the RINs to any other willing 

party. Brokers involved in RIN transfer 

could either operate in the role of 

arbitrator without holding the RINs, or 

alternatively could receive the RINs 

from one party and transfer them to 

another. If they are the transferee of any 

RINs, they would also be subject to the 

registration, recordkeeping, and 

reporting requirements. We do not 

believe that it would be appropriate or 

useful for the EPA to become directly 

involved in RIN transfers, other than in 

the role of providing a database within 

which transfers can be recorded. Thus 

EPA would not plan on establishing a 

clearinghouse or centralized brokerage 

for the management of RIN transfers, nor 

contract with a private firm through 

whom all RIN buyers and sellers would 

arrange transfers. Our experience with 

other credit trading programs suggests 

that, left to themselves, natural freemarket mechanisms will arise to handle 

RIN transfers, and that these 

mechanisms will maximize the 

efficiency of the market while 

minimizing the transaction costs for 

transfers of RINs. 

4. Alternative Approaches to RIN 

Distribution 

During the development of our 

proposed RFS trading and compliance 

program, stakeholders offered a variety 

of alternative program design 

approaches. Most of these alternatives 

recognize the value of a RIN-based 

system of compliance, but they differ in 

terms of which parties would be 

allowed to separate a RIN from a batch 

and the means through which the RINs 

should be transferred to obligated 

parties. We invite comment on all of 

these options. 

Our primary concern with the 

alternative approaches is that we believe 

they would be less effective than our 

proposed program at ensuring that RINs 

would get to the obligated parties who 

need them in a timely fashion. As 

described above, stakeholders have 

expressed serious concerns about any 

program structure that could allow nonobligated parties to exercise market 

power in the RIN market, and the 

program we are proposing today is 

designed to minimize these concerns. 

The alternative approaches described 

below, in contrast, could potentially 

allow some non-obligated parties who 

acquire RINs to either refuse to transfer 

them, make them difficult for obligated 

parties to obtain, or drive their price up 

by exercising market power. We believe 

that these stakeholder concerns about 

alternative program options are 

legitimate, given that nearly half of the 

production volumes of ethanol come 

from only seven companies and only 

five companies manage the majority of 

ethanol marketing. Our proposal also 

best addresses other related issues, such 

as limiting the number of obligated 

parties, providing for the most open RIN 

market, and providing an effective 

means at ensuring RIN certainty. 

a. Producer With Direct Transfer of 

RINs. One alternative to our proposed 

program would allow producers and 

importers of renewable fuels to transfer 

RINs separately from the renewable fuel 

that they represent. The producer or 

importer would still generate the RIN, 

but would not necessarily need to assign 

it to a specific batch of renewable fuel. 

The producer or importer would be 

required to transfer the RIN, but only to 

an obligated party. 

Under this approach non-obligated 

parties other than producers and 

importers would have no RIN 

ownership opportunities and would 

therefore not bear any burden associated 

with transferring RINs with batches. 


jlentini on PROD1PC65 with PROPOSAL2
55592 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

This would eliminate most of the 

recordkeeping and reporting 

requirements applicable to them under 

our proposed program. There would 

also be no need for any regulatory 

requirements to ensure proper 

accounting of RINs as they move 

through the distribution system, such as 

requirements necessary to address 

volume changes due to temperature, 

batch splits and mergers, use of 

renewable fuels in their neat form, and 

the recordkeeping and reporting 

associated with these requirements. 

The challenges associated with this 

approach, however, pertain to the 

disconnect between RINs and batches of 

renewable fuel. For instance, the 

disconnect would produce the 

possibility for the creation of market 

power with the renewable fuel producer 

that generates the RINs. As discussed 

above, there is the possibility that 

renewable producers might not place all 

RINs on the market for procurement by 

the obligated parties, thereby driving up 

their price and/or increasing further the 

demand for renewables. It is very 

unlikely that they would withhold 

renewable fuel itself from the market in 

order to drive up the price for it. Not 

only is storage capacity limited, but 

there is no evidence that ethanol 

producers or marketers have ever 

exercised this type of market control. 

This is also true under our proposed 

program. 

In addition, although a refiner could 

purchase renewable fuel directly from a 

producer and acquire RINs at the same 

time, there would be many other cases 

in which a refiner would purchase 

renewable fuel without RINs (such as 

from a marketer). Although the market 

would likely develop in such a way that 

renewable fuel without RINs would be 

priced differently than renewable fuels 

with RINs, the purchase of the 

renewable fuel would still have no 

bearing on the refiner’s RFS compliance 

demonstration, contrary to the intent of 

the Act. The refiner would have to 

procure RINs separately. If the refiner 

purchased more renewable fuel than it 

needed for compliance purposes in this 

way, it would not have any excess RINs 

to transfer to another party. The Act 

stipulates that allowances must be made 

for credits to be generated for excess 

renewable fuel. 

To address the concern regarding 

producers withholding RINs from the 

market, under this alternative the 

renewable producer would be required 

to make the RINs available for transfer 

to an obligated party. As under the 

proposed option, this RIN transfer could 

be done in one of several ways, such as 

through direct contract or a restricted 

clearinghouse. Any RINs not provided 

directly to an obligated party would 

then need to be made available through 

a regularly scheduled public auction to 

the highest bidder. This could be 

through an existing internet auction 

Web site, or through another auction 

mechanism implemented by a generator 

so long as the mechanism is equally 

open and available to all obligated 

parties. Only obligated parties would be 

permitted to bid on the RINs in such an 

auction. 

To ensure the effectiveness of such an 

approach, however, there are a number 

of additional aspects of the program that 

would need to be specified. Since a 

renewable producer could essentially 

withhold RINs from the market by 

setting the selling price too high, such 

an approach would hinge upon any 

such auctions occurring without any 

minimum price for the RINs. Producers 

would be required to transfer RINs to 

the highest bidder regardless of the bid 

price, even if there was only a single 

bidder. The renewable producer would 

be required to send the successful 

bidder a written confirmation of the RIN 

transfer, including the RIN 

identification numbers. If there were no 

bids, the renewable producer would be 

required to roll them over to subsequent 

auction cycles until such time as the 

RINs were no longer valid for 

compliance purposes and they would 

simply be retired. Finally, in order to 

ensure that RINs were actually being 

made available, such sales, trades, or 

auctions would be required to occur at 

least quarterly, but we seek comment on 

whether a shorter cycle would be more 

appropriate. 

Various other aspects of the RIN 

auctions or transactions would also 

have to be specified. For example, the 

location, time, and other details of any 

auction would have to be made widely 

known to obligated parties in sufficient 

time for them to participate. To this end, 

the rule could specify that there must be 

advance public notice of the intent to 

conduct an auction and the auction 

procedures, and that this notice must be 

advertised through nationwide media or 

a public Internet posting. The minimum 

amount of advance notice could be, for 

example, one week or four weeks. The 

regulations could require that the RINs 

be transferred in large enough blocks, 

such as 5,000 RINs, in order to prevent 

undue transaction costs. The regulations 

could also specify the time period 

during which any public auction must 

remain open; seven days could be 

specified, for example. Other criteria for 

how the auction is conducted could be 

included in order to ensure its 

legitimacy. Interested commenters 

should include details for RIN auctions 

or transactions that they believe should 

be addressed in implementing 

regulations. 

Our proposed program is designed to 

ensure that the existing market 

mechanisms for the distribution of 

renewable fuel can be used for the 

distribution of RINs as well. The need 

for independent RIN markets is 

minimized, and likewise the regulatory 

oversight of such markets is minimized. 

Under the direct transfer alternative 

described above, however, not only does 

an independent RIN market become a 

central feature of the RFS program, but 

the regulations might need to specify 

the many various aspects of RIN 

transfers as described above, and doing 

so would represent an intervention into 

the market that the Agency has not 

exercised before. It may be necessary to 

design the regulatory provisions in this 

way in order to have an enforceable 

program under this alternative, but we 

would have to be convinced that such 

an approach could be properly 

structured and that it was superior to 

other alternatives. 

Under this option, non-obligated 

parties such as marketers or brokers 

would not be allowed to own RINs. It 

could be possible to add in this 

flexibility, but in effect this option 

would then operate similarly to our 

proposed approach, but with additional 

complications and transaction costs due 

to the fact RINs would not follow 

batches through the distribution system. 

Therefore, we do not believe it is 

appropriate to provide this flexibility as 

part of the direct-transfer option. 

b. Producer With Open RIN Market. 

Another approach would allow 

producers and importers of renewable 

fuels to transfer RINs separately from 

the renewable fuel to any party. If a 

renewable fuel producer did choose to 

transfer the RIN with the batch, any 

downstream party would have the right 

to separate that RIN from the batch. 

Although we believe that the 

recordkeeping burden placed upon 

marketers and distributors under our 

proposed program would be minimal, 

this alternative approach would 

essentially eliminate that burden 

altogether. Marketers and distributors 

would not have to ensure that RINs 

were transferred with batches and keep 

a record of those transfers, and would 

not be responsible for ensuring that 

RINs remain assigned to batches during 

batch splits and mergers. Any marketer 

or distributor that did receive a batch 

with an assigned RIN could separate the 

RIN from the batch and transfer it, 

maximizing the choices available to 

them. 


jlentini on PROD1PC65 with PROPOSAL2
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55593 

However, this alternative approach 

would increase the burdens for 

obligated parties to comply with their 

renewable fuel obligation since all RINs 

would be controlled by producers and 

marketers at the point of generation. The 

concerns described above regarding the 

exercising of market power in the RIN 

market by a small number of nonobligated parties would apply to this 

alternative. Although these concerns 

may be less significant under EIA’s 

current projections that renewable fuel 

production volumes will exceed the 

RFS program requirements, we believe 

that we should design the RFS program 

to function smoothly under any future 

market scenario. Since it is possible that 

the market conditions leading to EIA’s 

projections could change, we believe 

that the concern about producers and 

marketers exercising market power in 

the RIN market is important. As a result, 

we do not believe that this alternative 

approach is most appropriate. 

c. First Purchaser. As under our 

proposed approach, in this alternative 

the renewable fuel producer would be 

required to assign a RIN to every batch 

of renewable fuel and to transfer that 

RIN with the batch. However, the first 

party in the distribution system to take 

ownership of the batch would have the 

right to separate the RIN from the batch. 

This means that any non-obligated party 

that purchased the renewable fuel from 

its producer would be able to separate 

the RIN and to transfer it independently 

from the batch. 

The advantage of this alternative 

approach, as compared to our proposal, 

is that it would remove control of the 

sale of RINs from the producers. 

However, the concern raised by refiners 

about the exercise of market power in 

the RIN market remains because only 

five companies today manage the 

majority of ethanol marketing in the 

U.S. With such a small number of 

companies, any one could exert a 

controlling influence on the RIN market. 

In addition, many large producers 

operate as marketers for other smaller 

producers, allowing some producers to 

be the first purchaser. As discussed for 

the previous alternative, we believe that 

we should design the RFS program to 

function smoothly under any future 

market scenario, including ones 

different from those forming the basis of 

the current EIA projections. Thus we 

believe that the concern about marketers 

exercising market power in the RIN 

market is still important, and as a result 

we do not believe that the first 

purchaser approach offers significant 

advantages over our proposed program. 

d. Owner at Time of Blending. An 

alternative approach to our proposed 

option of allowing obligated parties to 

separate RINs as soon as they gain 

ownership would prohibit all parties 

from separating a RIN from a batch of 

renewable fuel until the batch had 

actually been blended into gasoline or 

diesel. The obligated party could retain 

the RIN as soon as it gained ownership 

of the batch, but could not transfer the 

RIN or use it for compliance purposes 

until the renewable fuel that it 

represented was actually blended into 

gasoline or diesel. Thus, a RIN could be 

separated from the batch of renewable 

fuel to which it has been assigned only 

at the time of blending, and whomever 

owns the batch at the time of blending 

would also have the right to separate the 

RIN and use or transfer it. 

Although we based our proposed 

program design on the expectation that 

all renewable fuels will eventually be 

consumed as fuel, primarily through 

blending with conventional gasoline or 

diesel, this alternative approach would 

provide direct verification of blending. 

However, we do not believe that this is 

necessary in order to provide an 

enforceable program, and in fact it 

would create an additional and 

unnecessary burden for blenders. 

As discussed in Section III.D, it is not 

necessary to track renewable fuels all 

the way to the point of blending because 

we can confidently treat production 

volumes as an accurate surrogate for 

consumption. This fact provides the 

basis for our proposed program, and 

could also be used in support of the 

alternatives described previously. If 

verification of blending were required 

before a RIN could be separated from a 

batch, both obligated parties and 

blenders would be subject to additional 

recordkeeping and paperwork burdens. 

The Agency would be compelled to 

enforce activities at the blender level, 

adding about 1200 parties to the list of 

those subject to enforcement under our 

proposed program. 

By requiring refiners to wait until 

renewable fuel is blended before they 

can separate the RIN, this alternative 

approach could limit the potential for 

one refiner to purchase large volumes of 

renewable fuel with the intent of 

separating the RINs and exercising 

market power in the RIN market. 

However, we do not believe that this 

represents an advantage to this 

alternative since it could not occur 

under our proposed program either. 

There are no geographic limitations to 

RIN transfers within the 48 contiguous 

states, so obligated parties that need 

RINs can purchase them from any 

refiner who has an excess. In addition, 

RINs that have been separated from 

their assigned batches by oxygenate 

blenders represent an additional safety 

valve in the RIN market, providing 

additional assurances that no one 

refiner could exercise market power in 

the RIN market, thereby demanding an 

unreasonably high price for them. 

For these reasons, we do not believe 

that requiring renewable fuel to be 

blended into gasoline or diesel before a 

RIN could be separated from the batch 

would provide any significant 

advantages over our proposed program. 

However, we request comment on this 

alternative approach. 

e. Blender at Time of Blending. 

Although we have concluded that 

production volumes are an accurate 

surrogate for consumption, thus 

eliminating the need to measure 

renewable fuel volumes at the point of 

blending into gasoline or diesel, an 

alternative approach would do just that. 

In this alternative program approach, 

RINs would not be generated by the 

producer of the renewable fuel and 

assigned to batches. Instead, blenders 

would keep detailed records of the 

volumes of renewable fuel that they 

blended into gasoline or diesel, and 

would generate credits for those 

volumes. Blenders would be considered 

obligated parties, but their obligation 

would be considered as zero percent to 

avoid redundant obligations (i.e., to 

avoid the blender being responsible for 

blending renewable fuel into gasoline 

for which a refiner or importer also has 

an RFS program responsibility). Thus 

they would generate credits which 

could then be sold to a refiner or 

importer who needs it for compliance 

purposes. 

The blender approach would differ 

from our proposed program and all the 

other alternative approaches in that it 

would be based on actual blending 

activity, as compared to ownership of 

the renewable fuel. Under this 

alternative approach, the blender would 

not use records of batch ownership to 

establish generation of credits, but 

rather would be required to demonstrate 

that it had actually blended the 

renewable fuel into gasoline or diesel. 

Since the blender was responsible for 

blending, the blender would generate 

the credits from that blending and 

would have the right to transfer them to 

another party. 

Although blenders could use IRS fuel 

credit forms to verify the volumes of 

ethanol blended into gasoline under this 

alternative, the IRS forms would not 

provide useful information related to 

biodiesel or other renewable fuels that 

are blended into conventional gasoline 


jlentini on PROD1PC65 with PROPOSAL2
55594 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

36There is some evidence that biodiesel 

producers are operating as blenders in order to 

claim the right to the Federal excise tax credit for 

biodiesel. However, in these cases they often blend 

only very small amounts of conventional diesel into 

biodiesel, such as 0.1 volume percent. The mixture, 

identified as B99.9, is then transported to another 

blender who often adds significant additional 

quantities of conventional diesel to make blends 

such as B2 or B20. 

37Please refer to http://www.epa.gov/otaq/regs/ 

fuels/rfgforms.htm. The relevant registration forms 

for our existing fuels programs are 3520–20A, 3520–

20B, and 3520–20B1. Interested parties may wish to 

view these forms, as they may be useful in 

preparing comments on this proposed rule. 

or diesel.36 Alternative approaches to 

verifying that these other renewable 

fuels were actually blended would 

therefore need to be designed under this 

alternative, and these verifications 

would necessarily involve additional 

recordkeeping and reporting 

requirements. 

This approach would also tend to 

increase the burdens on refiners to gain 

access to credits and thus demonstrate 

compliance. A refiner who took 

ownership of a batch of renewable fuel 

could not use that batch to meet its RVO 

unless he blended it into gasoline or 

diesel himself. Such circumstances 

would create additional complexity for 

the obligated parties that are avoided by 

the more streamlined approach we are 

proposing. 

A blender approach would also be 

difficult to implement. To begin with, 

many blenders are small businesses, and 

none have been substantially regulated 

in an EPA fuel program before. We 

would be imposing upon these parties 

the primary enforcement burden 

associated with the RFS program even 

though they are not obligated for 

meeting the renewable fuel standard. 

Also, this approach would not be able 

to distinguish between cellulosic 

biomass ethanol and ethanol made from 

other feedstocks, which creates 

significant difficulties in meeting 

program requirements. 

Under a blender approach, even 

accurate records of blending would be 

difficult to verify. There are more than 

1200 blenders in the U.S. who blend 

ethanol into gasoline, in addition to 

those that blend biodiesel into 

conventional diesel fuel. Thus the 

blender approach would maximize the 

number of parties involved, overly 

complicating the compliance system. 

The enforcement burden on the Agency 

would be significant, and ultimately it 

would be likely that many claims of 

blending would go unchecked. 

Some of the concerns raised above 

could be addressed by re-introducing 

the RIN concept into a blender 

approach. For instance, the existence of 

RINs could help identify cellulosic 

biomass ethanol as such. However, if a 

RIN-based system were implemented, 

this alternative approach would become 

very similar to our proposed program, 

but with additional enforcement 

burdens placed upon blenders. As a 

result the advantages of this alternative 

approach over our proposed program 

would disappear. 

Due to the additional and unnecessary 

recordkeeping and reporting burdens 

that would be placed upon blenders 

under this alternative, the dissociation 

of credits from renewable fuels acquired 

by obligated partiers, and the likelihood 

that many blending events may go 

unchecked, we do not believe that the 

alternative blender approach should be 

adopted. 

IV. Registration, Recordkeeping, and 

Reporting Requirements 

A. Introduction 

Registration, recordkeeping and 

reporting are necessary to track 

compliance with the renewable fuels 

standard and transactions involving 

RINs. We are proposing to utilize the 

same basic forms for registration that we 

use under the reformulated gasoline 

(RFG) and anti-dumping program.37

These forms are well known in the 

regulated community and are simple to 

fill out. Information requested includes 

company and facility names and 

addresses and the identification of a 

contact person with phone number and 

e-mail address. Registrations do not 

expire and upon receipt of a completed 

registration form, EPA will issue unique 

company and facility identification 

numbers that will appear in compliance 

reports and, in the case of renewable 

fuels producers, will be incorporated in 

the unique RINs they generate for each 

batch of renewable fuel. We intend to 

use the same simplified registration 

method we use for existing fuels 

programs under 40 CFR part 80, and 

parties who have already registered with 

EPA under an existing fuels program 

will not be required to re-register and 

will be able to use their existing EPAissued company and facility registration 

numbers. 

We plan to use a simplified method 

of reporting via the Agency’s Central 

Data Exchange (CDX). CDX will permit 

us to accept reports that are 

electronically signed and certified by 

the submitter in a secure and robustly 

encrypted fashion. Guidance for 

reporting will be issued prior to 

implementation and will contain 

specific instructions and formats 

consistent with provisions in the final 

rule. We intend to accept electronic 

reports generated in virtually all 

commercially available spreadsheet 

programs and to permit parties to 

submit reports in comma delimited text, 

which can be generated with a variety 

of basic software packages. In order to 

permit maximum flexibility in meeting 

the RFS program requirements, we must 

track activities involving the creation 

and use of RINs, as well as any 

transactions such as purchase or sale of 

RINs. Reports will be included in a 

compliance database managed by EPA’s 

Office of Transportation and Air Quality 

and will be reviewed for completeness 

and for potential violations. Potential 

violations will be referred to 

enforcement personnel. 

Records related to RIN transactions 

may be kept in any format and the 

period of record retention by reporting 

parties is five (5) years, which is the 

time frame for retention under similar 

40 CFR part 80 fuels compliance 

reporting programs. Records retained 

would include copies of all compliance 

reports submitted to EPA and copies of 

product transfer documents (PTDs). 

Records would have to be provided to 

the Administrator or the Administrator’s 

representative upon request and they 

may have to be converted to a readable, 

usable format. 

B. Requirements for Obligated Parties 

and Exporters of Renewable Fuels 

1. Registration 

We are proposing that ‘‘obligated 

parties’’ including refiners, importers, 

and blenders of gasoline, as well as 

exporters of renewable fuel, must 

register with EPA by [90 DAYS AFTER 

FINAL PUBLICATION OF THE FINAL 

RULE]. Most refiners and importers are 

already registered with us under various 

regulations related to reformulated 

(RFG) and conventional gasoline or 

diesel fuel. We propose that these 

existing registrations be applicable 

under the renewable fuel standard as 

well. Exporters of renewable fuels may 

not have registered with EPA and we 

anticipate perhaps 25 new registrations 

and 25 updated registrations because of 

this program. If a party becomes subject 

to this proposed regulation after the 

effective date, then we propose that they 

must register with us and receive their 

EPA-issued company and facility 

registration numbers prior to engaging 

in any transaction involving RINs. 

Any party who is not currently 

registered with us would have to submit 

a simple registration form. We will issue 

a 4-digit company identification number 

and, for each facility registered, a 5-digit 

facility identification number. Currently 

registered parties will only be 


jlentini on PROD1PC65 with PROPOSAL2
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responsible for updating company and 

facility records as the need to update 

routine information arises, for example, 

if corporate points of contact or 

addresses change. Currently registered 

refiners and importers would continue 

to use their existing 4-digit company 

and 5-digit facility identification 

numbers. 

2. Reporting 

There are three types of reports that 

would be required of obligated parties 

and exporters of renewable fuel. Reports 

would be required to be submitted on an 

annual basis by the February 28 

following a given January through 

December annual compliance period. 

The first type of report would provide 

the compliance demonstration. It would 

require obligated parties to provide 

information about their annual volume 

of gasoline produced or imported, and 

would require exporters to provide 

information about their annual volume 

of renewable fuel exported. The report 

would also describe the calculation of 

their corresponding renewable volume 

obligation (RVO), a listing of the RINs 

applied towards the RVO, any deficit 

carried over from the previous year, and 

any deficit carried into the next year. 

The second type of report would 

provide detailed transactional 

information regarding RINs. It would be 

akin to credit trading reports submitted 

by refiners and importers under other 

fuels programs in 40 CFR part 80, such 

as the gasoline sulfur program. The 

purpose of this report would be to 

document the ownership, transfer and 

use of RINs and to track expired RINs. 

As such, and noted below, these reports 

would be required of any party that 

owns RINs during the compliance 

period covered by the report. The 

transactional report is necessary because 

compliance with the RVO is primarily 

demonstrated through self-reporting of 

RIN trades and therefore it is necessary 

for Agency personnel to be able to link 

transactions involving each unique RIN 

in order to verify compliance. We will 

be able to import reports into our 

compliance database and match RINs to 

transactions across their entire journey 

from generation to use. As with our 

other 40 CFR part 80 compliance-onaverage and credit trading programs, 

many potential violations are expected 

to be self-reported. Because the use of 

RINs permits great flexibility in meeting 

the RVO, we believe that obligated 

parties and others who create and 

handle RINs (including brokers) will 

benefit from self-reporting. 

The third type of report will 

summarize RIN activities for the 

previous year and will include the total 

number of RINs owned, used for 

compliance, transferred and expired. 

This report would not include details of 

every RIN owned or used, since this 

information would be included in the 

compliance and transactional reports. 

Instead, this third report would simply 

summarize the total number of RINs 

falling into different categories. 

All reports submitted to us would 

have to be signed and certified as true 

and correct by a responsible corporate 

officer. This can be done electronically. 

As discussed above, we plan to utilize 

a highly simplified electronic method of 

reporting via the Agency’s Central Data 

Exchange that is secure, provides 

encryption and reliable electronic 

signatures, and that permits us to accept 

reports in the submitter’s choice of 

simple comma delimited text or 

commercially available spreadsheet 

packages. 

We are proposing annual reporting 

only. However, we encourage comments 

related to the frequency of reporting. We 

are particularly interested in comments 

related to the frequency of transactional 

reports related to RINs and whether 

these reports should be submitted 

quarterly rather than annually. We also 

request comment on our proposed 

requirement that three distinct types of 

reports be submitted for each calendar 

year, specifically whether these reports 

could be simplified or whether a smaller 

number of reports could provide the 

same information. 

3. Recordkeeping 

The proposed recordkeeping 

requirements for obligated parties and 

exporters of renewable fuel support the 

enforcement of the use of RINs for 

compliance purposes. Product transfer 

documents (PTDs) are central to 

tracking individual RINs through the 

fungible distribution system when those 

RINs are assigned to batches of 

renewable fuel. PTDs are customarily 

issued in the course of business (i.e., 

issuing them is a ‘‘customary business 

practice’’) and are familiar to parties 

who transfer or receive fuel. As with 

other fuels programs, PTDs may take 

many forms, including bills of lading, as 

long as they travel with the volume of 

renewable fuel being transferred. 

Specifically, we propose that on each 

occasion any person transfers 

ownership of renewable fuels subject to 

this proposed regulation that they 

provide the transferee documents 

identifying the renewable fuel and 

containing identifying information 

including the name and address of the 

transferor and transferee, the EPAissued company and facility IDs of the 

transferor and transferee, the volume of 

renewable fuel that is being transferred, 

the location of the renewable fuel at the 

time of transfer, and the unique RIN 

associated with the volume of fuel being 

transferred, if any. PTDs are used by all 

parties in the distribution chain down to 

the retail outlet or wholesale purchaserconsumer facility that dispenses it into 

motor vehicles. 

Except for transfers to truck carriers, 

retailers or wholesale purchaserconsumers, product codes describing 

various attributes of the fuel may be 

used to convey the information required 

for PTDs, as long as the codes are clearly 

understood by each transferee. 

Therefore, refiners and importers and 

exporters of renewable fuel may use 

codes. The RIN would always have to 

appear on each PTD in its entirety 

before it is separated from a batch, since 

it is a unique identification number and 

cannot be summarized by a shorter 

code. 

Obligated parties and exporters of 

renewable fuel would have to keep 

copies of PTDs and of all compliance 

reports submitted to EPA for a period of 

not less than five (5) years. The five year 

period is common to all our 40 CFR part 

80 programs and is a reasonable period 

to retain records in the event a potential 

violation is reported and must be 

investigated and pursued by 

enforcement personnel. They would 

also have to keep information related to 

the sale, purchase, brokering and 

trading of RINs that support the 

information they report to EPA. Refiners 

and importers would be responsible for 

providing records to the Administrator 

or the Administrator’s authorized 

representative in a usable format upon 

request. 

C. Requirements for Producers and 

Importers of Renewable Fuel 

1. Registration 

We propose that any producer or 

importer of renewable fuel must register 

by [90 DAYS AFTER THE DATE OF 

FINAL PUBLICATION OF THE FINAL 

RULE]. The registration requirements 

are the same as those for refiners and 

importers of gasoline, as described 

above. Renewable fuel producers were 

not previously required to register with 

EPA and we anticipate around 280 new 

registrants as a result of this proposed 

registration requirement. Although 

renewable fuels producers are not 

‘‘obligated parties,’’ they are the parties 

who generate RINs. As mentioned above 

in IV.B.1, the EPA-issued registration 

numbers will be part of the unique RIN 

generated by the producer or importer of 

renewable fuel. In order to support 

effective recordkeeping and reporting 


jlentini on PROD1PC65 with PROPOSAL2
55596 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

for compliance purposes, we believe it 

is necessary for them and any party who 

generates or owns RINs to register with 

the Agency. 

Registration is a simple process and 

there is no expiration date associated 

with a registration. However, 

registration information may be updated 

by the registrant as needed, for example, 

if a mailing address changes. The 

information collected includes company 

name and address; facility name(s) and 

address(es); and a contact person’s 

name, phone number and e-mail 

address. Any party who is not currently 

registered with us would have to submit 

registration forms. We will issue a 4- 

digit company identification number 

and, for each facility registered, a 5-digit 

facility identification number. If a party 

becomes subject to this proposed 

regulation after the effective date, then 

we propose that they must register with 

us and receive their EPA-issued 

company and facility identification 

numbers prior to generating or holding 

any RINs. 

We also propose that small volume 

domestic producers of renewable fuels, 

those who produce less than 10,000 

gallons per year, be allowed to remain 

unregistered. This proposed provision 

would free them from recordkeeping 

and reporting requirements, but it 

would also preclude them from 

generating RINs. 

2. Reporting 

Renewable fuel producers and 

importers would be required to submit 

three different annual reports by 

February 28, reflecting activity during 

the previous calendar year. The first 

report would be an annual report that 

reflects the generation of RINs. This 

report would identify each batch of 

renewable fuel produced or imported 

during the previous year and the RINs 

generated for each batch. This annual 

report would provide information about 

the production date, renewable fuel type 

and volume of renewable fuel produced 

or imported. For specific information 

about how RINs are actually generated, 

please refer to the discussion in Section 

III.D.2 of this preamble. 

Like any of the parties who can own 

RINs, a renewable fuel producer would 

also have to submit a second type of 

report detailing transactional 

information regarding RINs. This report 

would list the RINs which they own at 

the end of the reporting period as well 

as any RINs they have acquired from 

other parties or have transferred to other 

parties, identifying which parties took 

part in the transfer. This report would 

be similar to the transaction report 

described below required of RIN owners 

who are not obligated parties, exporters, 

or producers of renewable fuels. 

Finally, each producer or importer of 

renewable fuel would be required to 

submit a third annual report 

summarizing RIN activities for the 

previous year. This report would 

include the total number of RINs 

generated, owned, transferred, and 

expired. 

All reports would have to be signed 

and certified as true and correct by a 

responsible corporate officer. This can 

be done electronically. As discussed 

above, we plan to utilize a highly 

simplified electronic method of 

reporting via the Agency’s Central Data 

Exchange that is secure, provides 

encryption and reliable electronic 

signatures, and that permits generation 

of reports in the submitter’s choice of 

simple comma delimited text or 

commercially available spreadsheet 

packages. 

We request comment on our proposed 

requirement that three distinct types of 

reports be submitted for each calendar 

year, specifically whether these reports 

could be simplified or whether a smaller 

number of reports could provide the 

same information. 

3. Recordkeeping 

The proposed recordkeeping 

requirements for renewable fuels 

producers support the enforcement of 

the use of RINs for compliance 

purposes. Product transfer documents 

(PTDs) are central to tracking individual 

RINs through the fungible distribution 

system when those RINs are assigned to 

batches of renewable fuel. PTDs are 

customarily generated and issued in the 

course of business (i.e. issuing them is 

a ‘‘customary business practice’’) and 

are familiar to parties who transfer or 

receive fuel. As with other fuels 

programs, PTDs may take many forms, 

including bills of lading, as long as they 

travel with the volume of renewable fuel 

being transferred. Specifically, we 

propose that on each occasion any 

person transfers ownership of renewable 

fuels subject to this proposed regulation 

that they provide the transferee 

documents identifying the renewable 

fuel and containing identifying 

information including the name and 

address of the transferor and transferee, 

the EPA-issued company and facility 

IDs of the transferor and transferee, the 

volume of renewable fuel that is being 

transferred, the location of the 

renewable fuel at the time of transfer, 

and the unique RIN associated with the 

volume of fuel being transferred, if any. 

PTDs are used by all parties in the 

distribution chain down to the retail 

outlet or wholesale purchaser-consumer 

facility that dispenses it into motor 

vehicles. 

Except for transfers to truck carriers, 

retailers or wholesale purchaserconsumers, product codes may be used 

to convey the information required for 

PTDs, as long as the codes are clearly 

understood by each transferee. 

Therefore, renewable fuels producers 

may use codes. The RIN would always 

have to appear on each PTD in its 

entirety before it was separated from the 

batch, since it is a unique identification 

number and cannot be summarized by 

a shorter code. 

Renewable fuels producers would 

have to keep copies of PTDs and of all 

compliance reports submitted to EPA 

for a period of not less than five (5) 

years. They would also have to keep 

information related to the sale, 

purchase, brokering and trading of RINs. 

Upon request, renewable fuels 

producers or importers would be 

responsible for providing 

documentation of PTDs to the 

Administrator or the Administrator’s 

authorized representative in a usable 

format. 

D. Requirements for Other Parties Who 

Own RINs 

1. Registration 

We propose that other parties who 

intend to own RINs, and who are not 

obligated parties, exporters of renewable 

fuels, or renewable fuels producers or 

importers, must also register before 

ownership of any RINs is assumed. The 

registration requirements are the same 

as those for other parties discussed 

previously in Sections IV.B.1 and IV.C.1 

above, and require the registrant to 

provide very basic information about 

the company, its facility or facilities, 

and a contact person. The registration is 

on very simple forms provided by EPA. 

A variety of parties may own RINs 

including (but certainly not limited to) 

marketers, blenders, terminal operators, 

and jobbers. (As is mentioned in the 

previous two sections, obligated parties 

and renewable producers may also own 

RINs but have other reporting 

responsibilities, as well.) 

It is possible to own RINs separately 

from batches of renewable fuel. For 

example, a broker might be expected to 

own RINs in this fashion. Any party 

who is not currently registered with us 

and who intends to own RINs would 

have to submit a simple registration 

form, as described above. We anticipate 

about 1,500 new registrants as a result 

of this proposed registration 

requirement, although an exact 

estimation of the number of parties that 

will constitute this group is difficult to 


jlentini on PROD1PC65 with PROPOSAL2
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55597 

38Sec. 1501(b) of the Energy Policy Act of 2005. 

make. As with the other parties 

described in this Section, we will issue 

a 4-digit company identification number 

and, for each facility registered, a 5-digit 

facility identification number. If a party 

becomes subject to this proposed 

regulation after the effective date, then 

we propose that they must register with 

us and receive their EPA-issued 

company and facility identification 

numbers prior to owning any RINs. 

2. Reporting 

Parties who own RINs would be 

required to submit two types of annual 

reports by February 28, representing 

activity in the previous calendar year. 

The first report would document RIN 

transactions. This report is akin to the 

credit trading reports submitted by 

refiners and importers under other fuels 

programs in 40 CFR part 80 and is the 

same as the second report described for 

obligated parties in some detail in 

Section IV.B.2 above. 

The second type of report would 

summarize RIN activities for the 

previous year, including the total 

number of RINs owned, transferred, and 

expired. This report would not include 

details of every RIN owned or used, 

since this information would be 

included in the transactional report. 

Instead, this report would simply 

summarize the total number of RINs 

falling into different categories. 

All reports would have to be signed 

and certified as true and correct by a 

responsible corporate officer. This can 

be done electronically. As discussed 

above, we plan to utilize a highly 

simplified electronic method of 

reporting via the Agency’s Central Data. 

As discussed above, we are seeking 

comments on the frequency of reporting, 

especially with regard to RIN 

transactions. We are proposing annual 

reporting, but are seeking comments on 

whether reporting should be quarterly. 

We also request comment on our 

proposed requirement that two distinct 

types of reports be submitted for each 

calendar year, specifically whether 

these reports could be simplified or 

whether a smaller number of reports 

could provide the same information. 

3. Recordkeeping 

The proposed recordkeeping 

requirements for parties who own RINs 

support the enforcement of the use of 

RINs for compliance purposes. Product 

transfer documents (PTDs) are central to 

tracking individual RINs through the 

fungible distribution system when those 

RINs are assigned to batches of 

renewable fuel. PTDs are customarily 

generated and issued in the course of 

business (i.e., issuing them is a 

‘‘customary business practice’’) and are 

familiar to parties who transfer or 

receive fuel. As with other fuels 

programs, PTDs may take many forms, 

including bills of lading, as long as they 

travel with the volume of renewable fuel 

being transferred. Specifically, we 

propose that on each occasion any 

person transfers ownership of RINs 

(whether assigned to batches of 

renewable fuel or not) that they provide 

the transferee documents identifying the 

RIN and containing identifying 

information including the name and 

address of the transferor and transferee, 

the EPA-issued company and facility 

IDs of the transferor and transferee, and 

the unique RINs that are being 

transferred. Typically, parties who own 

RINs connected with batches of fuel 

would handle PTDs; however, parties 

who own RINs separate from batches 

may not. A party who owns RINs in 

connection with fuel and who received 

a PTD would be responsible for meeting 

requirements related to PTDs. 

Parties who own RINs but who are not 

obligated parties, exporters of renewable 

fuel, or renewable fuel producers or 

importers would have to keep copies of 

PTDs associated with RIN transfers and 

of all compliance reports submitted to 

EPA for a period of not less than five (5) 

years. They would also have to keep 

information related to the sale, 

purchase, brokering and trading of RINs. 

Upon request, owners of RINs would be 

responsible for providing records to the 

Administrator or the Administrator’s 

authorized representative in a usable 

format. 

V. What Acts Are Prohibited and Who 

Is Liable for Violations? 

The prohibition and liability 

provisions applicable to this proposed 

RFS program would be similar to those 

of other gasoline programs. The 

proposed rule identifies certain 

prohibited acts, such as a failure to 

acquire sufficient RINs to meet a party’s 

renewable fuel obligation (RVO), 

producing or importing a renewable fuel 

that is not assigned a proper RIN, 

creating or transferring invalid RINs, or 

transferring RINs that are not identified 

by proper RIN numbers. Any person 

subject to a prohibition would be held 

liable for violating that prohibition. 

Thus, for example, an obligated party 

would be liable if the party failed to 

acquire sufficient RINs to meet its RVO. 

A party who produces or imports 

renewable fuels would be liable for a 

failure to assign proper RINs to batches 

of renewable fuel produced or imported. 

Any party, including an obligated party, 

would be liable for transferring a RIN 

that was not properly identified. 

In addition, any person who is subject 

to an affirmative requirement under the 

RFS program would be liable for a 

failure to comply with the requirement. 

For example, an obligated party would 

be liable for a failure to comply with the 

annual compliance reporting 

requirements. A renewable fuel 

producer or importer would be liable for 

a failure to comply with the applicable 

batch reporting requirements. Any party 

subject to recordkeeping or product 

transfer document requirements would 

be liable for a failure to comply with 

these requirements. Like other EPA 

fuels programs, the proposed rule 

provides that a party who causes 

another party to violate a prohibition or 

fail to comply with a requirement may 

be found liable for the violation. 

The Energy Act 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).38

Accordingly, under the proposed rule, 

any person who violates any prohibition 

or requirement of the RFS program may 

be subject to civil penalties for every 

day of each such violation and the 

amount of economic benefit or savings 

resulting from the violation. Under the 

proposed rule, a failure to acquire 

sufficient RINs to meet a party’s 

renewable fuels obligation would 

constitute a separate day of violation for 

each day the violation occurred during 

the annual averaging period. 

As discussed above and in Section 

III.D, the regulations would prohibit any 

party from creating or transferring 

invalid RINs. These invalid RIN 

provisions would apply regardless of 

the good faith belief of a party that the 

RINs were valid. These enforcement 

provisions are necessary to ensure the 

RFS program goals are not compromised 

by illegal conduct in the creation and 

transfer of RINs. 

As in other motor vehicle fuel credit 

programs, the regulations would address 

the consequences if an obligated party 

was found to have used invalid RINs to 

demonstrate compliance with its RVO. 

In this situation, the refiner or importer 

that used the invalid RINs would be 

required to deduct any invalid RINs 

from its compliance calculations. The 

refiner or importer would be liable for 

violating the standard if the remaining 

number of valid RINs was insufficient to 

meet its RVO, and the obligated party 

might be subject to monetary penalties 

if it used invalid RINs in its compliance 

demonstration. In determining what 

penalty is appropriate, if any, we would 

consider a number of factors, including 


jlentini on PROD1PC65 with PROPOSAL2
55598 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

39The June 2006 ethanol production baseline was 

generated from a variety of data sources including 

Renewable Fuels Association (RFA), Ethanol 

Biorefinery Locations (Updated June 19, 2006); 

Ethanol Producer Magazine (EPM), U.S. & Canada 

Fuel Ethanol Plant Map (Spring 2006); and 

International Fuel Quality Center (IFQC), Special 

Biofuels Report #75 (April 11, 2006) as well as 

ethanol producer websites. The production baseline 

includes small-scale ethanol production facilities as 

well as former food-grade ethanol plants that have 

since transitioned into the fuel-grade ethanol 

market. Where applicable, current ethanol plant 

production levels were used to represent plant 

capacity, as nameplate capacities are often 

underestimated. 

whether the obligated party did in fact 

procure sufficient valid RINs to cover 

the deficit created by the invalid RINs, 

and whether the purchaser was indeed 

a good faith purchaser based on an 

investigation of the RIN transfer. A 

penalty might include both the 

economic benefit of using invalid RINs 

and/or a gravity component. 

Although an obligated party would be 

liable under our proposed program for 

a violation if it used invalid RINs for 

compliance purposes, we would 

normally look first to the generator or 

seller of the invalid RINs both for 

payment of penalty and to procure 

sufficient valid RINs to offset the invalid 

RINs. However, if, for example, that 

party was out of business, then attention 

would turn to the obligated party who 

would have to obtain sufficient valid 

RINs to offset the invalid RINs. 

Because there are no standards under 

the RFS rule that may be measured 

downstream, we believe that a 

presumptive liability scheme, i.e., a 

scheme in which parties upstream from 

the facility where the violation is found 

are presumed liable for the violation, 

would not be applicable under the RFS 

program. We request comment on 

whether a presumptive liability scheme 

may have application under the RFS 

rule. We also request comment on the 

need for additional prohibition and 

liability provisions specific to the 

proposed RFS program. 

VI. Current and Projected Renewable 

Fuel Production and Use 

While the definition of renewable fuel 

does not limit compliance with the 

standard to any one particular type of 

renewable fuel, ethanol is currently the 

most prevalent renewable fuel blended 

into gasoline today. Biodiesel represents 

another renewable fuel, which while not 

as widespread as ethanol use (in terms 

of volume), has been increasing in 

production capacity and use over the 

last several years. This section provides 

a brief overview of the ethanol and 

biodiesel industries today and how they 

are projected to grow into the future. 

A. Overview of U.S. Ethanol Industry 

and Future Production/Consumption 

1. Current Ethanol Production 

As of June 2006, there were 102 

ethanol production facilities operating 

in the United States with a combined 

production capacity of approximately 

4.9 billion gallons per year.39 All of the 

ethanol currently produced comes from 

grain or starch-based feedstocks that can 

easily be broken down into ethanol via 

traditional fermentation processes. The 

majority of ethanol (almost 93 percent 

by volume) is produced exclusively 

from corn. Another 7 percent comes 

from a blend of corn and/or similarly 

processed grains (milo, wheat, or barley) 

and less than 1 percent is produced 

from waste beverages, cheese whey, and 

sugars/starches combined. A summary 

of ethanol production by feedstock is 

presented in Table VI.A.1–1. 

TABLE VI.A.1–1.—2006 U.S. ETHANOL PRODUCTION BY FEEDSTOCK

Plant feedstock Capacity 

MMGal/yr 

Percent of 

capacity 

Number of 

plants 

Percent of 

plants 

Corn a ............................................................................................................................... 4,516 92.7 85 83.3 

Corn/Milo .......................................................................................................................... 162 3.3 5 4.9 

Corn/Wheat ...................................................................................................................... 90 1.8 2 2.0 

Corn/Barley ...................................................................................................................... 40 0.8 1 1.0 

Milo/Wheat ....................................................................................................................... 40 0.8 1 1.0 

Waste Beverage b ............................................................................................................ 16 0.3 5 4.9 

Cheese Whey .................................................................................................................. 8 0.2 2 2.0 

Sugars & Starches ........................................................................................................... 2 0.0 1 1.0 

Total .......................................................................................................................... 4,872 100.0 102 100.0 

a Includes seed corn. 

b Includes brewery waste. 

There are a total of 94 plants 

processing corn and/or other similarly 

processed grains. Of these facilities, 84 

utilize dry milling technologies and the 

remaining 10 plants rely on wet-milling 

processes. Dry mill ethanol plants grind 

the entire kernel and produce only one 

primary co-product: distillers’ grains 

with solubles (DGS). The co-product is 

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

agricultural market as animal feed. 

Carbon dioxide is also produced in the 

process and may be recovered as a 

saleable product. In contrast to dry mill 

plants, wet mill facilities separate the 

kernel prior to processing and in turn 

produce other co-products (usually 

gluten feed, gluten meal, and oil) in 

addition to DGS. Wet mill plants are 

generally more costly to build but are 

larger in size on average. As such, 

approximately 23 percent of the current 

ethanol production comes from the 10 

previously-mentioned wet mill 

facilities. 

The remaining 8 plants which process 

waste beverages, cheese whey, or 

sugars/starches, operate differently than 

their grain-based counterparts. These 

facilities do not require milling and 

instead operate a more simplistic 

enzymatic fermentation process. 

In addition to grain and starch-toethanol production, another method 

exists for producing ethanol from a 

more diverse feedstock base. This 

process involves converting cellulosic 

feedstocks such as bagasse, wood, straw, 

switchgrass, and other biomass into 

ethanol. Cellulose consists of tightlylinked polymers of starch, and 

production of ethanol from it requires 

additional steps to convert these 

polymers into fermentable sugars. 

Scientists are actively pursuing acid and 

enzyme hydrolysis to achieve this goal, 

but the technologies are still not fully 

developed for large-scale commercial 

production. As of June 2006, there were 

no U.S ethanol plants processing 

cellulosic feedstocks. Currently, the 

only known cellulose-to-ethanol plant 

in North America is Iogen in Canada, 

which produces approximately one 


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million gallons of ethanol per year from 

wood chips. For a more detailed 

discussion on cellulosic ethanol 

production/technologies, refer to 

Section 7.1.2 of the Draft Regulatory 

Impact Analysis (DRIA). 

The ethanol production process is 

relatively resource-intensive and 

requires the use of water, electricity and 

steam. Steam needed to heat the process 

is generally produced onsite or by other 

dedicated boilers. Of today’s 102 

ethanol production facilities, 98 burn 

natural gas, 2 burn coal, 1 burns coal 

and biomass, and 1 burns syrup from 

the process to produce steam. A 

summary of ethanol production by plant 

energy source is found below in Table 

VI.A.1–2. 

TABLE VI.A.1–2.—2006 U.S. ETHANOL PRODUCTION BY ENERGY SOURCE

Energy source Capacity 

MMGal/yr 

Percent of 

capacity 

Number of 

plants 

Percent of 

plants 

Natural Gas a ................................................................................................................... 4,671 95.9 98 96.1 

Coal .................................................................................................................................. 102 2.1 2 2.0 

Coal & Biomass ............................................................................................................... 50 1.0 1 1.0 

Syrup ................................................................................................................................ 49 1.0 1 1.0 

Total .......................................................................................................................... 4,872 100.0 102 100.0 

a Includes a natural gas facility which is considering transitioning to coal. 

Currently, 7 of the 102 ethanol plants 

utilize co-generation or combined heat 

and power (CHP) technology. CHP is a 

mechanism for improving overall plant 

efficiency. CHP facilities produce their 

own electricity (or coordinate with the 

local municipality) and use otherwisewasted exhaust gases to help heat their 

process, reducing the overall demand 

for boiler fuel. 

The majority of ethanol is produced 

in the Midwest within PADD 2—not 

surprisingly, where most of the corn is 

grown. Of the 102 U.S. ethanol 

production facilities, 93 are located in 

Midwest. The PADD 2 facilities account 

for about 97 percent (or 4.7 billion 

gallons per year) of the total domestic 

ethanol production, as shown in Table 

VI.A.1–3. 

TABLE VI.A.1–3.—2006 U.S. ETHANOL PRODUCTION BY PADD 

PADD Capacity 

MMgal/yr 

Percent of 

capacity 

Number of 

plants 

Percent of 

plants 

PADD 1 ............................................................................................................................ 0.4 0.0 1 1.0 

PADD 2 ............................................................................................................................ 4,710 96.7 93 91.2 

PADD 3 ............................................................................................................................ 30 0.6 1 1.0 

PADD 4 ............................................................................................................................ 98 2.0 4 3.0 

PADD 5 ............................................................................................................................ 34 0.7 3 2.9 

Total .......................................................................................................................... 4,872 100.0 102 100.0 

Leading the Midwest in ethanol 

production are Iowa, Illinois, Nebraska, 

Minnesota, and South Dakota with a 

combined capacity of 3.9 billion gallons 

per year. Together, these five states’ 69 

ethanol plants account for 80 percent of 

the total domestic product. Although 

the majority of ethanol production 

comes from the Midwest, there is a 

sprinkling of plants situated outside the 

corn belt ranging from California to 

Tennessee all the way down to Georgia. 

The U.S. ethanol industry is currently 

comprised of a mixture of corporations 

and farmer-owned cooperatives (coops). More than half (55) of today’s 

plants are owned by corporations and, 

on average, these plants are larger in 

size than farmer-owned co-ops. 

Accordingly, company-owned plants 

account for nearly 65 percent of the total 

U.S. ethanol production capacity. 

Additionally, 45 percent of the total 

capacity comes from 22 plants owned 

by just 8 different companies. 

2. Expected Growth in Ethanol 

Production 

Over the past 25 years, domestic fuel 

ethanol production has steadily 

increased due to technological 

advances, environmental regulation 

(e.g., oxygenate requirements in ozone 

and carbon monoxide non-attainment 

areas), and the rising cost of crude oil. 

More recently, ethanol production has 

soared due to state MTBE bans, steep 

increases in crude oil prices, and 

producer tax incentives. As shown 

below in Figure VI.A.2–1, over the past 

three years, domestic ethanol 

production has nearly doubled from 2.1 

billion gallons in 2002 to 4.0 billion 

gallons in 2005. 


jlentini on PROD1PC65 with PROPOSAL2
55600 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

40Under construction plant locations, capacities, 

feedstocks, and energy sources as well as planned/ 

proposed plant locations and capacities were 

derived from a variety of data sources including 

Renewable Fuels Association (RFA), Ethanol 

Biorefinery Locations (Updated June 19, 2006); 

Ethanol Producer Magazine (EPM), U.S. & Canada 

Fuel Ethanol Plant Map (Spring 2006); and 

International Fuel Quality Center (IFQC), Special 

Biofuels Report #75 (April 11, 2006) as well as 

ethanol producer Web sites. 

EPA forecasts ethanol production to 

continue to grow into the future. In 

addition to the past impacts of Federal 

and state tax incentives, as well as the 

more recent impacts of state ethanol 

mandates and the removal of MTBE 

from all U.S. gasoline, record-high crude 

oil prices are expected to continue to 

drive up demand for ethanol. As a 

result, the nation is on track to exceed 

the renewable fuel volume requirements 

contained in the Act. Today’s ethanol 

production capacity (4.9 billion gallons) 

is already exceeding the 2006 renewable 

fuel requirement (4.0 billion gallons). In 

addition, there is another 2.5 billion 

gallons of ethanol production capacity 

currently under construction.40 A 

summary of the new construction and 

expansion projects currently underway 

(as of June 2006) is found in Table 

VI.A.2–1. 

TABLE VI.A.2–1.—UNDER CONSTRUCTION U.S. ETHANOL PLANT CAPACITY

2006 ETOH baseline New construction Plant expansions 2006 baseline + 

UC a

MMGal/yr Plants MMGal/yr Plants MMGal/yr Plants MMGal/yr Plants 

PADD 1 ............................................................ 0.4 1 0 0 0 0 0.4 1 

PADD 2 ............................................................ 4,710 93 2,048 35 252 8 7,010 128 

PADD 3 ............................................................ 30 1 30 1 0 0 60 2 

PADD 4 ............................................................ 98 4 50 1 7 1 155 5 

PADD 5 ............................................................ 34 3 90 2 0 0 124 5 


jlentini on PROD1PC65 with PROPOSAL2EP22SE06.002</GPH>
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55601 

TABLE VI.A.2–1.—UNDER CONSTRUCTION U.S. ETHANOL PLANT CAPACITY—Continued 

2006 ETOH baseline New construction Plant expansions 2006 baseline + 

UC a

MMGal/yr Plants MMGal/yr Plants MMGal/yr Plants MMGal/yr Plants 

Total .......................................................... 4,872 102 2,218 39 259 9 7,349 141 

a Under Construction. 

A select group of builders, technology 

providers, and construction contractors 

are completing the majority of the 

construction projects described in Table 

VI.A.2–1. As such, the completion dates 

of these projects are staggered over 

approximately 18 months, resulting in 

the gradual phase-in of ethanol 

production shown in Figure VI.A.2–2. 

As shown in Table VI.A.2–1 and 

Figure VI.A.2–2, once all the 

construction projects currently 

underway are complete (estimated by 

December 2007), the resulting U.S. 

ethanol production capacity would be 

over 7.3 billion gallons. Together with 

estimated biodiesel production (300 

million gallons by 2012), this would be 

more than enough renewable fuel to 

satisfy the 2012 renewable fuel 

requirement (7.5 billion gallons) 

contained in the Act. However, ethanol 

production is not expected to stop here. 

There are more and more ethanol 

projects being announced each day. 

Many of these potential projects are at 

various stages of planning, such as 

conducting feasibility studies, gaining 

city/county approval, applying for 

permits, applying for financing/ 

fundraising, or obtaining contractor 

agreements. Other projects have been 

proposed or announced, but have not 

entered the formal planning process. If 

all these plants were to come to fruition, 

the combined domestic ethanol 

production could exceed 20 billion 

gallons as shown in Table VI.A.2–2. 


jlentini on PROD1PC65 with PROPOSAL2EP22SE06.003</GPH>
55602 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

41We anticipate a ramp-up in cellulosic ethanol 

production in the years to come so that capacity 

exists to satisfy the 2013 Act’s requirement (250 

million gallons of cellulosic biomass ethanol). 

Therefore, for subsequent analysis purposes, we 

have assumed that 250 million gallons of ethanol 

would come from cellulosic biomass sources by 

2012. 

42EIA Monthly Energy Review, June 2006 (Table 

10.1: Renewable Energy Consumption by Source, 

Appendix A: Thermal Conversion Factors). 

43File containing historical RFG MTBE usage 

obtained from EIA representative on March 9, 2006. 

44EIA 2004 Petroleum Marketing Annually (Table 

48: Prime Supplier Sales Volumes of Motor 

TABLE VI.A.2–2.—POTENTIAL U.S. ETHANOL PRODUCTION PROJECTS

2006 baseline + UC a Planned Proposed Total ETOH potential 

MMGal/yr Plants MMGal/yr Plants MMGal/yr Plants MMGal/yr Plants 

PADD 1 .......................................................... 0 .4 1 250 3 1,005 21 1,255 25 

PADD 2 .......................................................... 7,010 128 1,940 15 7,508 90 16,458 233 

PADD 3 .......................................................... 60 2 108 1 599 9 767 12 

PADD 4 .......................................................... 155 5 0 0 815 14 970 19 

PADD 5 .......................................................... 124 5 128 2 676 18 928 25 

Total ........................................................ 7,349 141 2,426 21 10,603 152 20,378 314 

a Under Construction. 

However, although there is clearly a 

great potential for growth in ethanol 

production, it is unlikely that all the 

announced projects would actually 

reach completion in a reasonable 

amount of time. There is no precise way 

to know exactly which plants would 

come to fruition in the future; however, 

we’ve chosen to focus our further 

discussions on only those plants which 

are under construction or in the final 

planning stages (denoted as ‘‘planned’’

above in Table VI.A.2–2). The 

distinction between ‘‘planned’’ versus 

‘‘proposed’’ is that as of June 2006 

planned projects had completed 

permitting, fundraising/financing, and 

had builders assigned with definitive 

construction timelines whereas 

proposed projects did not. 

As shown in Table VI.A.2–2, once all 

the under construction and planned 

projects are complete (by 2012 or 

sooner), the resulting U.S. ethanol 

production capacity would be 9.8 

billion gallons, exceeding the 2012 EIA 

demand estimate (9.6 billion gallons). 

This forecasted growth would double 

today’s production capacity and greatly 

exceed the 2012 renewable fuel 

requirement (7.5 billion gallons). In 

addition, domestic ethanol production 

would be supplemented by imports, 

which are also expected to increase in 

the future (as discussed in DRIA Section 

1.5). 

Of the 60 forecasted new ethanol 

plants (39 under construction and 21 

planned), all would (at least initially) 

rely on grain-based feedstocks. Of the 

plants, 56 would rely exclusively on 

corn as a feedstock. As for the remaining 

plants: Two would rely on both corn 

and milo, one would process molasses 

and sweet sorghum, and the last would 

start off processing corn and then 

transition into processing bagasse, rice 

hulls, and wood. 

Under the Energy Act, the RFS 

program requires that 250 million 

gallons of the renewable fuel consumed 

in 2013 and beyond meet the definition 

of cellulosic biomass ethanol. As 

discussed in Section III.B.1, the Act 

defines cellulosic biomass ethanol as 

ethanol derived from any lignocellulosic 

or hemicellulosic matter that is 

available on a renewable or recurring 

basis including dedicated energy crops 

and trees, wood and wood residues, 

plants, grasses, agricultural residues, 

fibers, animal wastes and other waste 

materials, and municipal solid waste. 

The term also includes any ethanol 

produced in facilities where animal or 

other waste materials are digested or 

otherwise used to displace 90 percent of 

more of the fossil fuel normally used in 

the production of ethanol. 

Of the 60 forecasted plants, only one 

is expected to meet the definition of 

‘‘cellulosic biomass ethanol’’ based on 

feedstocks. The planned 108 MMgal/yr 

facility would start off processing corn 

and then transition into processing 

bagasse, rice hulls, and wood (cellulosic 

feedstocks). It is unclear as to whether 

this facility would be processing 

cellulosic material by 2013, however 

there are several other facilities that 

could potentially meet the Act’s 

definition of cellulosic ethanol based on 

plant energy sources. In total, there are 

seven ethanol plants that burn or plan 

to burn renewable feedstocks to generate 

steam for their processes. As shown in 

Table VI.A.1–2, two existing plants burn 

renewable feedstocks. One plant burns a 

combination of coal and biomass and 

the other burns syrup from the 

production process. Together these 

existing plants have a combined ethanol 

production capacity of 99 MMgal/yr. 

Additionally, there are four under 

construction ethanol plants which plan 

to burn renewable fuels. One plant 

plans to burn a combination of coal and 

biomass, two plants plan to rely on 

manure/syngas, and the other plans to 

start up burning natural gas and then 

transition to biomass. Together these 

under construction facilities have a 

combined ethanol production capacity 

of 87 MMgal/yr. Finally, a planned 275 

MMgal/yr ethanol production facility 

plans to burn a combination of coal, 

tires, and biomass. Depending on how 

much fossil fuel is displaced by these 

renewable feedstocks (on a plant-byplant basis), a portion or all of the 

aforementioned ethanol production (up 

to 461 MMgal/yr) could potentially 

qualify as ‘‘cellulosic biomass ethanol’’

under the Act. Combined with the 108 

MMgal/yr plant planning to process 

renewable feedstocks, the total 

cellulosic potential could be as high as 

569 MMgal/yr in 2013. Even if only half 

of this ethanol were to end up 

qualifying as cellulosic biomass ethanol, 

it would still be more than enough to 

satisfy the Act’s cellulosic requirement 

(250 million gallons).41

3. Current Ethanol and MTBE 

Consumption 

To understand the impact of the 

increased ethanol production/use on 

gasoline properties and in turn overall 

air quality, we first need to gain a better 

understanding of where ethanol is used 

today and how the picture is going to 

change in the future. As such, in 

addition to the production analysis 

presented above, we have completed a 

parallel consumption analysis 

comparing current ethanol consumption 

to future predictions. 

In the 2004 base case, 3.5 billion 

gallons of ethanol 42 and 1.9 billion 

gallons of MTBE 43 were blended into 

gasoline to supply the transportation 

sector with a total of 136 billion gallons 

of gasoline.44 A breakdown of the 2004 

gasoline and oxygenate consumption by 

PADD is found below in Table VI. A.3–

1. 


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Gasoline by Grade, Formulation, PAD District, and 

State). 

45Based on conversation with Dean Simeroth at 

California Air Resources Board (CARB). 

46For the purpose of this analysis, except where 

noted, the term pertains to Federal RFG plus 

California Phase 3 RFG (CaRFG3) and Arizona 

Clean Burning Gasoline (CBG). 

47 2004 MTBE consumption was obtained from 

EIA. The data received was limited to states with 

RFG programs, thus MTBE use was assumed to be 

limited to RFG areas for the purpose of this 

analysis. 

TABLE VI.A.3–1.—2004 U.S. GASOLINE & OXYGENATE CONSUMPTION BY PADD 

PADD Gasoline 

MMgal 

Ethanol MTBEa

MMgal Percent MMgal Percent 

PADD 1 .................................................................................................... 49,193 660 1.34 1,360 2.76 

PADD 2 .................................................................................................... 38,789 1,616 4.17 1 0.00 

PADD 3 .................................................................................................... 20,615 79 0.38 498 2.42 

PADD 4 .................................................................................................... 4,542 83 1.83 0 0.00 

PADD 5 b .................................................................................................. 7,918 209 2.63 19 0.23 

California .................................................................................................. 14,836 853 5.75 0 0.00 

Total .................................................................................................. 135,893 3,500 2.58 1,878 1.38 

a MTBE blended into RFG. 

bPADD 5 excluding California. 

As shown above, nearly half (or about 

45 percent) of the ethanol was 

consumed in PADD 2 gasoline, not 

surprisingly, where the majority of 

ethanol was produced. The next highest 

region of use was the State of California 

which accounted for about 25 percent of 

domestic ethanol consumption. This is 

reasonable because California alone 

accounts for over 10 percent of the 

nation’s total gasoline consumption and 

all the fuel (both Federal RFG and 

California Phase 3 RFG) has been 

assumed to contain ethanol (following 

their recent MTBE ban) at 5.7 volume 

percent.45 The bulk of the remaining 

ethanol was used in reformulated 

gasoline (RFG) and winter oxy-fuel areas 

requiring oxygenated gasoline. Overall, 

62 percent of ethanol was used in RFG, 

33 percent was used in CG, and 5 

percent was used in winter oxy-fuel.46

As shown above in Table VI.A.3–1, 99 

percent of MTBE use occurred in 

PADDs 1 and 3. This reflects the high 

concentration of RFG areas in the 

northeast (PADD 1) and the local 

production of MTBE in the gulf coast 

(PADD 3). PADD 1 receives a large 

portion of its gasoline from PADD 3 

refineries who either produce the fossilfuel based oxygenate or are closely 

affiliated with MTBE-producing 

petrochemical facilities in the area. 

Overall, 100 percent of MTBE in 2004 

was assumed to be used in reformulated 

gasoline.47

In 2004, total ethanol use exceeded 

MTBE use. Ethanol’s lead oxygenate 

role is relatively new, however the trend 

has been a work in progress over the 

past few years. From 2001 to 2004, 

ethanol consumption more than 

doubled (from 1.7 to 3.5 billion gallons), 

while MTBE use (in RFG) was virtually 

cut in half (from 3.7 to 1.9 billion 

gallons). A plot of oxygenate use over 

the past decade is provided below in 

Figure VI.A.3–1. 

The nation’s transition to ethanol is 

linked to states’’ responses to recent 

environmental concerns surrounding 

MTBE groundwater contamination. 

Resulting concerns over drinking water 

quality have prompted several states to 

significantly restrict or completely ban 

MTBE use in gasoline. At the time of 

this analysis, 19 states had adopted 

MTBE bans. A list of the states with 

MTBE bans is provided in DRIA Table 

2.1–4. 


jlentini on PROD1PC65 with PROPOSAL2
55604 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

48Total ethanol use based on EIA Monthly Energy 

Review, June 2006 (Table 10.1: Renewable Energy 

Consumption by Source, Appendix A: Thermal 

Conversion Factors). MTBE use in RFG also 

provided by EIA (file received from EIA 

representative on March 9, 2006). Reported 2004 

MTBE use has been adjusted from 2.0 to 1.9 Bgal 

based on assumption of timely implementation of 

CA, CT, and NY MTBE bans on 1/1/04 (EIA 

reported a slight delay and thus showed small 

amounts of MTBE use in these states in 2004). 

49Energy Act Section 1504, promulgated on May 

8, 2006 at 71 FR 26691. 

50Based on discussions with the refining 

industry. 

51AEO 2006 Table 17 Renewable Energy 

Consumption by Sector and Source shows 0.80 

quadrillion BTUs of energy coming from ethanol in 

2012. A parallel spreadsheet provided to EPA 

shows 2012 total ethanol use as 628.7 thousand 

bbls/day (which works out to be 9.64 billion 

gallons/yr). 

52As a comparison point for cost and emissions 

analyses, a 2012 reference case of 3.9 billion gallons 

of ethanol was also considered. The reference case 

is described in Section II.A.1 (above) and a 

complete derivation is contained in DRIA Section 

2.1.3. 

4. Expected Growth in Ethanol 

Consumption 

As mentioned above, ethanol demand 

is expected to increase well beyond the 

levels contained in the renewable fuels 

standard (RFS) under the Act. With the 

removal of the oxygenate mandate for 

reformulated gasoline (RFG),49 all U.S. 

refiners are expected to eliminate the 

use of MTBE in gasoline as soon as 

possible. In order to accomplish this 

transition quickly (by 2006 or 2007 at 

the latest) while maintaining gasoline 

volume, octane, and mobile source air 

toxics emission performance standards, 

refiners are electing to blend ethanol 

into virtually all of their RFG.50 This has 

caused a dramatic increase in demand 

for ethanol which, in 2006 is being met 

by temporarily shifting large volumes of 

ethanol out of conventional gasoline 

and into RFG areas. By 2012, however, 

ethanol production will have grown to 

accommodate the removal of MTBE 

without the need for such a shift from 

conventional gasoline. More important 

than the removal of MTBE over the long 

term, however, is the impact that the 

dramatic rise in the price of crude oil is 

having on demand for renewable fuels, 

both ethanol and biodiesel. This has 

dramatically improved the economics 

for renewable fuel use, leading to a 

surge in demand that is expected to 

continue. In the Annual Energy Outlook 

(AEO) 2006, EIA forecasted that by 

2012, total ethanol use (corn, cellulosic, 

and imports) would be about 9.6 billion 

gallons 51 and biodiesel use would be 

about 0.3 billion gallons at a crude oil 

price forecast of $47 per barrel. This 

ethanol projection was not based on 

what amount the market would demand 

(which could be higher), but rather on 

the amount that could be produced by 

2012. Others are making similar 

predictions, and as discussed above in 

VI.A.2, production capacity would be 

sufficient. Therefore, in assessing the 

impacts of expanded use of renewable 

fuels, we have chosen to evaluate two 

different future ethanol consumption 

levels, one reflecting the statutory 

required minimum, and one reflecting 

the higher levels projected by EIA. For 

the statutory consumption scenario we 

assumed 7.2 billion gallons of ethanol 

(0.25 of which was assumed to be 

cellulosic) and 0.3 billion gallons of 

biodiesel. For the higher projected 

renewable fuel consumption scenario, 

we assumed 9.6 billion gallons of 

ethanol (0.25 of which is once again 

assumed to be cellulosic) and 0.3 billion 

gallons of biodiesel. Although the actual 

renewable fuel volumes consumed in 

2012 may differ from both the required 

and projected volumes, we believe that 

these two scenarios provide a 

reasonable range for analysis 

purposes.52

In addition to modeling two different 

future 2012 ethanol consumption levels, 

two scenarios were considered based on 

how refineries could potentially 

respond to the recent removal of the 

RFG oxygenate mandate. In both cases, 

the impacted RFG areas did not change 


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Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55605 

53For a list of the Federal RFG areas, refer to 

DRIA Table 2.2–1. 

54Refer to DRIA Table 2.1–2. 

from the 2004 base case.53 In the 

maximum scenario (‘‘max-RFG’’), 

refineries would continue to add 

oxygenate (ethanol) into all batches of 

reformulated gasoline. In this case, 

refineries currently blending MTBE (at 

11 volume percent) would be expected 

to replace it with ethanol (at 10 volume 

percent). In the minimum scenario 

(‘‘min-RFG’’), we predict some refineries 

would respond by using less (or even 

zero) ethanol in RFG based on the 

minimum amount needed to meet 

volume, octane, and/or total toxics 

performance requirements. Applying 

the max-RFG and min-RFG criteria 

resulted in a total of four different 2012 

ethanol consumption control cases: 

1. 7.2 billion gallons of ethanol, 

maximum amount used in RFG areas; 

2. 7.2 billion gallons of ethanol, 

minimum amount used in RFG areas; 

3. 9.6 billion gallons of ethanol, 

maximum amount used in RFG areas; 

and 

4. 9.6 billion gallons of ethanol, 

minimum amount used in RFG areas. 

The seasonal RFG assumptions 

applied in 2012 (in terms of percent 

ethanol marketshare) are summarized 

below in Table VI.A.4–1. The rationale 

behind these selected values are 

explained in DRIA Section 2.1.4.2. 

TABLE VI.A.4–1.—2012 RFG AREA ASSUMPTIONS

RFG areas 

ETOH-blended gasoline (% market share) a

Min-RFG 

scenario 

Max-RFG scenario 

Summer 

(percent) 

Winter 

(percent) 

Summer 

(percent) 

PADD 1 ............................................................................................................................................ 0 100 100 100 

PADD 2 ............................................................................................................................................ 50 100 100 100 

PADD 3 ............................................................................................................................................ 0 25 100 100 

California b ........................................................................................................................................ 25 100 100 100 

Arizona c ........................................................................................................................................... 0 100 100 100 

aPercent marketshare of E10, with the exception of California (E5.7 year-round) and Arizona (E5.7 summer only). 

bPertains to both Federal RFG and California Phase 3. RFG. 

cPertains to Arizona Clean Burning Gasoline (CBG). 

Once we determined how much 

ethanol was likely to be used in RFG 

areas (by PADD), we systematically 

allocated the remaining ethanol into 

conventional gasoline. First it was 

apportioned to winter oxy-fuel areas. In 

the 2004 base case, there were 14 stateimplemented winter oxy-fuel programs 

in 11 states. Of these programs, 9 were 

required in response to non-attainment 

with the CO National Ambient Air 

Quality Standards (NAAQS) and 4 were 

implemented to maintain CO attainment 

status.54 By 2012, 4 areas are expected 

to be redesignated to CO attainment 

status and discontinue oxy-fuel use and 

2 areas are predicted to discontinue 

using oxy-fuel as a maintenance 

strategy. Accordingly, a reduced amount 

of ethanol was allocated to oxy-fuel 

areas in 2012. The remaining ethanol 

was distributed to conventional gasoline 

(CG) in different states based on a 

computed ethanol margin (rack gasoline 

price minus ethanol delivered price 

adjusted by miscellaneous subsidies/ 

penalties). The methodology is 

described in DRIA Section 2.1.4.3. 

The main difference in the four 

resulting ethanol consumption scenarios 

was how far the ethanol penetrated the 

conventional gasoline pool. A summary 

of the forecasted 2012 ethanol 

consumption (by control case, fuel type 

and season) is found in Table VI.A.4–2. 

TABLE VI.A.4–2.—2012 FORECASTED U.S. ETHANOL CONSUMPTION BY SEASON

2012 Control case 

Ethanol consumption (MMgal) 

CG OXYa RFG b Total 

Summer Winter Winter Summer Winter Summer Winter 

7.2 Bgal/Max-RFG ............................................................... 1,269 1,537 72 1,932 2,389 3,201 3,999 

7.2 Bgal/Min-RFG ................................................................ 2,144 2,571 72 244 2,168 2,388 4,812 

9.6 Bgal/Max-RFG ............................................................... 2,356 2,830 73 1,941 2,400 4,297 5,303 

9.6 Bgal/Min-RFG ................................................................ 3,223 3,881 73 246 2,178 3,468 6,132 

aWinter oxy-fuel programs. 

bFederal RFG plus Ca Phase 3 RFG and Arizona CBG. 

As expected, the least amount of 

ethanol was consumed in conventional 

gasoline in the 7.2 billion gallon control 

case when a maximum amount was 

allocated to RFG. Similarly, the most 

ethanol was consumed in CG in the 9.6 

billion gallon control case when a 

minimum amount was allocated to RFG. 

For more information on the four 

resulting 2012 control cases, refer to 

DRIA Section 2.1.4.6. 

B. Overview of Biodiesel Industry and 

Future Production/Consumption 

1. Characterization of U.S. Biodiesel 

Production/Consumption 

Historically, the cost to make 

biodiesel was an inhibiting factor to 

production in the U.S. The cost to 

produce biodiesel was high compared to 

the price of petroleum derived diesel 

fuel, even with consideration of the 

benefits of subsidies and credits 

provided by Federal and state programs. 

Much of the demand occurred as a 

result of mandates from states and local 

municipalities, which required the use 


jlentini on PROD1PC65 with PROPOSAL2
55606 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

55NBB Survey April 28, 2006 ‘‘Commercial 

Biodiesel Production Plants.’’

56From Presentation ‘‘Biodiesel Production 

Capacity,’’ by Leland Tong, National Biodiesel 

Conference and Expo, February 7, 2006. 

57EIA Annual Energy Outlook 2006, Table 1. 

of biodiesel. However, over the past 

couple years biodiesel production has 

been increasing rapidly. The 

combination of higher crude oil prices 

and greater Federal tax subsidies has 

created a favorable economic situation. 

The Biodiesel Blenders Tax Credit 

programs and the Commodity Credit 

Commission Bio-energy Program, both 

subsidize producers and offset 

production costs. The Energy Policy Act 

extended the Biodiesel Blenders Tax 

Credit program to 2008. This credit 

provides about one dollar per gallon in 

the form of a Federal excise tax credit 

to biodiesel blenders from virgin 

vegetable oil feedstocks and 50 cents per 

gallon to biodiesel produced from 

recycled grease and animal fats. The 

program was started in 2004 under the 

American Jobs Act, spurring the 

expansion of biodiesel production and 

demand. Historical estimates and future 

forecasts of biodiesel production in the 

U.S. are presented in Table VI.B.1–1 

below. 

TABLE VI.B.1–1.—ESTIMATED

BIODIESEL PRODUCTION

Year 

Million 

gallons 

per year 

2001 .......................................... 5 

2002 .......................................... 15 

2003 .......................................... 20 

2004 .......................................... 25 

2005 .......................................... 91 

2006 .......................................... 150 

2007 .......................................... 414 

2012 .......................................... 303 

Source: Historical data from 2001–2004 obtained from estimates from John Baize ‘‘ The 

Outlook and Impact of Biodiesel on the Oilseeds Sector’’ USDA Outlook Conference 06. 

Year 2005 data from USDA Bioenergy Program http://www.fsa.usda.gov/daco/bioenergy/ 

2005/FY2005ProductPayments, Year 2006 

data from verbal quote based on projection by 

NBB in June of 2006. Production data for 

years 2007 and higher are from EIA’s AEO 

2006. 

With the increase in biodiesel 

production, there has also been a 

corresponding rapid expansion in 

biodiesel production capacity. 

Presently, there are 65 biodiesel plants 

in operation with an annual production 

capacity of 395 million gallons per 

year.55 The majority of the current 

production capacity was built in 2005, 

and was first available to produce fuel 

in the last quarter of 2005. Though 

capacity has grown, historically the 

biodiesel production capacity has far 

exceeded actual production with only 

10–30 percent of this being utilized to 

make biodiesel, see Table VI.B.1–2.56

TABLE VI.B.1–2.—U.S. PRODUCTION CAPACITY HISTORYa

2001 2002 2003 2004 2005 2006 

Plants ................................................................................................................................... 9 11 16 22 45 53 

Capacity (million gal/yr) ....................................................................................................... 50 54 85 157 290 354 

a Capacity Data based on surveys conducted around the month of September for most years, though the 2006 information is based on survey 

conducted in January 2006. 

2. Expected Growth in U.S. Biodiesel 

Production/Consumption 

In addition to the 53 biodiesel plants 

already in production, as of early 2006, 

there were an additional 50 plants and 

8 plant expansions in the construction 

phase, which when completed would 

increase total biodiesel production 

capacity to over one billion gallons per 

year. Most of these plants should be 

completed by early 2007. There were 

also 36 more plants in various stages of 

the preconstruction phase (i.e. raising 

equity, permitting, conceptual design, 

buying equipment) with a capacity of 

755 million gallons/year. As shown in 

Table VI.B.2–1, if all of this capacity 

came to fruition, U.S. biodiesel capacity 

would exceed 1.8 billion gallons. 

TABLE VI.B.2–1.—PROJECTED BIODIESEL PRODUCTION CAPACITY

Existing plants Construction 

phase 

Pre-construction 

phase 

Number of plants ....................................................................................................................... 53 58 36 

Total Plant Capacity, MM Gallon/year ....................................................................................... 354 714 754 .7 

For cost and emission analysis 

purposes, three biodiesel usage cases 

were considered: A 2004 base case, a 

2012 reference case, and a 2012 control 

case. The 2004 base case was formed 

based on historical biodiesel usage (25 

million gallons as summarized in Table 

VI.B.1.1). The reference case was 

computed by taking the 2004 base case 

and growing it out to 2012 in a manner 

consistent with the growth of gasoline.57

The resulting 2012 reference case 

consisted of approximately 28 million 

gallons of biodiesel. Finally, for the 

2012 control case, forecasted biodiesel 

use was assumed to be 300 million 

gallons based on EIA’s AEO 2006 report 

(rounded value from Table VI.B.1.1). 

Unlike forecasted ethanol use, biodiesel 

use was assumed to be constant at 300 

million gallons under both the statutory 

and higher projected renewable fuel 

consumption scenarios described in 

VI.A.4. EIA’s projection is based on the 

assumption that the blender’s tax credit 

is not renewed beyond 2008. If the tax 

credit is renewed, the projection for 

biodiesel demand would increase. 

C. Feasibility of the RFS Program 

Volume Obligations 

This section examines whether there 

are any feasibility issues associated with 

the meeting the minimum renewable 

fuel requirements of the Energy Act. 

Issues are examined with respect to 


jlentini on PROD1PC65 with PROPOSAL2
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55607 

58 ‘‘Infrastructure Requirements for an Expanded 

Fuel Ethanol Industry,’’ Downstream Alternatives 

Inc., January 15, 2002. 

renewable production capacity, 

cellulosic ethanol production capacity, 

and distribution system capability. Land 

resource requirements are discussed in 

Chapter 7 of the RIA. 

1. Production Capacity of Ethanol and 

Biodiesel 

As shown in sections VI.A. and VI.B., 

increases in renewable fuel production 

capacity are already proceeding at a 

pace significantly faster than required to 

meet the 2012 mandate in the Act of 7.5 

billion gallons. The combination of 

ethanol and biodiesel plants in 

existence and planned or under 

construction is expected to provide a 

total renewable fuel production capacity 

of over 9.6 billion gallons by the end of 

2012. Production capacity is expected to 

continue to increase in response to 

strong demand. We estimate that this 

will require a maximum of 2,100 

construction workers and 90 engineers 

on a monthly basis through 2012. 

2. Production Capacity of Cellulosic 

Ethanol 

Beginning in 2013, a minimum of 250 

million gallons per year of cellulosic 

ethanol must be used in gasoline. The 

Act’s definition of cellulosic, however, 

includes corn based ethanol as long as 

greater than 90% of the process energy 

was derived from animal wastes or other 

waste materials. As discussed in section 

VI.A. above, we believe that of the 

ethanol plants currently in existence, 

under construction, or in the final stages 

of planning there is likely to be more 

than 250 million gallons per year of 

ethanol produced from plants which 

meet these alternative definitions for 

cellulosic ethanol. 

However, this is not to say that 

ethanol produced from cellulose will 

not be part of the renewable supply by 

2012. As far as we know there is 

currently only one demonstration-level 

cellulosic ethanol plant in operation in 

North America; it produces 1 million 

gallons of ethanol per year (Iogen a 

privately held company, based in 

Ottawa, Ontario, Canada). However, the 

technology used to produce ethanol 

from cellulosic feedstocks continues to 

improve. With the grants made available 

through the Energy Act, we expect 

several cellulosic process plants will be 

constructed and an ever increasing 

effort will naturally be made to find 

better, more efficient ways to produce 

cellulosic ethanol. 

To produce ethanol from cellulosic 

feedstocks, pretreatment is necessary to 

hydrolyze cellulosic and hemicellulosic 

polymers and break down the lignin 

sheath. In so doing, the structure of the 

cellulosic feedstock is opened to allow 

efficient and effective enzyme 

hydrolysis of the cellulose/ 

hemicellulose to glucose and xylose. 

The central problem is that the a-linked 

saccharide polymers in the cellulose/ 

hemicellulose structure prevent the 

microbial fermentation reaction. By 

comparison, when corn kernels are used 

as feedstock, fermentation of the starch 

produced from the corn kernels which 

have a-linked saccharide polymers takes 

place much more readily. An acid 

hydrolysis process was developed to 

pretreat cellulosic feedstocks (through 

hydrolysis which breaks up the b-links), 

but it continues to be prohibitively 

expensive for producing ethanol. 

Some technologies that are being 

developed may solve some of the 

problems associated with production of 

ethanol from cellulosic sources. 

Specifically, one problem with 

cellulosic feedstocks is that the 

hydrolysis reactions produce both 

glucose, a six-carbon sugar, and xylose, 

a five-carbon sugar (pentose sugar, 

C5H10O5; sometimes called ‘‘wood 

sugar’’). Early conversion technology 

required different microbes to ferment 

each sugar. Recent research has 

developed better cellulose hydrolysis 

enzymes and ethanol-fermenting 

organisms. Now, glucose and xylose can 

be co-fermented—hence, the presentday terminology: Weak-acid enzymatic 

hydrolysis and co-fermentation. In 

addition, several research groups, using 

recently developed genome modifying 

technology, have been able to produce 

a variety of new or modified enzymes 

and microbes that show promise for use 

in a process known as weak-acid, 

enzymatic-prehydrolysis. 

Cellulosic biomass can come from a 

variety of sources. Because the 

conversion of cellulosic biomass to 

ethanol has not yet been commercially 

demonstrated, we cannot say at this 

time which feedstocks are superior to 

others. In particular, there is only one 

cellulosic ethanol plant in North 

America (Iogen, Ottawa, Ontario, 

Canada). To the best of our knowledge, 

the technology that Iogen employs is not 

yet fully developed or optimized. 

Generally, the industry seems to be 

moving toward a process that uses 

dilute acid enzymatic prehydrolysis 

with simultaneous saccharification 

(enzymatic) and co-fermentation. 

3. Renewable Fuel Distribution System 

Capability 

Ethanol and biodiesel blended fuels 

are not shipped by petroleum product 

pipeline due to operational issues and 

additional cost factors. Hence, a 

separate distribution system is needed 

for ethanol and biodiesel up to the point 

where they are blended into petroleumbased fuel as it is loaded into tank 

trucks for delivery to retail and fleet 

operators. In cases where ethanol and 

biodiesel are produced within 200 miles 

of a terminal, trucking is often the 

preferred means of distribution. For 

longer shipping distances, the preferred 

method of bringing renewable fuels to 

terminals is by rail and barge. 

Modifications to the rail, barge, tank 

truck, and terminal distribution systems 

will be needed to support the transport 

of the anticipated increased volumes of 

renewable fuels. These modifications 

include the addition of terminal 

blending systems for ethanol and 

biodiesel, additional storage tanks at 

terminals, additional rail delivery 

systems at terminals for ethanol and 

biodiesel, and additional rail cars, 

barges, and tank trucks to distribute 

ethanol and biodiesel to terminals. 

Terminal storage tanks for 100 percent 

biodiesel will also need to be heated 

during cold months to prevent gelling. 

In the past the refining industry has 

raised concerns regarding whether the 

distribution infrastructure can expand 

rapidly enough to accommodate the 

increased demand for ethanol. The most 

comprehensive study of the 

infrastructure requirements for an 

expanded fuel ethanol industry was 

conducted for the Department of Energy 

(DOE) in 2002.58 The conclusions 

reached in that study indicate that the 

changes needed to handle the 

anticipated increased volume of ethanol 

by 2012 will not represent a major 

obstacle to industry. While some 

changes have taken place since this 

report was issued, including an 

increased reliance on rail over marine 

transport, we continue to believe that 

the rail and marine transportation 

industries can manage the increased 

growth in demand in an orderly fashion. 

This belief is supported by the 

demonstrated ability for the industry to 

handle the rapid increases and 

redistribution of ethanol use across the 

country over the last several years as 

MTBE was removed. The necessary 

facility changes at terminals and at retail 

stations to dispense ethanol containing 

fuels have been occurring at a record 

pace. Given that future growth is 

expected to progress at a steadier pace 

and with greater advance warning in 

response to economic drivers, we 

anticipate that the distribution system 

will be able to respond appropriately. A 

discussion of the costs associated 

making the changes discussed above is 


jlentini on PROD1PC65 with PROPOSAL2
55608 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

59 Kwaitkowski, J.R., McAloon, A., Taylor, F., 

Johnston, D.B., Industrial Crops and Products 23 

(2006) 288–296. 

60Shapouri, H., Gallagher, P., USDA’s 2002 

Ethanol Cost-of-Production Survey (published July 

2005). 

contained in section VII.B. of this 

preamble. 

VII. Impacts on Cost of Renewable 

Fuels and Gasoline 

This section examines the impact on 

fuel costs resulting from the growth in 

renewable fuel use between a base year 

of 2004 and 2012. We note that based 

on analyses conducted by the Energy 

Information Administration (EIA), 

renewable fuels will be used in gasoline 

and diesel fuel in excess and 

independent of the RFS requirements. 

As such, the changes in the use of 

renewable fuels and their related cost 

impacts are not directly attributable to 

the RFS rule. Rather, our analysis 

assesses the broader fuels impacts of the 

growth in renewable fuel use in the 

context of corresponding changes to the 

makeup of gasoline. These fuel impacts 

include the elimination of the 

reformulated gasoline (RFG) oxygen 

standard which has resulted in the 

refiners ceasing to use the gasoline 

blendstock methyl tertiary butyl ether 

(MTBE) and replacing it with ethanol. 

We also expect that by ending the use 

of MTBE that the former MTBE 

feedstock, isobutylene, will be reused to 

produce increased volumes of alkylate, 

a moderate to high octane gasoline 

blendstock. Thus, in this analysis, we 

are assessing the impact on the cost of 

gasoline and diesel fuel of increased use 

of renewable fuels, the cost savings 

resulting from the phase out of MTBE 

and the increased cost due to the 

production of alkylate. 

As discussed in section II., we chose 

to analyze a range of renewable fuels 

use. In the case of ethanol’s use in 

gasoline, the lower end of this range is 

based on the minimum renewable fuel 

volume requirements in the Act, and the 

higher end is based on AEO 2006. At 

both ends of this range, we assume that 

biodiesel consumption will be the level 

estimated in AEO 2006. We analyzed 

the projected fuel consumption scenario 

and associated program costs in 2012, 

the year that the RFS is fully phased-in. 

The volumes of renewable fuels 

consumed in 2012 at the two ends of the 

range are summarized in Table VII–1. 

TABLE VII–1.—RENEWABLE FUELS VOLUMES USED IN COST ANALYSIS

Renewable fuels 

consumption in 2012 

(billion gallons) 

Low High 

Corn Ethanol .......................................................................................................................................................... 6 .95 9.35 

Cellulosic Ethanol .................................................................................................................................................. 0 .25 0.25 

Biodiesel ................................................................................................................................................................ 0 .30 0.30 

Total Biofuel Consumption ............................................................................................................................. 7 .5 9.90 

We have estimated an average corn 

ethanol production cost of $1.20 per 

gallon in 2012 (2004 dollars) in the case 

of 7.5 billion gallons per year (bill gal/ 

yr) and $1.26 per gallon in the case of 

9.9 bill gal/yr. For cellulosic ethanol, we 

estimate it will cost approximately 

$1.65 in 2012 (2004 dollars) to produce 

a gallon of ethanol using corn stover as 

a cellulosic feedstock. In this analysis, 

however, we assume that the cellulosic 

requirement will be met by corn-based 

ethanol produced by energy sourced 

from biomass (animal and other waste 

materials as discussed in Section III.B of 

this preamble) and costing the same as 

corn based ethanol produced by 

conventional means. 

We estimated production costs for 

soy-derived biodiesel of $2.06 per gallon 

in 2004 and $1.89 per gal in 2012. For 

yellow grease derived biodiesel, we 

estimate an average production cost of 

$1.19 per gallon in 2004 and $1.10 in 

2012. 

The impacts on overall gasoline costs 

with and without fuel consumption 

subsidies resulting from the increased 

use of ethanol and the corresponding 

changes to the other aspects of gasoline 

were estimated for both of these cases. 

The 7.5 bill gal/yr case would result in 

increased total costs which range from 

0.33 cents to 0.41 cents per gallon 

depending on assumptions with respect 

to ethanol use in RFG and butane 

control constraints. The 9.9 bill gal/yr 

case would result in increased total 

costs which range from 0.93 to 1.05 

cents per gallon. The actual cost at the 

fuel pump, however, will be decreased 

due the effect of State and Federal tax 

subsidies for ethanol. Taking this into 

consideration results in ‘‘at the pump’’

decreased costs (cost savings) ranging 

from 0.82 to 0.89 cents per gallon for the 

7.5 bill gal/yr case and ‘‘at the pump’’

decreased costs ranging from 0.98 to 

1.08 cents per gallon for the 9.9 bill gal/ 

yr case. We ask for comment on these 

derived costs as well as on the analysis 

methodology used to derive these costs, 

and refer the reader to Section 7 of the 

DRIA which contains much more detail 

on the cost analysis used to develop 

these costs. 

A. Renewable Fuel Production and 

Blending Costs 

1. Ethanol Production Costs 

a. Corn Ethanol. A significant amount 

of work has been done in the last decade 

on surveying and modeling the costs 

involved in producing ethanol from 

corn, 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 

a model developed by USDA in the 

1990s that has been continuously 

updated by USDA. The most current 

version was documented in a peerreviewed journal paper on cost 

modeling of the dry-grind corn ethanol 

process,59 and it produces results that 

compare well with cost information 

found in surveys of existing plants.60

We made some minor modifications to 

the USDA model to allow scaling of the 

plant size, to allow consideration of 

plant energy sources other than natural 

gas, and to adjust for energy prices in 

2012, the year of our analysis. 

The cost of ethanol production is 

most sensitive to the prices of corn and 

the primary co-product, DDGS. Utilities, 

capital, and labor expenses also have an 

impact, although to a lesser extent. Corn 

feedstock minus DDGS sale credits 

represents about 50% of the final pergallon cost, while utilities, capital and 

labor comprise about 20%, 10%, and 

5%, respectively. For this work, we 

used corn price projections from USDA 

of $2.23 per bushel in 2012 for the 7.2 

bill gal/yr case, and an adjusted value of 

$2.31 per bushel for the 9.6 bill gal/yr 


jlentini on PROD1PC65 with PROPOSAL2
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55609 

61USDA Agricultural Baseline Projections to 

2015, Report OCE–2006–1. 

62EIA NEMS model for ethanol production, 

updated for AEO 2006. 

63Food and Agricultural Policy Research Institute 

(FAPRI) study entitled ‘‘Implications of Increased 

Ethanol Production for U.S. Agriculture’’, FAPRI–

UMC Report #10–05. 

64Food and Agricultural Policy Research Institute 

(FAPRI) U.S. and World Agricultural Outlook, 

January 2006, FAPRI Staff Report 06–FSR 1. 

65Historical data at http://tonto.eia.doe.gov/dnav/ 

pet/pet_pri_allmg_d_nus_PTA_cpgal_m.htm 

(gasoline), http://tonto.eia.doe.gov/dnav/ng/ 

ng_pri_sum_dcu_nus_m.htm (natural gas), http:// 

www.eia.doe.gov/cneaf/electricity/page/ 

sales_revenue.xls (electricity), http:// 

www.eia.doe.gov/cneaf/coal/page/acr/table28.html 

(coal); EIA Annual Energy Outlook 2006, Tables 8, 

12, 13, 15; EIA Web site. 

66Whims, J., Sparks Companies, Inc. and Kansas 

State University, ‘‘Corn Based Ethanol Costs and 

Margins, Attachment 1’’ (Published May 2002). 

67Piel, W.J., Tier & Associates, Inc., March 9, 

2006 report on costs of ethanol production and 

alternatives. 

68Energy Policy Act of 2005, Section 1501 

amending Clean Air Act Section 211(o)(1)(A). 

69Lignocellulosic Biomass to Ethanol Process 

Design and Economics Utilizing Co-Current Dilute 

Acid Prehydrolysis and Enzymatic Hydrolysis 

Current and Futuristic Scenarios, Robert Wooley, 

Mark Ruth, John Sheehan, and Kelly Ibsen, 

Biotechnology Center for Fuels and Chemicals 

Henry Majdeski and Adrian Galvez, Delta-T 

Corporation; National Renewable Energy 

Laboratory, Golden, CO, July 1999, NREL/TP–580–

26157. 

70 Determining the Cost of Producing Ethanol 

from Corn Starch and Lignocellulosic Feedstocks; A 

Joint Study Sponsored by: USDA and USDOE, 

October 2000, NREL/TP–580–28893, Andrew 

McAloon, Frank Taylor, Winnie Yee, USDA, 

Eastern Regional Research Center Agricultural 

Research Service; Kelly Ibsen, Robert Wooley, 

National Renewable Energy Laboratory, 

Biotechnology Center for Fuels and Chemicals, 

1617 Cole Boulevard, Golden, CO 80401–3393; 

NREL is a USDOE Operated by Midwest Research 

Institute Battelle Bechtel; Contract No. DE–AC36–

99–GO10337. 

case.61 The adjustment at the higher 

volume case was taken from work done 

by FAPRIand EIA. 62 63 Prices used for 

DDGS were $65 per ton in the 7.2 bill 

gal/yr case and $55 per ton in the 9.6 

case, based on work by FAPRI and 

EIA.64 Energy prices were derived from 

historical data and projected to 2012 

using EIA’s AEO 2006.65 While we 

believe the use of USDA and FAPRI 

estimates for corn and DDGS prices is 

reasonable, additional modeling work is 

being done for the final rulemaking 

using the Forestry and Agricultural 

Sector Optimization Model described 

further in Chapter 8 of the RIA. 

The estimated average corn ethanol 

production cost of $1.20 per gallon in 

2012 (2004 dollars) in the case of 7.2 bill 

gal/yr and $1.26 per gallon in the case 

of 9.6 bill gal/yr 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. It does 

not account for any subsidies on 

production or sale of ethanol. This cost 

is independent of the market price of 

ethanol, which has been related closely 

to the wholesale price of gasoline for the 

past decade.66 67

Under the Energy Act, starch-based 

ethanol can be counted as cellulosic if 

at least 90% of the process energy is 

derived from renewable feedstocks, 

which include plant cellulose, 

municipal solid waste, and manure 

biogas.68 It is expected that the 250 

million gallons per year of cellulosic 

ethanol production required by 2013 

will be made using this provision. 

While we have been unable to develop 

a detailed production cost estimate for 

corn ethanol meeting cellulosic criteria, 

we assume that the costs will not be 

significantly different from 

conventionally produced corn ethanol. 

We believe this is reasonable because 

these processes will simply be corn 

ethanol plants with additional fuel 

handling mechanisms that allow them 

to combust waste materials for process 

energy instead of natural gas. We expect 

them to be in locations where the very 

low or zero cost of the waste material or 

biogas itself will likely offset the costs 

of hauling it and/or the additional 

capital for processing and firing it, 

making them cost-competitive with 

conventional corn ethanol plants. 

Furthermore, because the quantity of 

ethanol produced using these processes 

is still expected to be a relatively small 

fraction of the total ethanol demand, the 

sensitivity of the overall analysis to this 

assumption is also very small. Based on 

these factors, we have assigned starch 

ethanol made using this cellulosic 

criteria the same cost as ethanol 

produced from corn using conventional 

means. 

b. Cellulosic Ethanol. In 1999, the 

National Renewable Energy Laboratory 

(NREL) published a report outlining its 

work with the USDA to design a 

computer model of a plant to produce 

ethanol from hardwood chips.69

Although the model was originally 

prepared for hardwood chips, it was 

meant to serve as a modifiable-platform 

for ongoing research using cellulosic 

biomass as feedstock to produce 

ethanol. Their long-term plan was that 

various indices, costs, technologies, and 

other factors would be regularly 

updated. 

NREL and USDA used a modified 

version of the model to compare the cost 

of using corn-grain with the cost of 

using corn stover to produce ethanol. 

We used the corn stover model from the 

second NREL/USDA study for the 

analysis for this proposed rule. Because 

there were no operating plants that 

could potentially provide real world 

process design, construction, and 

operating data for processing cellulosic 

ethanol, NREL had considered modeling 

the plant based on assumptions 

associated with a first-of-a-kind or 

pioneer plant. The literature indicates 

that such models often underestimate 

actual costs since the high performance 

assumed for pioneer process plants is 

generally unrealistic. 

Instead, the NREL researchers 

assumed that the corn stover plant was 

an Nth generation plant, e.g., not a 

pioneer plant or first-or-its kind, built 

after the industry had been sufficiently 

established to provide verified costs. 

The corn stover plant was normalized to 

the corn kernel plant, e.g., placed on a 

similar basis.70 It is also reasonable to 

expect that the cost of cellulosic ethanol 

would be higher than corn ethanol 

because of the complexity of the 

cellulose conversion process. Recently, 

process improvements and 

advancements in corn production have 

considerably reduced the cost of 

producing corn ethanol. We also believe 

it is realistic to assume that cellulosederived ethanol process improvements 

will be made and that one can likewise 

reasonably expect that as the industry 

matures, the cost of producing ethanol 

from cellulose will also decrease. 

We calculated fixed and variable 

operating costs using percentages of 

direct labor and total installed capital 

costs. Following this methodology, we 

estimate that producing a gallon of 

ethanol using corn stover as a cellulosic 

feedstock would cost $1.65 in 2012 

(2004 dollars). 

c. Ethanol’s Blending Cost. Ethanol 

has a high octane value of 115 (R+M)/ 

2 which contributes to its value as a 

gasoline blendstock. As the volume of 

ethanol blended into gasoline increases 

from 2004 to 2012, refiners will account 

for the octane provided by ethanol when 

they plan their gasoline production. 

This additional octane would allow 

them to back off of their octane 

production from their other gasoline 

producing units resulting in a cost 

savings to the refinery. For this cost 

analysis, the cost savings is expressed as 

a cost credit to ethanol added to the 

production cost for producing ethanol. 

We obtained gasoline blending costs 

on a PADD basis for octane from a 

consultant who conducted a cost 

analysis for a renewable fuels program 

using an LP refinery cost model. LP 

refinery models value the cost of octane 

based on the octane producing capacity 

for the refinery’s existing units, by 


jlentini on PROD1PC65 with PROPOSAL2
55610 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

71Based on EIA’s AEO 2006, the total volume of 

highway and off-road diesel fuel consumed in 2012 

was estimated at 58.9 billion gallons. 

added capital and operating costs for 

new octane producing capacity, and 

based on purchased gasoline 

blendstocks. The value of octane is 

expressed as a per-gallon cost per octane 

value, and ranges from 0.38 cents per 

octane-gallon in PADD 2 where lots of 

ethanol is expected to be used, to 1.43 

cents per octane-gallon in California. 

Octane is more costly in California 

because the Phase 3 RFG standards 

restriction aromatics content which also 

reduces the use of a gasoline blendstock 

named reformate—a relatively cheap 

source of octane. Also, California’s 

Phase 3 RFG distillation restrictions 

tend to limit the volume of eight carbon 

alkylate, another lower cost and 

moderately high octane blendstock. 

Another blending factor for ethanol is 

its energy content. Ethanol contains a 

lower heat content per gallon than 

gasoline. Since refiners blend up their 

gasoline based on volume, they do not 

consider the energy content of its 

gasoline, only its price. Instead, the 

consumer pays for a gasoline’s energy 

density based on the distance that the 

consumer can achieve on a gallon of 

gasoline. Since we try to capture all the 

costs of using ethanol, we consider this 

effect. Ethanol contains 76,000 British 

Thermal Units (BTU) per gallon which 

is significantly lower than gasoline, 

which contains an average of 115,000 

BTUs per gallon. This lower energy 

density is accounted for below in the 

discussion of the gasoline costs. 

2. Biodiesel Production Costs 

We based our cost to produce 

biodiesel fuel on a range estimated from 

the use of USDA’s and NREL’s biodiesel 

computer models. Both of these models 

represent the continuous 

transesterification process for 

converting vegetable soy oil to esters, 

along with the ester finishing processes 

and glycerol recovery. The models 

estimate biodiesel production costs 

using prices for soy oil, methanol, 

chemicals and the byproduct glycerol. 

The models estimate the capital, fixed 

and operating costs associated with the 

production of soy based biodiesel fuel, 

considering utility, labor, land and any 

other process and operating 

requirements. 

Each model is based on a medium 

sized biodiesel plant that was designed 

to process raw degummed virgin soy oil 

as the feedstock, yielding 10 million 

gallons per year of biodiesel fuel. USDA 

estimated the equipment needs and 

operating requirements for their 

biodiesel plant through the use of 

process simulation software. This 

software determines the biodiesel 

process requirements based on the use 

of established engineering relationships, 

process operating conditions and 

reagent needs. To substantiate the 

validity and accuracy of their model, 

USDA solicited feedback from major 

biodiesel producers. Based on 

responses, they then made adjustments 

to their model. The NREL model is also 

based on process simulation software, 

though the results are adjusted to reflect 

NREL’s modeling methods. 

The production costs are based on an 

average biodiesel plant located in the 

Midwest using soy oil and methanol, 

which are catalyzed into esters and 

glycerol by use of sodium hydroxide. 

Because local feedstock costs, 

distribution costs, and biodiesel plant 

type introduce some variability into cost 

estimates, we believe that using an 

average plant to estimate production 

costs provides a reasonable approach. 

Therefore, we simplified our analysis 

and used costs based on an average 

plant and average feedstock prices since 

the total biodiesel volumes forecasted 

are not large and represent a small 

fraction of the total projected renewable 

volumes. The production costs are 

based on a plant that makes 10 million 

gallons per year of biodiesel fuel. 

The model is further modified to use 

input prices for the feedstocks, 

byproducts and energy prices to reflect 

the effects of the fuels provisions in the 

Energy Act. Based on the USDA model, 

for soy oil-derived biodiesel we estimate 

a production cost of $2.06 per gallon in 

2004 and $1.89 per gal in 2012 (in 2004 

dollars) For yellow grease derived 

biodiesel, USDA’s model estimates an 

average production cost of $1.19 per 

gallon in 2004 and $1.10 in 2012 (in 

2004 dollars). In order to capture a range 

of production costs, we compared these 

cost projections to those derived from 

the NREL biodiesel model. With the 

NREL model, we estimate biodiesel 

production cost of $2.11 per gallon for 

soy oil feedstocks and $1.28 per gallon 

for yellow grease in 2012, which are 

slightly higher than the USDA results. 

With the current Biodiesel Blender 

Tax Credit Program, producers using 

virgin vegetable oil stocks receive a one 

dollar per gallon tax subsidy while 

yellow grease producers receive 50 

cents per gallon, reducing the net 

production cost to a range of 89 to 111 

cents per gallon for soy derived 

biodiesel and 60 to 78 cents per gallon 

for yellow grease biodiesel in 2012. This 

compares favorably to the projected 

wholesale diesel fuel prices of 138 cents 

per gallon in 2012, signifying that the 

economics for biodiesel are positive 

under the effects of the blender credit 

program, though, the tax credit program 

expires in 2008 if not extended. 

Congress may later elect to extend the 

blender credit program, though, 

following the precedence used for 

extending the ethanol blending 

subsidies. Additionally, the Small 

Biodiesel Blenders Tax credit program 

and state tax and credit programs offer 

some additional subsidies and credits, 

though the benefits are modest in 

comparison to the Blender’s Tax credit. 

3. Diesel Fuel Costs 

Biodiesel fuel is blended into 

highway and nonroad diesel fuel, which 

increases the volume and therefore the 

supply of diesel fuel and thereby 

reduces the demand for refineryproduced diesel fuel. In this section, we 

estimate the overall cost impact, 

considering how much refinery-based 

diesel fuel is displaced by the forecasted 

production volume of biodiesel fuel. 

The cost impacts are evaluated 

considering the production cost of 

biodiesel with and without the subsidy 

from the Biodiesel Blenders Tax credit 

program. Additionally, the diesel cost 

impacts are quantified under two 

scenarios, with refinery diesel prices as 

forecasted by EIA’s AEO 2006 with 

crude at $47 a barrel and with refinery 

diesel prices based on $70 per barrel 

crude oil. 

We estimate the net effect that 

biodiesel production has on overall cost 

for diesel fuel in year 2012 using total 

production costs for biodiesel and diesel 

fuel. The costs are evaluated based on 

how much refinery-based diesel fuel is 

displaced by the biodiesel volumes as 

forecasted by EIA, accounting for energy 

density differences between the fuels. 

The cost impact is estimated from a 

2004 year basis, by multiplying the 

production costs of each fuel by the 

respective changes in volumes for 

biodiesel and estimated displaced diesel 

fuel. We further assume that all of the 

forecasted biodiesel volume is used as 

transport fuel, neglecting minor uses in 

the heating oil market. 

For the AEO scenario, the net effect of 

biodiesel production on diesel fuel 

costs, including the biodiesel blenders’

subsidy, is a reduction in the cost of 

transport diesel fuel costs by $90 

million per year, which equates to a 

reduction in fuel cost of about 0.15 

c/gal.71 Without the subsidy, the 

transport diesel fuel costs are increased 

by $118 million per year, or an increase 

of 0.20 c/gal for transport diesel fuel. 

With crude at $70 per barrel, including 

the biodiesel blenders subsidy, results 

in a cost reduction of $184 million per 


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72 Infrastructure Requirements for an Expanded 

Fuel Ethanol Industry, Downstream Alternatives 

Inc., January 15, 2002. 

73See Chapter 7.3 of the Draft Regulatory Impact 

Analysis associated with today’s rule for additional 

discussion of how the results of the DAI study were 

adjusted to reflect current conditions in estimating 

the ethanol distribution infrastructure capital costs 

under today’s rule. 

74For both the 7.2 bill gal/yr and 9.6 bill gal/yr 

cases, the baseline from which the DOE study cases 

were projected was adjusted to reflect a 3.9 bill gal/ 

yr 2012 baseline. 

75Petroleum Market Model of the National Energy 

Modeling System, Part 2, March 2006, DOE/EIA–

059 (2006), http://tonto.eia.doe.gov/FTPROOT/ 

modeldoc/m059(2006)-2.pdf. 

76 2004 baseline of 25 million gallons grown with 

diesel demand to 2012. 

77See section VI.C. in today’s preamble regarding 

the special handling requirements for biodiesel 

under cold conditions. 

year, or a reduction of 0.31 c/gal for the 

total transport diesel pool. Without the 

subsidy, transport diesel costs are 

increased by $25 million per year, or 

0.04 c/gal. 

B. Distribution Costs 

1. Ethanol Distribution Costs 

There are two components to the costs 

associated with distributing the volumes 

of ethanol necessary to meet the 

requirements of the Renewable Fuels 

Standard (RFS): (1) the capital cost of 

making the necessary upgrades to the 

fuel distribution infrastructure system, 

and (2) the ongoing additional freight 

costs associated with shipping ethanol 

to terminals. The most comprehensive 

study of the infrastructure requirements 

for an expanded fuel ethanol industry 

was conducted for the Department of 

Energy (DOE) in 2002.72 That study 

provided the foundation our estimates 

of the capital costs associated with 

upgrading the distribution infrastructure 

system as well as the freight costs to 

handle the increased volume of ethanol 

needed to meet the requirements of the 

RFS in 2012. Distribution costs are 

evaluated here for the case where the 

minimum volume of ethanol is used to 

meet the requirements of the RFS (7.2 

bill gal/yr) and for the projected case 

where the volume of ethanol used is 9.6 

bill gal/yr. The 2012 reference case 

against which we are estimating the cost 

of distributing the additional volume of 

ethanol needed to meet the 

requirements of the RFS is 3.9 billion 

gallons. 

a. Capital Costs To Upgrade 

Distribution System For Increased 

Ethanol Volume. The 2002 DOE study 

examined two cases regarding the use of 

renewable fuels for estimating the 

capital costs for distributing additional 

ethanol. The first assumed that 5.1 bill 

gal/yr of ethanol would be used in 2010, 

and the second assumed that 10 bill gal/ 

yr of ethanol would be used in the 2015 

timetable. We interpolated between 

these two cases to provide an estimate 

of the capital costs to support the use of 

7.2 bill gal/yr of ethanol in 2012.73 The 

10 bill gal/yr case examined in the DOE 

study was used to represent the 

projected case examined in today’s rule 

of 9.6 bill gal/yr of ethanol.74 Table 

VII.B.1.a–1 contains our estimates of the 

infrastructure changes and associated 

capital costs for the two ethanol use 

scenarios examined in today’s rule. 

Amortized over 15 years, the total 

capital costs equate to approximately 

one cent per gallon. We performed a 

sensitivity analysis where we increased 

reliance on rail use at the expense of 

barge use in transporting ethanol. The 

costs were relatively insensitive, 

increasing to just 1.1 cents per gallon. 

TABLE VII.B.1.A–1.—ESTIMATED ETHANOL DISTRIBUTION INFRASTRUCTURE CAPITAL COSTS ($M) RELATIVE TO A 3.9 

BILLION GALLON PER YEAR REFERENCE CASE

7.2 billion 

gallons 

(per year) 

9.6 billion 

gallons 

(per year) 

Fixed Facilities: 

Retail ................................................................................................................................................................. 24 44 

Terminals .......................................................................................................................................................... 142 246 

Mobile Facilities: 

Transport Trucks .............................................................................................................................................. 38 50 

Barges .............................................................................................................................................................. 30 52 

Rail Cars ........................................................................................................................................................... 104 161 

Total Capital Costs .................................................................................................................................... 317 542 

b. Ethanol Freight Costs. The DOE 

study contains ethanol freight costs for 

each of the 5 PADDs. The Energy 

Information Administration translated 

these cost estimates to a census division 

basis.75 We took the EIA projections and 

translated them into State-by-State 

ethanol freight costs. In conducting this 

translation, we accounted for increases 

in the cost in transportation fuels used 

to ship ethanol by truck, rail, and barge. 

We estimate that the freight cost to 

transport ethanol to terminals would 

range from 5 cents per gallon in the 

Midwest, to 18 cents per gallon to the 

West Coast, which averages 9.2 cents 

per gallon of ethanol on a national basis. 

We estimate the total cost for 

producing and distributing ethanol to be 

between $1.30 and $1.36 per gallon of 

ethanol, on a nationwide average basis. 

This estimate includes both the capital 

costs to upgrade the distribution system 

and freight costs. 

2. Biodiesel Distribution Costs 

The volume of biodiesel used by 2012 

under the RFS is estimated at 300 

million gallons per year. The 2012 

baseline case against which we are 

estimating the cost of distributing the 

additional volume of biodiesel is 28 

million gallons.76

For the purposes of this analysis, we 

are assuming that to ensure consistent 

operations under cold conditions all 

terminals will install heated biodiesel 

storage tanks and biodiesel will be 

transported to terminals in insulated 

tank trucks and rail cars in the cold 

seasons.77 Due to the developing nature 

of the biodiesel industry, specific 

information on biodiesel freight costs is 

lacking. The need to protect biodiesel 

from gelling during the winter may 

marginally increase freight costs over 

those for ethanol. Counterbalancing this 

is the likelihood that biodiesel shipping 

distances may be somewhat shorter due 

to the more geographically dispersed 

nature of biodiesel production facilities. 

In any event, the potential difference 

between biodiesel and ethanol freight 

costs is likely to be small and the cost 

of distributing biodiesel does not 

appreciably affect the results of our 

analysis. Therefore, we believe that 


jlentini on PROD1PC65 with PROPOSAL2
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estimated freight costs for ethanol of 9.2 

cents per gallon adequately reflects the 

freight costs for biodiesel for this 

analysis. 

The capital costs associated with 

distribution of biodiesel will be 

somewhat higher per gallon than those 

associated with the distribution of 

ethanol due to the need for storage 

tanks, barges, tanker trucks and rail cars 

to be insulated and in many cases 

heated. We estimate that to handle the 

increased biodiesel volume will require 

a total capital cost investment of 

$49,813,000, which equates to about 2 

cents per gallon of new biodiesel 

volume. 

We estimate the total cost for 

producing and distributing biodiesel to 

be between $2.00 and $2.22 per gallon 

of biodiesel, on a nationwide average 

basis. This estimate includes both the 

capital costs to upgrade the distribution 

system and freight costs. 

C. Estimated Costs to Gasoline 

To estimate the cost of increased use 

of renewable fuels, the cost savings from 

the phase out of MTBE and the 

production cost of alkylate, we 

developed our own spreadsheet cost 

model. As described above in Section 

VI.A, the cost analysis is conducted by 

comparing a base year before the Energy 

Act’s fuel changes to a modeled year 

with the fuel changes. We used 2004 as 

the base year. We grew the 2004 

gasoline demand to 2012 to create a 

reference case assuming that the 2004 

fuel demand scenario remained the 

same (fuel quality remained constant). 

The sum of fuel changes, including the 

increased use of ethanol, the phase-out 

of MTBE and the conversion of a part 

of the MTBE feedstocks to alkylate, is all 

assumed to occur by 2012 and is 

compared to the 2012 reference case. 

This analysis considers the production 

cost, distribution cost as well as the cost 

for balancing the octane and RVP 

caused by these fuel changes. 

In addition to assessing the cost at 7.2 

and 9.6 billion gallons of total ethanol 

use in gasoline, we considered that 

ethanol could be used at different levels 

in RFG. Instead of picking a single point 

for ethanol use in RFG, we assessed a 

range (see Section VI.A above). At the 

high end of the range, ethanol is used 

in RFG in both summer and winter. At 

the low end of the range, ethanol is still 

used in wintertime RFG, but to only a 

very limited extent in summertime RFG. 

The lower rate of ethanol use in 

summertime RFG may occur because 

the RVP increase associated with 

ethanol will cause refiners to incur a 

cost to further control the volatility of 

their summertime RFG. 

1. RVP Cost for Blending Ethanol Into 

Summertime RFG 

Blending ethanol into summertime 

RFG causes about a 1 PSI (pounds per 

square inch) increase in RVP. To enable 

this gasoline to continue to be sold into 

the summertime RFG market, this vapor 

pressure increase must be accounted for 

by adjusting the RVP of the base 

gasoline. The vapor pressure adjustment 

is made by reducing of volume of 

pentanes in the gasoline boiling that 

comes from the fluid catalytic cracking 

unit (FCCU). To reduce the pentane 

content FCC naphtha, refiners would 

likely have to add a distillation column 

called a depentanizer, where pentanes 

and lighter hydrocarbons are removed 

from the hydrocarbon feed and drawn 

off the top of the column while the 

heavier C6+ hydrocarbons are removed 

from the bottom. While the pentanes 

would be removed from the 

summertime RFG pool, they are 

expected to be reblended into either 

summertime CG or wintertime CG and 

RFG. To rebalance the RVP of the 

nonsummertime RFG pool or 

wintertime RFG or CG pool caused by 

relocated pentanes, butanes are 

estimated to be removed from the 

gasoline pool. When ethanol is blended 

into summertime RFG, about 10 percent 

of the base gasoline is lost due to the 

removed pentanes. We believe that 

refiners would reblend these removed 

pentanes into summertime CG or 

wintertime CG and RFG and rebalance 

the RVP of the gasoline pool into which 

the pentanes are being reblended by 

removing butanes, thus reducing the 

volume loss to one fifth of that if the 

pentanes were permanently removed. 

There is an opportunity cost to 

removing butanes from gasoline. In 2004 

butanes sold into the butane market 

were valued 36 cents per gallon less 

than gasoline, however, this opportunity 

cost would be much greater if pentanes 

were permanently removed from 

gasoline. 

We developed cost estimates for 

adding and operating a new 

depentanizer distillation column for the 

removal of pentanes from FCC naphtha 

in each refinery. The feed rate for an 

average FCC unit was estimated by 

PADD and ranged from 7 to 35 thousand 

barrels per day. Once the capital and 

operating costs were estimated, the total 

costs were averaged over the entire 

gasoline pool, which ranged from about 

two to three times the volume of FCC 

naphtha. When ethanol is being blended 

newly into summertime RFG, the capital 

and operating costs will both apply. 

However, when we model ethanol 

coming out of a summertime RFG 

market, we only reduce the 

depentanizer operating costs since the 

capital costs are sunk. 

Our analysis showed that the RVP 

blending costs for blending ethanol into 

summertime RFG ranges from 1 to 1.4 

cents per gallon of RFG. If the ethanol 

is coming out of summertime RFG, 

which occurs in some of the scenarios 

that we modeled, there would be a cost 

savings of 0.8 to 1.2 cents per gallon of 

RFG. 

In the cost of refinery gasoline section 

below, we took into account that 

butanes have a lower energy density 

compared to the gasoline pool from 

which the butanes were removed. This 

energy content adjustment will offset 

some of the cost for removing the 

butanes. Butane’s energy density is 

94,000 BTUs per gallon compared to 

115,000 BTU per gallon for gasoline. 

For further details on RVP reduction 

costs, see Section 7.4.2 of the RIA. 

2. Cost Savings for Phasing Out Methyl 

Tertiary Butyl Ether (MTBE) 

The Energy Act rescinded the oxygen 

standard for RFG and when the 

provision took effect, U.S. refiners 

stopped blending MTBE into gasoline. 

When MTBE use ended, the operating 

costs for operating those plants also 

ceased. The total costs saved for not 

operating the MTBE plants is calculated 

by multiplying the volume of MTBE no 

longer blended into gasoline with the 

operating costs for the plants producing 

that MTBE. 

We determined the operating costs 

saved by shutting down these plants. 

The volumetric feedstock demands and 

the operating costs factors for each of 

these MTBE plants are taken from 

literature. We estimated the MTBE 

operating costs to be $1.40 per gallon for 

captive and ethylene cracker plants, 

$1.48 per gallon for propylene oxide 

plants and $1.55 per gallon for merchant 

operating costs. Weighted by the 

percentages for domestic MTBE 

production, the average cost savings for 

no longer producing MTBE is estimated 

to be $1.46 per gallon. 

We also credited MTBE for its octane 

blending value. MTBE has a high octane 

value of 110 (R+M)/2 which increases 

its value compared to gasoline. This 

high octane value partially offsets its 

production cost. The cost of octane is 

presented above in subsection 

VII.(A)(1)(c) and is applied to the 

difference in octane value between 

MTBE and the average of the various 

gasoline grades (88 (R+M)/2). 

Accounting for MTBE’s octane value 

reduces its cost down to $1.27 to $1.38 

per gallon depending on the PADD. 

When accounting for the volume of 


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78Most people are aware of the 1 PSI RVP waiver 

that ethanol is provided for the summertime, but 

some states offer a similar waiver to ethanol for 

wintertime blending as well. 

MTBE removed, we also adjust for its 

energy content, which is 93,500 BTU 

per gallon. 

For further information on costs 

savings due to MTBE phaseout, see 

Section 7.4.3 of the RIA. 

3. Production of Alkylate From MTBE 

Feedstocks 

Discontinuing the blending of MTBE 

into U.S. gasoline is expected to result 

in the reuse of most of the primary 

MTBE feedstocks, isobutylene, to be 

used to produce alkylate. Alkylate is 

formed by reacting isobutylene together 

with isobutane. Prior to the 

establishment of the oxygen 

requirement for RFG, this isobutylene 

was, in most cases, used to make 

alkylate. Another option would be for 

reacting isobutylene with itself to form 

isooctene which would likely be 

hydrogenated to then form isooctane. 

However, our cost analysis found that 

alkylate is a more cost-effective way to 

reuse the isobutylene, even after 

considering isooctane’s higher octane 

content. The cost for converting to 

alkylate is estimated to be $1.42 per 

gallon for captive (in-refinery) plants 

and ethylene cracker plants, $1.46 per 

gallon for propylene oxide plants and 

$1.52 per gallon for merchant MTBE 

plants. We believe that the cost for 

converting merchant MTBE plants to 

alkylate is too high to support its 

conversion, thus the conversion cost is 

estimated to be $1.43 per gallon, the 

average of the conversion costs for 

captive, ethylene cracker and propylene 

oxide MTBE plants. This projected 

percent of MTBE plant conversion 

results in 0.84 gallons of alkylate 

produced for each gallon of MTBE no 

longer produced. 

The alkylate production cost is 

adjusted by PADD to account for the 

blending octane of alkylate, which 

varies by 1 to 2 cents per gallon 

depending on the value of octane in 

each PADD. Including its octane value, 

the cost of producing alkylate varies 

from $1.38 to $ 1.41 per gallon. 

For further information on production 

of alkylate from MTBE feedstocks, see 

section 7.4.4 of the RIA. 

4. Changes in Refinery Produced 

Gasoline Volume and Its Costs 

In the sections above, we estimated 

changes in gasoline volume and the cost 

associated with those volume changes 

for ethanol, MTBE, alkylate and butane. 

As these various gasoline blendstocks 

are added to or removed from the 

gasoline pool, they affect the refinery 

production of gasoline (or oxygenate 

blendstock). 

To estimate the changes in refinery 

gasoline production volumes, it was 

necessary to balance the total energy 

production of each control case to the 

reference case. The energy content of 

the reference case was estimated by 

multiplying the volumetric energy 

content of each gasoline pool 

blendstock, including MTBE, ethanol 

and refinery produced gasoline, by the 

associated gallons. 

The increase or decrease in ethanol 

content in summertime RFG assumed 

under the different scenarios resulted in 

the change in the volumes of butane in 

RFG as described above. We identified 

that the increase or decrease in ethanol 

in wintertime RFG and CG could cause 

reductions or increases in the amount of 

butanes blended into wintertime 

gasoline. Wintertime gasoline is limited 

in vapor pressure by the American 

Standard for Testing Materials (ASTM) 

RVP and V/L (vapor-liquid) standards. 

According to a refiner with extensive 

refining capacity, and also Jacobs 

Engineering, a refining industry 

consulting firm, refineries are blending 

their wintertime gasoline up to those 

standards today and are limited from 

blending more butane available to them. 

If this is the case, for each gallon of 

summertime RFG and wintertime RFG 

and CG blended with ethanol 2 percent 

of the base gasoline volume would be 

lost in terms of butane removed. 

However, some refineries may have 

room to blend more butane. Also, we are 

aware that some states offer 1 PSI 

waivers for blending of ethanol into 

wintertime gasoline, presumably to 

accommodate splash blending of 

ethanol.78 Consequently, it may be 

possible to accommodate the 1 PSI 

vapor pressure increase without forcing 

the removal of some or all of this 

butane. For this reason we assessed the 

costs as a range, on the upper end 

assuming that butane content would 

have to be removed to account for new 

ethanol blended into summertime RFG 

and wintertime RFG and CG , and on 

the low end assuming only that 

blending of ethanol into summertime 

RFG cause butanes to be removed. 

For estimating the volume of butane 

which must be removed from the 

gasoline because of the addition of 

ethanol, we assumed that ethanol will 

be used at 10 volume percent except for 

California where it would continue to be 

used at 5.7 volume percent. 

Development of the estimates for winter 

vs. summer ethanol consumption for the 

control cases is discussed in Chapter 2.1 

of the RIA. For the reference case, we 

estimated that 55 percent of the ethanol 

would be used in the winter and 45 

percent in the summer. Table VII.C.4–1 

summarizes the summertime RFG and 

wintertime RFG and CG volumes of 

ethanol and estimated change in butane 

content. 

TABLE VII.C.4–1.—ESTIMATED CHANGES IN U.S. SUMMERTIME RFG ETHANOL VOLUMES AND THEIR IMPACT ON BUTANE

BLENDING INTO GASOLINE

[Million gallons in 2012] 

Reference case 7.2 Bil gals max 

RFG 7.2 Bil gals min RFG 9.6 Bil gals max RFG 9.6 Bil gals min RFG 

Summertime RFG Ethanol 1,155 ........................ 1,932 ........................ 244 ........................... 1,932 ........................ 244 

Wintertime RFG & CG 

Ethanol.

2,178 ........................ 3,999 ........................ 4,812 ........................ 5,303 ........................ 6,132 

Change in Butane ............. .................................. ¥140 to ¥456 ........ 164 to ¥297 ............ ¥140 to ¥690 ........ 164 to ¥535 

The change in volume of ethanol, 

MTBE, alkylate, and butane for each 

control case is adjusted for energy 

content. The volume of refinery gasoline 

is then adjusted to maintain the same 

energy content as that of the reference 

gasoline pool. The refinery gasoline 

production is estimated by dividing the 

BTU content of gasoline, estimated to be 

115,000 BTU per gallon, into the total 

amount of BTUs for the entire gasoline 

pool after accounting for the BTUs of 

the other blendstocks. The BTUbalanced gasoline pool volumes for each 

control case are shown in Table 


jlentini on PROD1PC65 with PROPOSAL2
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79EPA typically assesses social benefits and costs 

of a rulemaking. However, this analysis is more 

limited in its scope by examining the average cost 

of production of ethanol and gasoline without 

accounting for the effects of farm subsidies that 

tend to distort the market price of agricultural 

commodities. 

VII.C.4–2. The changes are shown for 

both assumptions with respect to the 

need to remove butane from winter 

gasoline to accommodate more ethanol 

blending. 

TABLE VII.C.4–2.—ESTIMATED 2012 VOLUMES

[Million gallons] 

7.2 Bil gals, max RFG 7.2 Bil gals, min RFG 9.6 Bil gals, max RFG 9.6 Bil gals, min RFG 

Total Ethanol .................................... 7,200 7,200 9,600 9,600 

Increase in Ethanol .......................... 3,302 3,302 5,702 5,702 

Change in MTBE ............................. ¥2091 ¥2091 ¥2091 ¥2091 

New Alkylate .................................... 1,763 1,764 1,764 1,764 

Butane Removed in Winter .............. Yes No Yes No Yes No Yes No 

Change in Butane ............................ ¥456 ¥140 ¥297 164 ¥690 ¥140 ¥535 164 

Gasoline ........................................... 143,486 143,228 143,357 142,980 142,092 141,642 141,965 141,394 

Change in Gasoline ......................... ¥1,873 ¥2,131 ¥2,002 ¥2,379 ¥3,267 ¥3,716 ¥3,394 ¥3,965 

Change in Gasoline (%) .................. ¥1.3 ¥1.5 ¥1.4 ¥1.6 ¥2.2 ¥2.6 ¥2.3 ¥2.7 

Based on our estimated impacts on 

volumes shown in table VII.C.4–2, 

refinery produced gasoline demand will 

be reduced by a range of 1.3 percent to 

2.7 percent compared to the reference 

case, which would result in less 

imported finished petroleum products 

and/or less crude oil use. The projected 

impacts on refinery-produced gasoline 

demand depend on the volume of new 

ethanol blended into gasoline, on the 

volume of ethanol blended into 

summertime RFG and on whether 

butane blending into wintertime 

gasoline will be affected or not. To put 

this reduction in refinery-produced 

gasoline volume in perspective, the 

yearly annual growth in gasoline 

demand in this country is about 1.7 

percent. 

The cost for changes to refinery 

produced gasoline volume is assumed to 

be represented by the bulk price of 

gasoline in each PADD from EIA’s 2004 

Petroleum Marketing Annual. The 2004 

gasoline cost is adjusted to 2012 using 

the ratio of the projected crude oil price 

in 2012 of $47 per barrel to that in the 

2004 base case of $41 per barrel. The 

cost for distributing the gasoline to 

terminals is added on, which is 

estimated to be 4 cents per gallon. The 

estimated cost for producing and 

distributing gasoline to terminals 

(wholesale price at the terminal rack) 

ranges from $1.30 per gallon in the Gulf 

Coast, to $1.53 per gallon in California. 

Crude oil prices are much higher 

today which decreases the relative cost 

of producing and blending in more 

ethanol into gasoline. For this reason, 

we conducted a sensitivity analysis 

assuming that crude oil is priced at 

around $70 per barrel. Since this is only 

a sensitivity analysis, we simply ratioed 

the gasoline production costs, MTBE 

and alkylate feedstock costs and butane 

value upwards by the same ratio. The 

ratio is determined by the projected 

increase in the wholesale gasoline price 

relative to the increase in crude oil 

price. We extrapolated this relationship 

to crude oil priced at $70 per barrel 

compared to the price in 2004 which 

was $41 per barrel, which results in 

about a 1.4 ratio factor. We did not 

adjust other costs and assumptions 

which are much less sensitive to the 

price of crude oil and therefore not 

likely to change much (e.g., distribution 

costs, refinery utility costs, incremental 

octane costs, and ethanol production 

costs). At a $70 per barrel crude oil 

price, the cost for production and 

distribution of gasoline to the terminal 

ranges from $2.05 in the Gulf Coast to 

$2.43 per gallon in California. 

For further information on gasoline 

cost see section 7.4.5 in the RIA. 

5. Overall Impact on Fuel Cost 

We combined the costs and volume 

impacts described in the previous 

sections to estimate an overall fuel cost 

impact due to the changes in gasoline 

occurring with the projected fuel 

changes. This aggregated cost estimate 

includes the costs for producing and 

distributing ethanol, the blending costs 

of ethanol in summertime RFG, ending 

the production and distribution of 

MTBE, and reusing the MTBE feedstock 

isobutylene for producing alkylate, 

reducing the content of butane in 

summertime RFG and wintertime 

gasoline and for reducing the volume of 

refinery-produced gasoline. We also 

present the costs for the scenario that 

butanes would not need to be removed 

when ethanol is blended into 

wintertime gasoline. The costs for each 

control case are estimated by 

multiplying the change in volume for 

each gasoline blendstock, relative to the 

reference case, times its production, 

distribution and octane blending costs. 

The costs of these fuels changes are 

expressed two different ways. First, we 

express the cost of the program without 

the ethanol consumption subsidies in 

which the costs are based on the total 

accumulated cost of each of the fuels 

changes. The second way we express 

the cost is with the ethanol 

consumption subsidies included since 

the subsidized portion of the renewable 

fuels costs will be not be represented to 

the consumer in its fuels costs paid at 

the pump, but instead by being paid 

through the state and Federal tax 

revenues. For both cases we express the 

costs with and without butanes being 

removed due to changes in wintertime 

blending of ethanol. We evaluated the 

fuel costs using ranges in different 

assumptions to bound the many 

uncertainties in the cost analysis (see 

the DRIA for more discussion 

concerning the cost uncertainties). 

a. Cost without Ethanol Subsidies. 

Table VII.C.5.a–1 summarizes the costs 

without ethanol subsidies for each of 

the four control cases, including the cost 

for each aspect of the fuels changes, and 

the aggregated total and the per-gallon 

costs for all the fuel changes.79 This 

estimate of costs reflects the changes in 

gasoline that are occurring with the 

expanded use of ethanol, including the 

corresponding removal of MTBE. These 

costs include the labor, utility and other 

operating costs, fixed costs and the 

capital costs for all the fuel changes 

expected. We excluded Federal and 

state ethanol consumption subsidies 


jlentini on PROD1PC65 with PROPOSAL2
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55615 

which avoids the transfer payments 

caused by these subsidies that would 

hide a portion of the program’s costs. 

caused by these subsidies that would 

hide a portion of the program’s costs. 

TABLE VII.C.5.A–1.—ESTIMATED COST WITHOUT ETHANOL CONSUMPTION SUBSIDIES ($47/BBL CRUDE) 

[million dollars, except where noted] 

7.2 Bil gals, max RFG 7.2 Bil gals, min RFG 9.6 Bil gals, max RFG 9.6 Bil gals, min RFG 

Adding Ethanol ................................. 3,769 3,837 6,852 6,897 

RFG RVP Cost ................................ 72 ¥74 72 ¥74 

Eliminating MTBE ............................ ¥2,821 ¥2,821 ¥2,821 ¥2,821 

Adding Alkylate ................................ 2,520 2,520 2,521 2,521 

Butane Removed in Winter .............. Yes No Yes No Yes No Yes No 

Changing Butane Volume ................ ¥439 ¥133 ¥275 174 ¥667 ¥133 ¥510 174 

Additional Gasoline Production ........ ¥2,484 ¥2,826 ¥2,638 ¥3,141 ¥4,350 ¥4,948 ¥4,507 ¥5,270 

Total Cost Excluding Subsidies ....... 619 582 548 496 1,606 1,542 1,507 1,426 

Per-Gallon Cost Excluding Subsidies (cents per gallon) ............... 0.41 0.38 0.38 0.33 1.05 1.01 0.99 0.93 

Our analysis shows that when 

considering all the costs associated with 

these fuel changes resulting from the 

expanded use of subsidized ethanol that 

these various possible gasoline use 

scenarios will cost the U.S. $0.5 billion 

to around $1.6 billion in the year 2012. 

Expressed as per-gallon costs, these fuel 

changes would cost the U.S. 0.3 to just 

over 1 cent per gallon of gasoline. 

b. Gasoline Costs Including Ethanol 

Consumption Tax Subsidies. Table 

VII.C.5.b–1 expresses the total and pergallon gasoline costs for the four control 

scenarios with the Federal and state 

ethanol subsidies included. The Federal 

tax subsidy is 51 cents per gallon for 

each gallon of new ethanol blended into 

gasoline. The state tax subsidies apply 

in 5 states and range from 1.6 to 29 

cents per gallon. The cost reduction to 

the fuel industry and consumers are 

estimated by multiplying the subsidy 

times the volume of new ethanol 

estimated to be used in the state. The 

costs are presented for the case that 

ethanol causes butanes to be withheld 

from the wintertime gasoline pool, and 

for the case that the blending of butanes 

remains unchanged. 

TABLE VII.C.5.B–1.—ESTIMATED COST INCLUDING SUBSIDIES ($47/BBL CRUDE) 

[million dollars, except where noted] 

7.2 Bil Gals Max RFG 7.2 Bil Gals Min RFG 9.6 Bil Gals Max RFG 9.6 Bil Gals Min RFG 

Butane Removed in Winter .............. Yes No Yes No Yes No Yes No 

Total Cost without Subsidies ........... 619 582 548 496 1,606 1,542 1,507 1,426 

Federal Subsidy ............................... ¥1,684 ¥1,684 ¥1,684 ¥1,684 ¥2,908 ¥2,908 ¥2,908 ¥3,908 

State Subsidies ................................ ¥180 ¥180 ¥173 ¥173 ¥189 ¥189 ¥176 ¥176 

Total Cost Including Subsidies ........ ¥1,245 ¥1,282 ¥1,308 ¥1,361 ¥1,491 ¥1,555 ¥1,578 ¥1,657 

Per-Gallon Cost Including Subsidies 

(cents/gallon) ................................ ¥0.82 ¥0.84 ¥0.86 ¥0.89 ¥0.98 ¥1.02 ¥1.03 ¥1.08 

The cost including subsidies better 

represents gasoline’s production cost as 

might be reflected to the fuel industry 

as a whole and to consumers ‘‘at the 

pump’’ because the Federal and state 

subsidies tends to hide a portion of the 

actual costs. Our analysis suggests that 

the fuel industry and consumers will 

see a 0.8 to 1.1 cent per gallon decrease 

in the apparent cost of producing 

gasoline with these changes to gasoline. 

c. Cost Sensitivity Case Assuming $70 

per Barrel Crude Oil. As described 

above, we analyzed a sensitivity 

analysis with the future price of crude 

oil remained at today’s prices which is 

around $70 per barrel. This analysis was 

conducted by applying about a 1.4 

multiplication factor times the 2004 

gasoline production costs, MTBE and 

alkylate feedstock costs and butane 

value. This factor was derived by 

examining the historical association 

between increasing wholesale gasoline 

prices with increasing crude oil prices. 

We did not adjust the distribution costs, 

any of the utility costs, octane value and 

ethanol prices based on the assumption 

that these would change much less and 

therefore we kept them the same as that 

used in the primary analysis. The cost 

results of the sensitivity analysis are 

provided with and without the ethanol 

consumption subsidies in Table 

VII.C.5.c–1. 

TABLE VII.C.5.C–1.—ESTIMATED COSTS FOR CRUDE OIL PRICED AT $70 PER BARREL

[Million dollars and cents per gallon] 

7.2 Bil gals, max RFG 7.2 Bil gals, min RFG 9.6 Bil gals, max RFG 9.6 Bil gals, min RFG 

Butane Removed in Winter .............. Yes No Yes No Yes No Yes No 


jlentini on PROD1PC65 with PROPOSAL2
55616 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

80Subject to funding. 81Alliance of Automobile Manufacturers North 

American Fuel Survey 2005. For the final rule, we 

intend to supplement this empirical approach with 

the results of refinery modeling which might better 

capture all of the effects of ethanol blending on 

gasoline quality. 

TABLE VII.C.5.C–1.—ESTIMATED COSTS FOR CRUDE OIL PRICED AT $70 PER BARREL—Continued 

[Million dollars and cents per gallon] 

Total Cost without Subsidies 

($million) ....................................... ¥171 ¥187 ¥223 ¥245 222 196 138 105 

Per-Gallon Cost without Subsidies 

(c/gal) ............................................ ¥0.11 ¥0.12 ¥0.15 ¥0.16 0.15 0.13 0.09 0.07 

Total Cost Including Subsidies 

($million) ....................................... ¥2,035 ¥2,051 ¥2,080 ¥2,102 ¥2,875 ¥2,901 ¥2,945 ¥2,978 

Per-Gallon Cost Including Subsidies 

(c/gal) ............................................ ¥1.34 ¥1.35 ¥1.37 ¥1.38 ¥1.88 ¥1.90 ¥1.93 ¥1.95 

If crude oil stays priced at around $70 

per barrel, the cost of these fuel changes 

would decrease significantly. In fact, we 

estimate that the 7.2 billion gallon 

ethanol case would result in a cost 

savings to the U.S. even if butanes are 

removed from the wintertime gasoline 

pool when ethanol is added. When 

considering the ethanol subsidies, the 

incentive to blend in ethanol becomes 

much stronger at today’s crude oil 

prices likely causing a rapid increase in 

ethanol production volume. 

VIII. What Are the Impacts of Increased 

Ethanol Use on Emissions and Air 

Quality? 

In this section, we evaluate the impact 

of increased production and use of 

renewable fuels on emissions and air 

quality in the U.S., particularly ethanol 

and biodiesel. In performing these 

analyses, we compare the emissions 

which would have occurred in the 

future if fuel quality had remained 

unchanged from pre-Act levels to those 

which will be required under the Energy 

Policy Act of 2005 (Energy Act or the 

Act). This approach differs from that 

traditionally taken in EPA regulatory 

impact analyses. Traditionally, we 

would have compared future emissions 

with and without the requirement of the 

Energy Act. However, as described in 

Section VI, we expect that total 

renewable fuel use in the U.S. in 2012 

to exceed 7.5 billion gallons even in the 

absence of the RFS program. Thus, a 

traditional regulatory impact analysis 

would have shown no impact on 

emissions or air quality. 

Strictly speaking, if the same volume 

and types of renewable fuels are 

produced and used with and without 

the RFS program, the RFS program is 

having no impact on emissions or air 

quality. However, levels of renewable 

fuel use are increasing dramatically 

relative to both today and the recent 

past, with corresponding impacts on 

emissions and air quality. We believe 

that it is appropriate to evaluate these 

changes here, regardless of whether they 

are occurring due to economic forces or 

Energy Act requirements. 

In the process of estimating the 

impact of increased renewable fuel use, 

we also include the impact of reduced 

use of MTBE in gasoline. It is the 

increased production and use of ethanol 

which is facilitating the removal of 

MTBE while still producing the 

required volume of RFG which meets 

both commercial and EPA regulatory 

specifications. Because of this 

connection, we found it impractical to 

isolate the impact of increased ethanol 

use from the removal of MTBE. 

A. Effect of Renewable Fuel Use on 

Emissions 

1. Emissions From Gasoline Fueled 

Motor Vehicles and Equipment 

Several models of the impact of 

gasoline quality on motor vehicle 

emissions have been developed since 

the early 1990’s. We evaluated these 

models and selected those which were 

based on the most comprehensive set of 

emissions data and developed using the 

most advanced statistical tools for this 

analysis. Still, as will be described 

below, significant uncertainty still exists 

as to the effect of these gasoline 

components on emissions from both 

motor vehicle and nonroad equipment, 

particularly from the latest models 

equipped with the most advanced 

emission controls. Pending adequate 

funding, we plan to conduct significant 

vehicle and equipment testing over the 

next several years to improve our 

estimates of the impact of these 

additives and other gasoline properties 

on emissions. The results of this testing 

will not be available for inclusion in the 

analyses supporting this rulemaking. 

We hope that the results from these test 

programs will be available for reference 

in the future evaluations of the emission 

and air quality impacts of U.S. fuel 

programs required by the Act.80

The remainder of this sub-section is 

divided into three parts. The first 

evaluates the impact of increased 

ethanol use and decreased MTBE use on 

gasoline quality. The second evaluates 

the impact of increased ethanol use and 

decreased MTBE use on motor vehicle 

emissions. The third evaluates the 

impact of increased ethanol use and 

decreased MTBE use on nonroad 

equipment emissions. 

a. Gasoline Fuel Quality. For this 

proposal, we estimate the impact of 

ethanol use on gasoline quality using 

fuel survey data obtained by Alliance of 

Automobile Manufacturers (AAM) from 

2001–2005.81 We estimate the impact of 

removing MTBE from gasoline based on 

refinery modeling performed in support 

of the RFG rulemaking. We plan to 

update these estimates for the FRM 

using refinery modeling which is 

currently underway. In general, as 

shown in Table VIII.A.1.a–1, adding 

ethanol to gasoline is expected to reduce 

levels of aromatics and olefins in 

conventional gasoline, as well as reduce 

mid and high distillation temperatures 

(e.g., T50 and T90). RVP is expected to 

increase, as most areas of the country 

grant ethanol blends a 1.0 RVP waiver 

of the applicable RVP standards in the 

summer. With the exception of RVP, the 

effect of removing MTBE results in 

essentially the opposite impacts. Please 

see Chapter 2 of the DRIA for a detailed 

description of the methodologies used 

and the specific changes in projected 

fuel quality. 


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Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55617 

82The one exception was the impact of sulfur on 

emissions from these later vehicles, which is not an 

issue here due to the fact that renewable fuel use 

is not expected to change sulfur levels significantly. 

83The VOC and NOX emissions from the 2000–

2004 model year vehicles are an order of magnitude 

lower than those from the Tier 0 vehicles used to 

develop the EPA Complex and Predictive Models. 

Thus, a similar impact of a fuel parameter in terms 

of percentage means a much smaller impact in 

terms of absolute emissions. 

84For more information on California’s request 

for a waiver of the RFG oxygen mandate and the 

Decision Document for EPA’s response, see 

http://www.epa.gov/otaq/rfg_regs.htm#waiver. 

TABLE VIII.A.1.A–1.—CG FUEL QUALITY WITH AND WITHOUT OXYGENATES

Fuel parameter Typical 9 

RVP CG 

MTBE CG 

blend 

Ethanol 

CG blend 

RVP (psi) ....................................................................................................................................................... 8.7 8.7 9.7 

T50 ................................................................................................................................................................. 218 206 186 

T90 ................................................................................................................................................................. 332 324 325 

Aromatics (vol%) ............................................................................................................................................ 32 25.5 27 

Olefins (vol%) ................................................................................................................................................ 7.7 7.7 6.1 

Oxygen (wt%) ................................................................................................................................................ 0 2 3.5 

Sulfur (ppm) ................................................................................................................................................... 30 30 30 

Benzene (vol%) ............................................................................................................................................. 1.0 1.0 1.0 

The effect of adding ethanol and 

removing MTBE on the quality of RFG 

is expected to very limited. RFG must 

meet stringent VOC, NOX and toxics 

performance standards. Thus, the 

natural effects of MTBE and ethanol 

blending on gasoline must often be 

addressed through further refining. The 

largest differences are expected to exist 

in terms of the distillation temperatures, 

due to the relatively low boiling point 

of ethanol. Other fuel parameters are 

expected to be very similar. For this 

analysis we have assumed no changes to 

fuel parameters other than ethanol and 

MTBE content for RFG. 

b. Emissions from Motor Vehicles. We 

use the EPA Predictive Models to 

estimate the impact of gasoline fuel 

quality on exhaust VOC and NOX

emissions from motor vehicles. These 

models were developed in 2000, in 

support of EPA’s response to 

California’s request for a waiver of the 

RFG oxygen mandate. These models 

represent a significant update of the 

EPA Complex Model. However, they are 

still based on emission data from Tier 0 

vehicles (roughly equivalent to 1990 

model year vehicles). We based our 

estimates of the impact of fuel quality 

on CO emissions on the EPA 

MOBILE6.2 model. We base our 

estimates of the impact of fuel quality 

on exhaust toxic emissions (benzene, 

formaldehyde, acetaldehyde, and 1,3- 

butadiene) primarily on the MOBILE6.2 

model, updated to reflect the effect of 

fuel quality on exhaust VOC emissions 

per the EPA Predictive Models. Very 

limited data are available on the effect 

of gasoline quality on PM emissions. 

Therefore, the effect of increased 

ethanol use on PM emissions can only 

be qualitatively discussed. 

In responding to California’s request 

for a waiver of the RFG oxygen mandate 

in 2000, we found that both very limited 

and conflicting data were available on 

the effect of fuel quality on exhaust 

emissions from Tier 1 and later 

vehicles.82 Thus, we assumed at the 

time that changes to gasoline quality 

would not affect VOC, CO and NOX

exhaust emissions from these vehicles. 

Very little additional data has been 

collected since that time on which to 

modify this assumption. Consequently, 

for our primary analysis for today’s 

proposal we have maintained the 

assumption that changes to gasoline do 

not affect exhaust emissions from Tier 1 

and later technology vehicles. 

There is one recent study by the 

Coordinating Research Council (CRC) 

which assessed the impact of ethanol 

and two other fuel properties on 

emissions from twelve 2000–2004 

model year vehicles (CRC study E–67). 

The results of this program indicate that 

emissions from these late model year 

vehicles may be at least as sensitive to 

changes to these three fuel properties as 

Tier 0 vehicles on a percentage basis.83

However, because this study is the first 

of its kind and not all relevant fuel 

properties have yet been studied, in our 

primary analysis we continue to assume 

that exhaust emissions from Tier 1 and 

later vehicles are not sensitive to fuel 

quality. Based on the indications of the 

CRC E–67 study, we also conducted a 

sensitivity analysis where the exhaust 

VOC and NOX emission impacts for all 

vehicles were assumed to be as sensitive 

to fuel quality as Tier 0 vehicles (i.e., as 

indicated by the EPA Predictive 

Models). 

We base our estimates of fuel quality 

on non-exhaust VOC and benzene 

emissions on the EPA MOBILE6.2 

model. The one exception to this is the 

effect of ethanol on permeation 

emissions through plastic fuel tanks and 

elastomers used in fuel line 

connections. Recent testing has shown 

that ethanol increases permeation 

emissions, both by permeating itself and 

increasing the permeation of other 

gasoline components. This effect was 

included in EPA’s analysis of 

California’s most recent request for a 

waiver of the RFG oxygen requirement, 

but is not in MOBILE6.2.84 Therefore, 

we have added the effect of ethanol on 

permeation emissions to MOBILE6.2’s 

estimate of non-exhaust VOC emissions 

in assessing the impact of gasoline 

quality on these emissions. 

No models are available which 

address the impact of gasoline quality 

on PM emissions. Very limited data 

indicate that ethanol blending might 

reduce exhaust PM emissions under 

very cold weather conditions (e.g., –20 

F to 0 F). Very limited testing at warmer 

temperatures (e.g., 20 F to 75 F) shows 

no definite trend in PM emissions with 

oxygen content. Thus, for now, no 

quantitative estimates can be made 

regarding the effect of ethanol use on 

direct PM emissions. 

Table VIII.A.1.b–1 presents the 

average per vehicle (2012 fleet) emission 

impacts of three types of RFG: Nonoxygenated, a typical MTBE RFG as has 

been marketed in the Gulf Coast, and a 

typical ethanol RFG which has been 

marketed in the Midwest. 


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55618 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

TABLE VIII.A.1.B–1.—EFFECT OF RFG ON PER MILE EMISSIONS FROM TIER 0 VEHICLES RELATIVE TO A TYPICAL 9PSI

RVP CONVENTIONAL GASOLINE a

Pollutant Source Non-Oxy RFG 

(percent) 

11 Volume 

percent MTBE 

10 Volume 

percent 

ethanol 

Exhaust Emissions 

VOC ................................................................ EPA Predictive Models .................................. –7.7 –11.1 –12.9 

NOX ................................................................. ......................................................................... –1.7 2.4 6.3 

CO ................................................................... MOBILE6.2 ..................................................... –24 –28 –32 

Exhaust Benzene ............................................ EPA Predictive and Complex Models ............ –18 –30 –35 

Formaldehyde ................................................. ......................................................................... 7 11 2 

Acetaldehyde .................................................. ......................................................................... 7 –8 143 

1,3-Butadiene .................................................. ......................................................................... 22 2 –7 

Non-Exhaust Emissions 

VOC ................................................................ MOBILE6.2 & CRC E–65 ............................... –30 –30 –18 

Benzene .......................................................... MOBILE6.2 & Complex Models ..................... –5 –15 –7 

aAverage per vehicle effects for the 2012 fleet during summer conditions. 

As can be seen, the oxygenated RFG 

blends are predicted to produce a 

greater reduction in exhaust VOC and 

CO emissions than 9 RVP conventional 

gasoline, but a larger increase in NOX

emissions. This comparison assumes 

that all gasoline meets EPA’s Tier 2 

gasoline sulfur standard of 30 ppm. 

Prior to this program, RFG contained 

less sulfur than conventional gasoline 

and produced less NOX emissions. Nonexhaust VOC emissions with the 

exception of permeation are roughly the 

same due to the fact that the RVP level 

of the three blends is the same. 

However, the increased permeation 

emissions associated with ethanol 

reduces the overall effectiveness of 

ethanol RFG. 

An increase in ethanol use will also 

impact emissions of air toxics. We 

evaluated effects on four air toxics 

affected by fuel parameter changes in 

the Complex Model-benzene, 

formaldehyde, acetaldehyde and 1,3- 

butadiene. The most notable effect on 

toxic emissions in percentage terms is 

the increase in acetaldehyde with the 

use of ethanol. Acetaldehyde emissions 

more than double. However, as will be 

seen below, base acetaldehyde 

emissions are low relative to the other 

toxics. Thus, the absolute increase in 

total emissions of these four air toxics 

is still relatively low. 

Table VIII.A.1.b–2 presents the effect 

of blending either MTBE or ethanol into 

conventional gasoline while matching 

octane. 

TABLE VIII.A.1.B–2.—EFFECT OF MTBE AND ETHANOL IN CONVENTIONAL GASOLINE ON TIER 0 VEHICLE EMISSIONS

RELATIVE TO A TYPICAL NON-OXYGENATED CONVENTIONAL GASOLINE a

Pollutant Source 

11 Volume 

percent 

MTBE 

10 Volume 

percent 

ethanol b

Exhaust VOC .................................................................. EPA Predictive Models ................................................... ¥9 .2 ¥7 .4 

NOX ................................................................................. ......................................................................................... 2 .6 7 .7 

CO c ................................................................................. MOBILE6.2 ..................................................................... ¥6/¥11 ¥11/¥19 

Exhaust Benzene ............................................................ EPA Predictive and Complex Models ............................ ¥22 ¥27 

Formaldehyde ................................................................. ......................................................................................... +10 +3 

Acetaldehyde .................................................................. ......................................................................................... ¥8 +141 

1,3-Butadiene .................................................................. ......................................................................................... ¥12 ¥27 

Non-Exhaust VOC .......................................................... MOBILE6.2 ..................................................................... 0 +17 

Non-Exhaust Benzene .................................................... MOBILE6.2 & Complex Models ..................................... ¥10 +13 

aAverage per vehicle effects for the 2012 fleet during summer conditions. 

bAssumes a 1.0 psi RVP waiver for ethanol blends. 

cThe first figure shown applies to normal emitters; the second applies to high emitters. 

As was the case with the RFG blends, 

the two oxygenated blends both reduce 

exhaust VOC and CO emissions, but 

increase NOX emissions. The MTBE 

blend does not increase non-exhaust 

VOC emissions, but the ethanol blend 

does due to the commonly granted 

waiver of the RVP standard. Both blends 

have lower exhaust benzene and 1,3- 

butadiene emissions. As above, ethanol 

increases non-exhaust benzene and 

acetaldehyde emissions. 

The exhaust emission effects shown 

above for VOC and NOX emissions only 

apply to Tier 0 vehicles in our primary 

analysis. For example, MOBILE6.2 

estimates that 34% of exhaust VOC 

emissions and 16% of NOX emissions 

from gasoline vehicles in 2012 come 

from Tier 0 vehicles. In the sensitivity 

analysis, these effects are extended to all 

gasoline vehicles. The effect of RVP on 

non-exhaust VOC emissions is 

temperature dependent. The figures 

shown above are based on the 

distribution of temperatures occurring 

across the U.S. in July. 

c. Nonroad Equipment. To estimate 

the effect of gasoline quality on 

emissions from nonroad equipment, we 

used EPA’s NONROAD emission model. 

We used the 2005 version of this model, 

NONROAD2005, which includes the 

effect of ethanol on permeation 

emissions from most nonroad 

equipment. 


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85 71, Federal Register, 15804, March 29, 2006. 86 ‘‘A Comprehensive Analysis of Biodiesel 

Impacts on Exhaust Emissions,’’ Draft Technical 

Report, U.S. EPA, EPA420–P–02–001, October 

2002. http://www.epa.gov/otaq/models/biodsl.htm. 

Only sulfur and oxygen content affect 

exhaust VOC, CO and NOX emissions in 

NONROAD. Since sulfur level is 

assumed to remain constant, the only 

difference in exhaust emissions between 

conventional and reformulated gasoline 

is due to oxygen content. Table 

VIII.A.1.c–1 shows the effect of adding 

11 volume percent MTBE or 10 volume 

percent ethanol to non-oxygenated 

gasoline on these emissions. 

TABLE VIII.A.1.C–1.—EFFECT MTBE AND ETHANOL ON NONROAD EXHAUST EMISSIONS

Base fuel 

4-Stroke engines 2-Stroke engines 

11 Volume 

percent 

MTBE 

10 Volume 

percent 

ethanol 

11 Volume 

percent 

MTBE 

10 Volume 

percent 

ethanol 

Exhaust VOC ................................................................................................................... ¥9 ¥15 ¥1 ¥1 

Non-Exhaust VOC 0 ........................................................................................................ 0 26 0 26 

CO .................................................................................................................................... ¥13 ¥21 ¥8 ¥12 

NOX .................................................................................................................................. +24 +37 +12 +18 

As can be seen, higher oxygen content 

reduces exhaust VOC and CO emissions 

significantly, but also increases NOX

emissions. However, NOX emissions 

from these engines tend to be fairly low 

to start with, given the fact that these 

engines run much richer than 

stoichiometric. Thus, a large percentage 

increase of a relative low base value can 

be a relatively small increase in absolute 

terms. 

Evaporative emissions from nonroad 

equipment are impacted by only RVP, 

and permeation by ethanol content. 

Both the RVP increase due to blending 

of ethanol and its permeation effect 

cause non-exhaust VOC emissions to 

increase with the use of ethanol in 

nonroad equipment. The 26 percent 

effect represents the average impact 

across the U.S. in July for both 2-stroke 

and 4-stroke equipment. We updated 

the NONROAD2005 hose permeation 

emission factors for small spark-ignition 

engines and recreational marine 

watercraft to reflect the use of ethanol. 

For nonroad toxics emissions, we base 

our estimates of the impact of fuel 

quality on the fraction of exhaust VOC 

emissions represented by each toxic on 

MOBILE6.2 (i.e., the same effects 

predicted for onroad vehicles). The 

National Mobile Inventory Model 

(NMIM) contains estimates of the 

fraction of VOC emissions represented 

by the various air toxics based on 

oxygenate type (none, MTBE or 

ethanol). However, estimates for 

nonroad gasoline engines running on 

different fuel types are limited, making 

it difficult to accurately model the 

impacts of changes in fuel quality. In 

the recent NPRM addressing mobile air 

toxic emissions, EPA replaced the toxicrelated fuel effects contained in NMIM 

with those from MOBILE6.2 for onroad 

vehicles.85 We follow the same 

methodology here. Future testing could 

significantly alter these emission impact 

estimates. 

2. Diesel Fuel Quality: Biodiesel 

EPA assessed the impact of biodiesel 

fuel on emissions in 2002 and published 

a draft report summarizing the results.86

At that time, most of the data available 

was for pre-1998 model year onroad 

diesel engines. The results are 

summarized in Table VIII.A.2–1. As 

shown, it indicated that biodiesel 

tended to reduce emissions of VOC, CO 

and PM. The NOX emission effect was 

more variable, showing a very small 

increase on average. 

TABLE VIII.A.2–1.—EFFECT OF 20 VO% BIODIESEL BLENDS ON DIESEL EMISSIONS (%) 

Pollutant 

2002 draft 

EPA study 

(percent) 

Recent test results 

Engine testing Vehicle testing 

VOC ....................................................................................................... ¥21 ¥12% (¥35% to +14%) .... +10% (¥33% to +113%) 

CO .......................................................................................................... ¥11 ¥14% (¥28% to +1%) ...... +4% (¥11% to +44%) 

NOX ........................................................................................................ +2 +1% (¥3% to +6%) ........... +2% (¥1% to +9%) 

PM .......................................................................................................... ¥10 ¥20% (¥31%+6%) ........... ¥3% (¥57% to +40%) 

We collected relevant engine and 

vehicle emission test data developed 

since the time of the 2002 study. The 

results of our analysis of this data are 

also shown in Table VIII.A.2–1. There, 

we show the average change in the 

emissions of each pollutant across all 

the engines or vehicles tested, as well as 

the range of effects found for each 

engine or vehicle. As can be seen, the 

variability in the emission effects is 

quite large, but the results of the more 

recent testing generally corroborate the 

findings of the 2002 study. Refer to 

DRIA Tables 3.1–15 and 3.1–16, and 

their corresponding discussion, for more 

detail on the data in the above table. 

Overall, data indicating the effect of 

biodiesel on emissions is still quite 

limited. The emission effects also 

appear to be dependent on the load and 

speed of the engine (or driving cycle 

and vehicle type in the case of vehicle 

testing). However, the data are too 

limited to determine the specific way in 

which this occurs. Also, with the 

implementation of stringent NOX and 

PM emission standards to onroad and 

nonroad diesels in the 2007–2010 

timeframe, any effect on a percentage 

basis will rapidly decrease in magnitude 

on a mass basis as base emission 

inventory level decreases. As additional 

testing is performed over the next 

several years we will update this 

assessment. 

3. Renewable Fuel Production and 

Distribution 

The primary impact of renewable fuel 

production and distribution regards 

ethanol, since it is expected to be the 


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predominant renewable fuel used in the 

foreseeable future. We approximate the 

impact of increased ethanol and 

biodiesel production, including corn 

and soy farming, on emissions based on 

DOE’s GREET model, version 1.6. We 

also include emissions related to 

distributing the renewable fuels and 

take credit for reduced emissions related 

to distributing displaced gasoline and 

diesel fuel. These emissions are 

summarized in Table VIII.A.3–1. 

TABLE VIII.A.3–1.—WELL-TO-PUMP

EMISSIONS FOR PRODUCING AND

DISTRIBUTING RENEWABLE FUELS

[Grams per gallon ethanol or biodiesel] a

Pollutant Ethanol Biodiesel 

VOC .................. 3.6 41.5 

CO .................... 4.4 25.1 

NOX .................. 10.8 44.3 

PM10 ................ 6.1 1.5 

SOX ................... 7.2 7.5 

a Includes credit for reduced distribution of 

gasoline and diesel fuel. 

At the same time, areas with refineries 

might experience reduced emissions, 

not necessarily relative to current 

emission levels, but relative to those 

which would have occurred in the 

future had renewable fuel use not risen. 

However, to the degree that increased 

renewable fuel use reduces imports of 

gasoline and diesel fuel, as opposed to 

the domestic production of these fuels, 

these reduced refinery emissions will 

occur overseas and not in the U.S. 

Similarly, areas with MTBE 

production facilities might experience 

reduced emissions from these plants as 

they cease producing MTBE. However, 

many of these plants may be converted 

to produce other gasoline blendstocks, 

such as iso-octane or alkylate. In this 

case, their emissions are not likely to 

change substantially. 

B. Impact on Emission Inventories 

We use the NMIM to estimate 

emissions under the various ethanol 

scenarios on a county by county basis. 

NMIM basically runs MOBILE6.2 and 

NONROAD2005 with county-specific 

inputs pertaining to fuel quality, 

ambient conditions, levels of onroad 

vehicle VMT and nonroad equipment 

usage, etc. We ran NMIM for two 

months, July and January. We estimate 

annual emission inventories by 

summing the two monthly inventories 

and multiplying by six. 

As described above, we removed the 

effect of gasoline fuel quality on exhaust 

VOC and NOX emissions from the 

onroad motor vehicle inventories which 

are embedded in MOBILE6.2. We then 

applied the exhaust emission effects 

from the EPA Predictive Models. In our 

primary analysis, we only applied these 

EPA Predictive Model effects to exhaust 

VOC and NOX emissions from Tier 0 

vehicles. In a sensitivity case, we 

applied them to exhaust VOC and NOX

emissions from all vehicles. Regarding 

the effect of fuel quality on emissions of 

four air toxics from nonroad equipment 

(in terms of their fraction of VOC 

emissions), in all cases we replaced the 

fuel effects contained in NMIM with 

those for motor vehicles contained in 

MOBILE6.2. The projected emission 

inventories for the primary analysis are 

presented first, followed by those for the 

sensitivity analysis. 

1. Primary Analysis 

The national emission inventories for 

VOC, CO and NOX in 2012 with current 

fuels (i.e., ‘‘reference fuel’’) are 

summarized in Table VIII.B.1–1. Also 

shown are the changes in emissions 

projected for the two levels of ethanol 

use (i.e., ‘‘control cases’’) described in 

Section VI and the two different cases 

for ethanol use in RFG. 

TABLE VIII.B.1.–1.—2012 EMISSIONS NATIONWIDE FROM GASOLINE VEHICLES AND EQUIPMENT UNDER SEVERAL

ETHANOL USE SCENARIOS—PRIMARY ANALYSIS

[Tons per year] 

Pollutant 

Inventory Change in inventory in control cases 

Reference 

case 

7.2 Billion gallons of ethanol 9.6 Billion gallons of ethanol 

Minimum RFG 

use 

Maximum 

RFG use 

Minimum RFG 

use 

Maximum 

RFG use 

VOC ..................................................................................... 5,837,000 31,000 8,000 57,000 29,000 

NOX ...................................................................................... 2,576,000 19,000 20,000 40,000 39,000 

CO ........................................................................................ 64,799,000 ¥843,000 ¥1,229,000 ¥1,971,000 ¥2,319,000 

Benzene ............................................................................... 177,000 ¥6,000 ¥3,000 ¥11,000 ¥8,000 

Formaldehyde ...................................................................... 40,200 300 0 800 500 

Acetaldehyde ....................................................................... 19,800 6,200 5,000 9,600 8,500 

1,3-Butadiene ....................................................................... 18,200 ¥500 ¥300 ¥800 ¥600 

Both VOC and NOX emissions are 

projected to increase with increased use 

of ethanol. However, the increases are 

small, generally less than 2 percent. 

Emissions of formaldehyde are also 

projected to increase slightly, on the 

order of 1–3 percent. Emissions of 1,3- 

butadiene and CO are projected to 

decrease by about 1–4 percent. Benzene 

emissions are projected to decrease by 

2–6 percent. The largest change is in 

acetaldehyde emissions, an increase of 

25–48 percent, as acetaldehyde is a 

partial combustion product of ethanol. 

CO also participates in forming ozone, 

much like VOCs. Generally, CO is 15–

50 times less reactive than typical VOC. 

Still, the reduction in CO emissions is 

roughly 20–140 times the increase in 

VOC emissions in the four scenarios. 

Thus, the projected reduction in CO 

emissions is important from an ozone 

perspective. However, as described 

above, the methodology for projecting 

the effect of ethanol use on CO 

emissions is inconsistent with that for 

exhaust VOC and NOX emissions. Thus, 

comparisons between changes in VOC 

and CO emissions are particularly 

uncertain. 

In addition to these changes in 

emissions due to ethanol use, biodiesel 

use is expected to have a minor impact 

on diesel emissions. Table VIII.B.1–2 

shows the expected emission reductions 

associated with an increase in biodiesel 

fuel use from the reference case of 28 

million gallons in 2012 to 

approximately 300 million gallons per 

year in 2012. This represents an 

increase from 0.06 to 0.6 percent of 

onroad diesel fuel consumption. In 

terms of a 20 percent biodiesel blend 


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Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55621 

(B20), it represents an increase from 0.3 to 3.2 percent of onroad diesel fuel 

consumption. 

TABLE VIII.B.1–2.—ANNUAL EMISSIONS NATIONWIDE FROM ONROAD DIESELS IN 2012 

[Tons per year] 

Reference 

inventory: 28 

mill gal biodiesel per year 

Change in 

emissions 

Inventory: 300 

mill gal biodiesel per year 

VOC ......................................................................................................................................................................... 135,000 ¥800 

NOX .......................................................................................................................................................................... 1,430,000 800 

CO ............................................................................................................................................................................ 353,000 ¥1,100 

Fine PM ................................................................................................................................................................... 27,000 ¥100 

As can be seen, the emission impacts 

due to biodiesel use are roughly two 

orders of magnitude smaller than those 

due to ethanol use. 

There will also be some increases in 

emissions due to ethanol and biodiesel 

production. Table VIII.B.1–3 shows 

estimates of annual emissions expected 

to occur nationwide due to increased 

production of ethanol. These estimates 

include a reduction in emissions related 

to the distribution of the displaced 

gasoline. 

TABLE VIII.B.1–3.—ANNUAL EMISSIONS NATIONWIDE FROM ETHANOL PRODUCTION AND TRANSPORTATION

[Tons per year] 

Reference 

inventory 

Increase in emissions 

7.2 Billion 

gallons of 

ethanol 

9.6 Billion 

gallons of 

ethanol 

VOC ............................................................................................................................................. 15,929 12,744 22,301 

NOX .............................................................................................................................................. 47,716 38,173 66,802 

CO ................................................................................................................................................ 19,389 15,511 27,144 

PM10 ............................................................................................................................................. 27,094 21,675 37,931 

SOX .............................................................................................................................................. 31,760 25,408 44,464 

As can be seen, the potential increases 

in emissions from ethanol production 

and transportation are of the same order 

of magnitude as those from ethanol use, 

with the exception of CO emissions. The 

vast majority of these emissions are 

related to farming and ethanol 

production. Both farms and ethanol 

plants are generally located in ozone 

attainment areas. 

Table VIII.B.1–4 shows estimates of 

annual emissions expected to occur 

nationwide due to increased production 

of biodiesel. These estimates include a 

reduction in emissions related to the 

distribution of the displaced diesel fuel. 

TABLE VIII.B.1–4.—ANNUAL EMISSIONS NATIONWIDE FROM BIODIESEL PRODUCTION AND TRANSPORTATION

[Tons per year] 

Pollutant 

Reference 

inventory: 28 

mill gal biodiesel per year 

Change in 

emissions 

Inventory: 300 

mill gal biodiesel per year 

VOC ......................................................................................................................................................................... 1,300 12,700 

NOX .......................................................................................................................................................................... 1,400 13,600 

CO ............................................................................................................................................................................ 800 7,200 

PM10 ......................................................................................................................................................................... 50 1,000 

SOX .......................................................................................................................................................................... 200 1,800 

The potential emission increases 

related to biodiesel production and 

distribution are generally much smaller, 

with the possible exception of VOC 

emissions. Again, these emissions are 

generally expected to be in ozone 

attainment areas. 

2. Sensitivity Analysis 

The national emission inventories for 

VOC and NOX in 2012 with current 

fuels are summarized in Table VIII.B.2–

1. Here, the emission effects contained 

in the EPA Predictive Models are 

assumed to apply to all vehicles, not 

just Tier 0 vehicles. Also shown are the 

changes in emissions projected for the 

two cases for future ethanol volume and 

the two cases of ethanol use in RFG. CO 

emissions are the same as in the primary 

analysis, as they are not affected by the 

EPA Predictive Models. 


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TABLE VIII.B.2–1.—2012 EMISSIONS NATIONWIDE FROM GASOLINE VEHICLES AND EQUIPMENT UNDER SEVERAL ETHANOL

USE SCENARIOS: SENSITIVITY ANALYSIS

[Tons per year] 

Pollutant 

Inventory Change in inventory in control cases 

Reference 

case 

7.2 Billion gallons of ethanol 9.6 Billion gallons of ethanol 

Minimum RFG 

use 

Maximum 

RFG use 

Minimum RFG 

use 

Maximum 

RFG use 

VOC ..................................................................................... 5,775,000 4,000 ¥8,000 14,000 ¥5,000 

NOX ...................................................................................... 2,610,000 49,000 45,000 95,000 89,000 

CO ........................................................................................ 64,799,000 ¥843,000 ¥1,229,000 ¥1,971,000 ¥2,319,000 

Benzene ............................................................................... 175,000 ¥9,000 ¥5,000 ¥14,000 ¥ 10,000 

Formaldehyde ...................................................................... 39,300 0 ¥200 300 0 

Acetaldehyde ....................................................................... 19,200 5,800 4,700 9,000 8,000 

1,3-Butadiene ....................................................................... 17,900 ¥600 ¥400 ¥1,100 ¥800 

The overall VOC and NOX emission 

impacts of the various ethanol use 

scenarios change to some degree when 

all motor vehicles are assumed to be 

sensitive to fuel ethanol content. The 

increase in VOC emissions either 

decreases substantially or turns into a 

net decrease due to a greater reduction 

in exhaust VOC emissions from onroad 

vehicles. However, the increase in NOX

emissions gets larger, as more vehicles 

are assumed to be affected by ethanol. 

Emissions of the four air toxics 

generally decrease slightly, due to the 

greater reduction in exhaust VOC 

emissions. 

3. Local and Regional VOC and NOX

Emission Impacts in July 

We also estimate the percentage 

change in VOC and NOX emissions from 

gasoline fueled motor vehicles and 

equipment in those areas which actually 

experienced a significant change in 

ethanol use. Specifically, we focused on 

areas where the market share of ethanol 

blends was projected to change by 50 

percent or more. We also focused on 

summertime emissions, as these are 

most relevant to ozone formation. 

Finally, we developed separately 

estimates for: (1) RFG areas, including 

the state of California and the portions 

of Arizona where their CBG fuel 

programs apply, (2) low RVP areas (i.e., 

RVP standards less than 9.0 RVP, and 

(3) areas with a 9.0 RVP standard. This 

set of groupings helps to highlight the 

emissions impact of increased ethanol 

use in those areas where emission 

control is most important. 

Table VIII.B.3–1 presents our primary 

estimates of the percentage change in 

VOC and NOX emission inventories for 

these three types of areas. While ethanol 

use is going up in the vast majority of 

the nation, ethanol use in RFG areas 

under the ‘‘Minimum Use in RFG’’

scenarios is actually decreasing 

compared to the 2012 reference case. 

This is important to note in order to 

understand the changes in emissions 

indicated. 

TABLE VIII.B.3–1.—CHANGE IN EMISSIONS FROM GASOLINE VEHICLES AND EQUIPMENT IN COUNTIES WHERE ETHANOL

USE CHANGED SIGNIFICANTLY—PRIMARY ANALYSIS

Ethanol use 7.2 Billion gallons 9.6 Billion gallons 

Ethanol use in RFG Minimum Maximum Minimum Maximum 

RFG Areas 

Ethanol Use ....................... Down ................................. Up ...................................... Down ................................. Up. 

VOC ................................... 1.6% .................................. 0.4% .................................. 1.6% .................................. 0.4%. 

NOX ................................... ¥5.2% .............................. 2.4% .................................. ¥5.2% .............................. 2.4%. 

Low RVP Areas 

Ethanol Use ....................... Up ...................................... Up ...................................... Up ...................................... Up. 

VOC ................................... 3.1% .................................. 3.2% .................................. 4.1% .................................. 3.5%. 

NOX ................................... 4.1% .................................. 6.0% .................................. 4.8% .................................. 4.4%. 

Other Areas 

Ethanol Use ....................... Up ...................................... Up ...................................... Up ...................................... Up. 

VOC ................................... 4.1% .................................. 4.1% .................................. 5.4% .................................. 4.4%. 

NOX ................................... 4.6% .................................. 6.0% .................................. 5.8% .................................. 4.8%. 

As expected, increased ethanol use 

tends to increase NOX emissions. The 

increase in low RVP and other areas is 

greater than in RFG areas, since the RFG 

in the RFG areas included in this 

analysis all contained MTBE. Also, 

increased ethanol use tends to increase 

VOC emissions, indicating that the 

increase in non-exhaust VOC emissions 

exceeds the reduction in exhaust VOC 

emissions. This effect is muted with 

RFG due to the absence of an RVP 

waiver for ethanol blends. The reader is 

referred to Chapter 2 of the DRIA for 

discussion of how ethanol levels will 

change at the state-level. 

Table VIII.B.3–2 presents the 

percentage change in VOC and NOX


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emission inventories under our 

sensitivity case (i.e., when we apply the 

emission effects of the EPA Predictive 

Models to all motor vehicles). 

TABLE VIII.B.3–2.—CHANGE IN EMISSIONS FROM GASOLINE VEHICLES AND EQUIPMENT IN COUNTIES WHERE ETHANOL

USE CHANGED SIGNIFICANTLY—SENSITIVITY ANALYSIS

7.2 Bgal Min 7.2 Bgal Max 9.6 Bgal Min 9.6 Bgal Max 

RFG Areas 

Ethanol Use ....................... Down ................................. Up ...................................... Down ................................. Up. 

VOC ................................... 2.6% .................................. 0.2% .................................. 2.6% .................................. 0.2%. 

NOX ................................... ¥9.0% .............................. 4.7% .................................. ¥9.0% .............................. 4.7%. 

Low RVP Areas 

Ethanol Use ....................... Up ...................................... Up ...................................... Up ...................................... Up. 

VOC ................................... 2.1% .................................. 2.1% .................................. 3.1% .................................. 2.5%. 

NOX ................................... 8.2% .................................. 10.6% ................................ 9.8% .................................. 8.9%. 

Other Areas 

Ethanol Use ....................... Up ...................................... Up ...................................... Up ...................................... Up. 

VOC ................................... 3.4% .................................. 3.4% .................................. 4.6% .................................. 3.7%. 

NOX ................................... 8.4% .................................. 10.1% ................................ 10.3% ................................ 8.8%. 

Directionally, the changes in VOC and 

NOX emissions in the various areas are 

consistent with those from our primary 

analysis. The main difference is that the 

increases in VOC emissions are smaller, 

due to more vehicles experiencing a 

reduction in exhaust VOC emissions, 

and the increases in NOX emissions are 

larger. 

C. Impact on Air Quality 

We estimate the impact of increased 

ethanol use on the ambient 

concentrations of two pollutants: ozone 

and PM. Quantitative estimates are 

made for ozone, while only qualitative 

estimates can be made currently for 

ambient PM. These impacts are 

described below. 

1. Impact of 7.2 Billion Gallon Ethanol 

Use on Ozone 

We use a metamodeling tool 

developed at EPA, the ozone response 

surface metamodel (Ozone RSM), to 

estimate the effects of the projected 

changes in emissions from gasoline 

vehicles and equipment for the 7.2 

billion gallon ethanol use case. The 

changes in diesel emissions are 

negligible in comparison. We did not 

include the estimated changes in 

emissions from renewable fuel 

production and distribution, because of 

their more approximate nature. Their 

geographical concentration also makes it 

more difficult to simulate with the 

Ozone RSM. 

The Ozone RSM was created using 

multiple runs of the Comprehensive Air 

Quality Model with Extensions (CAMx). 

Base and proposed control CAMx 

metamodeling was completed for the 

year 2015 over a modeling domain that 

includes all or part of 37 Eastern U.S. 

states, plus the District of Columbia. For 

more information on the Ozone RSM, 

please see the Chapter 5 of the DRIA for 

this proposal. 

The Ozone RSM limits the number of 

geographically distinct changes in VOC 

and NOX emissions which can be 

simulated. As a result, we could not 

apply distinct changes in emissions for 

each county. Therefore, two separate 

runs were made with different VOC and 

NOX emissions reductions. We then 

selected the ozone impacts from the 

various runs which best matched the 

VOC and NOX emission reductions for 

that county. This models the impact of 

local emissions reasonably well, but 

loses some accuracy with respect to 

ozone transport. No ozone impact was 

assumed for areas which did not 

experience a significant change in 

ethanol use. The predicted ozone 

impacts of increased ethanol use for 

those areas where ethanol use is 

projected to change by more than a 50% 

market share are summarized in Table 

VIII.C.1–1. As shown in Table 5.1–2 of 

the DRIA, national average impacts 

(based on the 37-state area modeled) 

which include those areas where no 

change in ethanol use is occurring are 

considerably smaller. 

TABLE VIII.C.1–1.—IMPACT ON 8-HOUR DESIGN VALUE EQUIVALENT OZONE LEVELS (PPB) a

Primary Analysis Sensitivity Analysis 

Min RFG 

Use 

Max RFG 

Use 

Min RFG 

Use 

Max RFG 

Use 

Minimum Change ............................................................................................................. ¥0.030 ¥0.025 ¥0.180 0.000 

Maximum Change ............................................................................................................ 0.395 0.526 0.637 0.625 

Average Change b ............................................................................................................ 0.137 0.171 0.294 0.318 

Population-Weighted Change b ........................................................................................ 0.134 0.129 0.268 0.250 

a In comparison to the 80 ppb 8-hour ozone standards. 

bOnly for those areas experiencing a change in ethanol blend market share of at least 50 percent. 

As can be seen, ozone levels generally 

increase to a small degree with 

increased ethanol use. This is likely due 

to the projected increases in both VOC 

and NOX emissions. Some areas do see 

a small decrease in ozone levels. In our 

primary analysis, where exhaust 

emissions from Tier 1 and later onroad 

vehicles are assumed to be unaffected 


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55624 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

by ethanol use, the population-weighted 

increase in ambient ozone levels in 

those areas where ethanol use changed 

significantly is 0.129–0.134 ppb. Since 

the 8-hour ambient ozone standard is 80 

ppb, this increase represents about 0.16 

percent of the standard, a very small 

percentage. 

In our sensitivity analysis, where 

exhaust emissions from Tier 1 and later 

onroad vehicles are assumed to respond 

to ethanol like Tier 0 vehicles, the 

population-weighted increase in 

ambient ozone levels is roughly twice as 

high, or 0.250–0.268 ppb. This increase 

represents about 0.32 percent of the 

standard. 

There are a number of important 

caveats concerning these estimates. 

First, the emission effects of adding 

ethanol to gasoline are based on 

extremely limited data for recent 

vehicles and equipment. Second, the 

Ozone RSM does not account for 

changes in CO emissions. As shown 

above, ethanol use should reduce CO 

emissions significantly, directionally 

reducing ambient ozone levels in those 

areas where ozone formation is VOClimited. (Ozone levels in areas which 

are NOX-limited are unlikely to be 

affected by a change in CO emissions.) 

The Ozone RSM also does not account 

for changes in VOC reactivity. With 

additional ethanol use, the ethanol 

content of VOC should increase. Ethanol 

is less reactive than the average VOC. 

Therefore, this change should also 

reduce ambient ozone levels in a way 

not addressed by the Ozone RSM, again 

in those areas where ozone formation is 

predominantly VOC-limited. 

Moving to health effects, exposure to 

ozone has been linked to a variety of 

respiratory effects including premature 

mortality, hospital admissions and 

illnesses resulting in school absences. 

Ozone can also adversely affect the 

agricultural and forestry sectors by 

decreasing yields of crops and forests. 

Although the health and welfare 

impacts of changes in ambient ozone 

levels are typically quantified in 

regulatory impact analyses, we do not 

evaluate them for this analysis. On 

average, the changes in ambient ozone 

levels shown above are small and would 

be even smaller if changes in CO 

emissions and VOC reactivity were 

taken into account. The increase in 

ozone would likely lead to negligible 

monetized impacts. We therefore do not 

estimate and monetize ozone health 

impacts for the changes in renewable 

use due to the small magnitude of this 

change, and the uncertainty present in 

the air quality modeling conducted 

here, as well as the uncertainty in the 

underlying emission effects themselves 

discussed earlier. 

2. Particulate Matter 

Ambient PM can come from two 

distinct sources. First, PM can be 

directly emitted into the atmosphere. 

Second, PM can be formed in the 

atmosphere from gaseous pollutants. 

Gasoline-fueled vehicles and equipment 

contribute to ambient PM 

concentrations in both ways. 

As described above, we are not 

currently able to predict the impact of 

fuel quality on direct PM emissions 

from gasoline-fueled vehicles or 

equipment. Therefore, we are unable at 

this time to project the effect that 

increased ethanol use will have on 

levels of directly emitted PM in the 

atmosphere. 

PM can also be formed in the 

atmosphere (termed secondary PM here) 

from several gaseous pollutants emitted 

by gasoline-fueled vehicles and 

equipment. Sulfur dioxide emissions 

contribute to ambient sulfate PM. NOX

emissions contribute to ambient nitrate 

PM. VOC emissions contribute to 

ambient organic PM, particularly the 

portion of this PM comprised of organic 

carbon. Increased ethanol use is not 

expected to change gasoline sulfur 

levels, so emissions of sulfur dioxide 

and any resultant ambient 

concentrations of sulfate PM are not 

expected to change. Increased ethanol 

use is expected to increase NOX

emissions, as described above. Thus, the 

possibility exists that ambient nitrate 

PM levels could increase. Increased 

ethanol is generally expected to increase 

VOC emissions, which could also 

impact the formation of secondary 

organic PM. However, some VOC 

emissions, namely exhaust VOC 

emissions, are expected to decrease, 

while non-exhaust VOC emissions are 

expected to increase and the impact on 

PM is a function of the type of VOC 

emissions. 

The formation of secondary organic 

PM is very complex, due in part to the 

wide variety of VOCs emitted into the 

atmosphere. Whether or not a specific 

gaseous VOC reacts to form PM in the 

atmosphere depends on the types of 

reactions that VOC undergoes, which in 

turn can depend on other pollutants 

present, such as ozone, NOX and other 

reactive compounds. The relative mass 

of secondary PM formed per mass of 

gaseous VOC emitted can also depend 

on the concentration of the gaseous VOC 

and the organic PM in the atmosphere. 

Most of the secondary organic PM exists 

in a continually changing equilibrium 

between the gaseous and PM phases. 

Both the rates of these reactions and the 

gaseous-PM equilibria depend on 

temperature, so seasonal differences can 

be expected. 

Recent smog chamber studies have 

indicated that gaseous aromatic VOCs 

can form secondary PM under certain 

conditions. These compounds comprise 

a greater fraction of exhaust VOC 

emissions than non-exhaust VOC 

emissions, as non-exhaust VOC 

emissions are dominated by VOCs with 

relatively high vapor pressures. 

Aromatic VOCs tend to have lower 

vapor pressures. As increased ethanol 

use is expected to reduce exhaust VOC 

emissions, emissions of aromatic VOCs 

should also decrease. In addition, 

refiners are expected to reduce the 

aromatic content of gasoline by 5 

volume percentage points as ethanol is 

blended into gasoline. Emissions of 

aromatic VOCs should decrease with 

lower concentrations of aromatics in 

gasoline. Thus, emissions of gaseous 

aromatic VOCs could decrease for both 

reasons. 

Overall, we expect that the decrease 

in secondary organic PM is likely to 

exceed the increase in secondary nitrate 

PM. In 1999, NOX emissions from 

gasoline-fueled vehicles and equipment 

comprised about 20% of national NOX

emissions from all sources. In contrast, 

gasoline-fueled vehicles and equipment 

comprised over 60% of all national 

gaseous aromatic VOC emissions. The 

percentage increase in national NOX

emissions due to increased ethanol use 

should be smaller than the percentage 

decrease in national emissions of 

gaseous aromatics. Finally, in most 

urban areas, ambient levels of secondary 

organic PM exceed those of secondary 

nitrate PM. Thus, directionally, we 

expect a net reduction in ambient PM 

levels due to increased ethanol use. 

However, we are unable to quantify this 

reduction at this time. 

EPA currently utilizes the CMAQ 

model to predict ambient levels of PM 

as a function of gaseous and PM 

emissions. This model includes 

mechanisms to predict the formation of 

nitrate PM from NOX emissions. 

However, it does not currently include 

any mechanisms addressing the 

formation of secondary organic PM. EPA 

is currently developing a model of 

secondary organic PM from gaseous 

toluene emissions. We plan to 

incorporate this mechanism into the 

CMAQ model in 2007. The impact of 

other aromatic compounds will be 

added as further research clarifies their 

role in secondary organic PM formation. 

Therefore, we expect to be able to 

quantitatively estimate the impact of 

decreased toluene emissions and 

increased NOX emissions due to 


jlentini on PROD1PC65 with PROPOSAL2
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55625 

87 Greenhouse gases, Regulated Emissions, and 

Energy use in Transportation. 

88See Chapter 6.1.2 of the RIA for further 

discussion of input assumptions used for the 

GREET modeling. Also see IX.A.2 of this preamble 

section for a discussion about the differing 

estimates. 

increased ethanol use as part of future 

analyses of U.S. fuel requirements 

required by the Act. 

IX. Impacts on Fossil Fuel Consumption 

and Related Implications 

Renewable fuels have been of 

significant interest for many years due 

to their ability to displace fossil fuels, 

which have often been targeted as 

primary contributors to emissions of 

greenhouse gases such as carbon 

dioxide and national energy concerns 

such as dependence on foreign sources 

of petroleum. Because significantly 

more renewable fuel is expected to be 

consumed over the next few years than 

has been consumed in the past, there is 

increased interest in the degree to which 

their increased use will impact 

greenhouse gas emissions and fossil fuel 

consumption. 

Based on our analysis, we estimate 

that increases in the use of renewable 

fuels will reduce fossil fuel 

consumption and GHG emissions as 

shown in Table IX–1 in 2012. The 

results represent the percent reduction 

in total transportation sector emissions 

and energy use. The ranges result from 

different cases evaluated of the amount 

of renewable fuel (7.5 billion gallons 

versus 9.9 billion gallons) that will 

actually be produced in 2012. 

TABLE IX–1.—LIFECYCLE IMPACTS OF INCREASED RENEWABLE FUEL USE RELATIVE TO THE 2012 REFERENCE CASE

7.5 Billion 

case a

9.9 Billion 

case b

Percent Reduction in Transportation Sector Petroleum Energy Use ............................................................................. 1.0 1.6 

Percent Reduction in Transportation Sector Fossil Fuel Energy Use ............................................................................ 0.5 0.8 

Percent Reduction in Transportation Sector GHG Emissions ........................................................................................ 0.4 0.6 

Percent Reduction in Transportation Sector CO2 Emissions .......................................................................................... 0.6 0.9 

a 7.2 billion gallons of ethanol. 

b 9.6 billion gallons of ethanol. 

This section provides a summary of 

our analysis of the fossil fuel impacts of 

the RFS rule. 

A. Lifecycle Modeling 

Although the use of renewable fuels 

in the transportation sector directly 

displaces some petroleum consumed as 

motor vehicle fuel, this displacement of 

petroleum is in fact only one aspect of 

the overall impact of renewable fuels on 

fossil fuel use. Fossil fuels are also used 

in producing and transporting 

renewable feedstocks such as plants or 

animal byproducts, in converting the 

renewable feedstocks into renewable 

fuel, and in transporting and blending 

the renewable fuels for consumption as 

motor vehicle fuel. To estimate the true 

impacts of increases in renewable fuels 

on fossil fuel use, modelers attempt to 

take many or all these steps into 

account. Similarly, energy is used and 

GHGs emitted in the pumping of oil, 

transporting the oil to the refinery, 

refining the crude oil into finished 

transportation fuel, transporting the 

refined gasoline or diesel fuel to the 

consumer and then burning the fuel in 

the vehicle. Such analyses are termed 

lifecycle or well-to-wheels analyses. 

A variety of approaches are available 

to conduct lifecycle analysis. This 

variety largely reflects different 

assumptions about (1) the boundary 

conditions and (2) the estimates of input 

factors. The boundary conditions 

determine the scope of the analysis. For 

example, a lifecycle analysis could 

include energy required to make farm 

equipment as part of the estimate of 

energy required to grow corn. The 

agency chose a lifecycle analytic 

boundary that encompasses the fuelcycle and does not include the example 

used above. Differing estimates on input 

factors (e.g. amount of fertilizer to grow 

corn) can also affect the results of the 

lifecycle analysis. 

For this proposed rulemaking, we 

have made use of a fuel-cycle model, 

GREET,87 developed at Argonne 

National Laboratory (ANL) under the 

sponsorship of the U.S. Department of 

Energy’s Office of Energy Efficiency and 

Renewable Energy (EERE). GREET has 

been under development for several 

years and has undergone extensive peer 

review through multiple updates. Of the 

available sources of information on 

lifecycle analyses of energy consumed 

and emissions generated, we believe 

that GREET offers the most 

comprehensive treatment of the 

transportation sector. For instance, 

GREET provides lifecycle assessments 

for ethanol made from corn and 

cellulosic materials, biodiesel made 

from soybean oil, and petroleum-based 

gasoline and diesel fuel. Thus GREET 

provides a means for calculating the 

relative greenhouse gas (GHG) and 

petroleum impacts of renewable fuels 

that displace conventional motor 

vehicle fuels. For this proposal, we used 

version 1.7 of the GREET model, with a 

few modifications to its input 

assumptions as described in more detail 

below. 

We do not believe that it would be 

appropriate at this time to base the 

regulatory provisions for this rule on 

lifecycle modeling, as described in more 

detail in Section III.B.4. Although the 

GREET model does provide a peerreviewed source for lifecycle modeling, 

a consensus on all the assumptions, 

including point estimates, that are used 

as inputs into that model does not 

exist.88 Also, given the short timeframe 

available for the development of this 

proposal, we have not had the 

opportunity to initiate the type of public 

dialogue on lifecycle modeling that 

would be necessary before such 

analyses could be incorporated into a 

regulatory framework. We have 

therefore chosen to use lifecycle 

modeling only as a means to estimate 

the impacts of the increased use of 

renewable fuel. 

In addition to the GREET model tool, 

EPA has also developed a lifecycle 

modeling tool that is specific to 

individual fuel producers. This FUELCO2 model is intended to help fuel 

producers estimate the lifecycle 

greenhouse gas emissions and fossil 

energy use for all stages in the 

development of their specific fuel. EPA 

will evaluate whether the FUEL-CO2 

model would be an appropriate tool for 

fuel providers who wish to demonstrate 

their actual reductions in greenhouse 

gas emissions and fossil energy use. 

This may also be the best way for 

ethanol producers to quantify the 

benefits of their renewable process 

energy use when qualifying corn 

ethanol as cellulosic biomass ethanol 

(an option for ethanol producers, 

stipulated in the Act). 


jlentini on PROD1PC65 with PROPOSAL2
55626 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

1. Modifications to GREET Assumptions 

GREET is subject to periodic updates 

by ANL, each of which results in some 

changes to the inputs and assumptions 

that form the basis for the lifecycle 

estimates of emissions generated and 

energy consumed. These updates 

generally focus on those input values for 

those fuels or vehicle technologies that 

are the focus of ANL at the time. As a 

result there are a variety of other inputs 

related to ethanol and biodiesel that 

have not been updated in some time. In 

the context of the RFS program, we 

determined that some of the GREET 

input values that were either based on 

outdated information or did not 

appropriately reflect market conditions 

under a renewable fuels mandate should 

be examined more closely, and updated 

if necessary. 

In the timeframe available for 

developing this proposal, we chose to 

concentrate our efforts on those GREET 

input values for ethanol that had 

significant influence on the lifecycle 

emissions or energy estimates and that 

were likely to be based on outdated 

information. We reviewed the input 

values only for ethanol made from corn, 

since this particular renewable fuel is 

likely to continue to dominate the 

renewable fuel pool through at least 

2012. For cellulosic ethanol and 

biodiesel the GREET default values were 

used in this proposal. However, we have 

also initiated a contract with ANL to 

investigate a wider variety of GREET 

input values, including those associated 

with the following fuel/feedstock 

pathways: 

• Ethanol from corn. 

• Ethanol from cellulosic materials 

(hybrid populars, switchgrass, and corn 

stover). 

• Biodiesel from soybean oil. 

• Methanol from renewable sources. 

• Natural gas from renewable sources. 

• Renewable diesel formulations. 

The contract focuses on the potential 

fuel production developments and 

efficiency improvements that could 

occur within the time-frame of the RFS 

program. The GREET input value 

changes resulting from this work are 

projected to be available in the fall of 

2006, not in time for this proposal, but 

they will be incorporated into revised 

lifecycle assessments for the final rule. 

We did not investigate the input 

values associated with the production of 

petroleum-based gasoline or diesel fuel 

in the GREET model for this proposal. 

However, the refinery modeling 

discussed in Section VII will provide 

some additional information on the 

process energy requirements associated 

with the production of gasoline and 

diesel under a renewable fuels mandate. 

We will use information from this 

refinery modeling for the final rule to 

determine if any GREET input values 

should be changed. 

A summary of the GREET corn 

ethanol input values we investigated 

and modified for this proposal is given 

below. We also examined several other 

GREET input values, but determined 

that the default GREET values should 

not be changed for a variety of reasons. 

These included ethanol plant process 

efficiency, corn and ethanol transport 

distances and modes, corn farming 

inputs, CO2 emissions from corn 

farming land use change, and byproduct 

allocation methods. Our investigation of 

these other GREET input values are 

discussed more fully in Chapter 6 of the 

RIA. The current GREET default factors 

for these other inputs were included in 

the analysis for this proposal. 

a. Wet-Mill Versus Dry Mill Ethanol 

Plants. The two basic methods for 

producing ethanol from corn are wet 

milling and dry milling. In the wet 

milling process, the corn is soaked to 

separate the starch, used to make 

ethanol, from the other components of 

the corn kernel. In the dry milling 

process, the entire corn kernel is ground 

and fermented to produce ethanol. The 

remaining components of the corn are 

then dried for animal feed (dried 

distillers grains with solubles, or 

DDGS). Wet milling is more 

complicated and expensive than dry 

milling, but it produces more valuable 

products (ethanol plus corn syrup, corn 

oil, and corn gluten meal and feeds). 

The majority of ethanol plants in the 

United States are dry mill plants, which 

produce ethanol more simply and 

efficiently. The GREET default is 70 

percent dry mill, 30 percent wet mill. 

For this analysis, we expect most new 

ethanol plants will be dry mill 

operations. That has been the trend in 

the last few years as the demand for 

ethanol has grown, and our analysis of 

ethanol plants under construction and 

planned for the near future has verified 

this. Therefore, it was assumed that 

essentially all new ethanol facilities 

would be dry mill plants. 

b. Coal Versus Natural Gas in Ethanol 

Plants. The type of fuel used within the 

ethanol plant for process energy, to 

power the various components that are 

used in ethanol production (dryers, 

grinders, heating, etc.) can vary among 

ethanol plants. The type of fuel used has 

an impact on the energy usage, 

efficiency, and emissions of the plant, 

and is primarily determined by 

economics. Most new plants built in the 

last few years have used natural gas. 

Based on specific situations and 

economics, some new plants are using 

coal. In addition, EPA is promoting the 

use of combined heat and power, or 

cogeneration, in ethanol plants to 

improve plant energy-efficiency and to 

reduce air emissions. This technology, 

in the face of increasing natural gas 

prices, may make coal a more attractive 

energy source for new ethanol plants. 

GREET assumes that 20 percent of 

plants will be powered by coal. 

However, our review of plants under 

construction and those planned for the 

near future indicates that coal will only 

be used for approximately 10% of the 

plants. This is the value we assumed in 

GREET for our analysis. However, as 

new plants are constructed to meet the 

demands of the RFS, this percentage is 

expected to go up. Future work in 

preparation for the final rule will 

evaluate the potential trends for 

combined heat and power and coal as 

process fuel. 

c. Ethanol Production Yield. It is 

generally assumed that 1 bushel of corn 

yields 2.7 gallons of ethanol. However, 

the development of new enzymes 

continues to increase the potential 

ethanol yield. We used a value of 2.71 

gal/bu in our analysis. This value 

represents pure ethanol production (i.e. 

no denaturant). This value is consistent 

with the cost modeling of corn ethanol 

discussed in Section VII. 

2. Controversy Concerning the Ethanol 

Energy Balance 

Although we have made use of 

lifecycle impact estimates from ANL’s 

GREET model, there are a variety of 

lifecycle impact analyses from other 

researchers that provide alternative and 

sometimes significantly different 

estimates. The lifecycle energy balance 

for corn-ethanol, in particular, has been 

the subject of numerous and sometimes 

contentious debates. 

Several metrics are commonly used to 

describe the energy efficiency of 

renewable fuels. We have chosen to use 

displacement indexes for this proposal 

because they provide the least 

ambiguous and most relevant 

mechanism for estimating the impacts of 

renewable fuels on GHGs and petroleum 

consumption. However, other metrics, 

such as the net energy balance and 

energy efficiency, have more commonly 

been used in the past. The use of these 

metrics has served to complicate the 

issue since they do not involve a direct 

comparison to the gasoline that the 

ethanol is replacing. 

Among researchers who have studied 

the lifecycle energy balance of cornethanol, the primary differences of 

opinion appear to center on fossil 

energy associated with fertilizers, the 


jlentini on PROD1PC65 with PROPOSAL2
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55627 

89A net energy balance of zero, or an energy 

efficiency of 1.0, would indicate that the full 

lifecycle fossil fuels used in the production and 

transportation of ethanol are exactly equal to the 

energy in the ethanol itself. 

90Pimentel, David ‘‘Ethanol Fuel: Energy 

Balance, Economics, and Environmental Impacts 

are Negative’’, Vol. 12, No. 2, 2003 International 

Association for Mathematical Geology, Natural 

Resources Research. 

91 Pimentel, D.; Patzek, T. ‘‘Ethanol production 

using corn, switchgrass, and wood; biodiesel 

production using soybean and sunflower.’’ Nat. 

Resour. Res. 2005, 14 (1), 65–76. 

92Hammerschlag, R. ‘‘Ethanol’s Energy Return on 

Investment: A Survey of the Literature 1990—

Present.’’ Environ. Sci. Technol. 2006, 40, 1744–

1750. 

93Farrell, A., Pelvin, R., Turner, B., Joenes, A., 

O’Hare, M., Kammen, D., ‘‘Ethanol Can Contribute 

to Energy and Environmental Goals’’, Science, 1/27/ 

2006, Vol. 311, 506–508. 

94Hill, J., Nelson, E., Tilman, D., Polasky, S., 

Tiffany, D., ‘‘Environmental, economic, and 

energetic costs and benefits of biodiesel and ethanol 

biofuels’’, Proceedings of the National Academy of 

Sciences, 7/25/2006, Vol. 103, No. 30, 11206–

11210. 

energy required to convert corn into 

ethanol, and the value of co-products. 

As a result of these differences, the net 

energy balance has been estimated to be 

somewhere between ¥34 and + 31 

thousand Btu/gal, and the energy 

efficiency has been estimated to be 

somewhere between 0.6 and 1.4.89 A 

concern arises in cases where a 

researcher concludes that the net energy 

balance is negative, or the energy 

efficiency is less than 1.0. Such cases 

would indicate that the fossil energy 

used in the production and 

transportation of ethanol exceeds the 

energy in the ethanol itself, and this is 

generally interpreted to mean that 

lifecycle fossil fuel use negates the 

benefits of replacing gasoline with 

ethanol. However, since the metrics 

used do not actually compare ethanol to 

gasoline, such interpretations are 

unwarranted. 

The primary studies that conclude 

that the energy balance is negative were 

conducted by Dr. David Pimental of 

Cornell University and Dr. T. Patzek of 

University of California, Berkeley 90 91. 

Many other researchers, however, have 

criticized that work as being based on 

out-dated farming and ethanol 

production data, including data not 

normally considered in lifecycle 

analysis for fuels, and not following the 

standard methodology for lifecycle 

analysis in terms of valuing co-products. 

Furthermore, several recent surveys 

have concluded that the energy balance 

is positive, although they differ in their 

numerical estimates.92 93 94 Authors of 

the GREET model have also concluded 

that the lifecycle amount of fossil energy 

used to produce ethanol is less than the 

amount of energy in the ethanol itself. 

Based on our review of all the available 

information, we have concluded that the 

energy balance is indeed positive, and 

we believe that the GREET model 

provides an accurate basis for 

quantifying the lifecycle impacts. 

B. Overview of Methodology 

The GREET model does not provide 

estimates of energy consumed and 

emissions generated in total, such as the 

total amount of natural gas consumed in 

the U.S. in a given year by ethanol 

production facilities. Instead, it 

provides estimates on a national 

average, per fuel unit basis, such as the 

amount of natural gas consumed for the 

average ethanol production facility per 

million Btus of ethanol produced. As a 

result we could not use GREET directly 

to estimate the nationwide impacts of 

replacing some gasoline and diesel with 

renewable fuels. 

Instead, we used GREET to generate 

comparisons between renewable fuels 

and the petroleum-based fuels that they 

displace. These comparisons allowed us 

to develop displacement indexes that 

represent the amount of lifecycle GHGs 

or fossil fuel reduced when a Btu of 

renewable fuel replaces a Btu of 

gasoline or diesel. In order to estimate 

the incremental impacts of increased 

use of renewable fuels on GHGs and 

fossil fuels, we combined those 

displacement indexes with our 

renewable fuel volume scenarios and 

GHG emissions and fossil fuel 

consumption data for the conventional 

fuels replaced. For example, to estimate 

the impact of corn-ethanol use on GHGs, 

these factors were combined in the 

following way: 

SGHG,corn ethanol = Rcorn ethanol × LCgasoline × 

DIGHG,corn ethanol

Where: 

SGHG,corn ethanol = Lifecycle GHG emission 

reduction relative to the 2012 reference 

case associated with use of corn ethanol 

(million tons of GHG). 

Rcorn ethanol = Amount of gasoline replaced by 

corn ethanol on an energy basis (Btu). 

LCgasoline = Lifecycle emissions associated 

with gasoline use (million tons of GHG 

per Btu of gasoline). 

DIGHG,corn ethanol = Displacement Index for 

GHGs and corn ethanol, representing the 

percent reduction in gasoline lifecycle 

GHG emissions which occurs when a Btu 

of gasoline is replaced by a Btu of corn 

ethanol. 

Variations of the above equation were 

also generated for impacts on all four 

endpoints of interest (emissions of CO2, 

emissions of GHGs, fossil fuel 

consumption, and petroleum 

consumption) as well as all three 

renewable fuels examined (cornethanol, cellulosic ethanol, and 

biodiesel). Each of the variables in the 

above equation are discussed in more 

detail below. Section 6 of the DRIA 

provides details of the analysis. 

1. Amount of Conventional Fuel 

Replaced by Renewable Fuel (R) 

In general, the volume fraction (R) 

represents the amount of conventional 

fuel no longer consumed—that is, 

displaced—as a result of the use of the 

replacement renewable fuel. Thus R 

represents the total amount of 

renewable fuel used under each of our 

renewable fuel volume scenarios, in 

units of Btu. We make the assumption 

that vehicle energy efficiency will not 

be affected by the presence of renewable 

fuels (i.e., efficiency of combusting one 

Btu of ethanol is equal to the efficiency 

of combusting one Btu of gasoline). 

Consistent with the emissions 

modeling described in Section VII, our 

analysis of the GHG and fossil fuel 

consumption impacts of renewable fuel 

use was conducted using three volume 

scenarios. The first scenario was a base 

case representing 2004 renewable fuel 

production levels, projected to 2012. 

This scenario provided the point of 

comparison for the other two scenarios. 

The other two renewable fuel scenarios 

for 2012 represented the RFS program 

requirements and the volume projected 

by EIA. In both scenarios, we assumed 

that the biodiesel production volume 

would be 0.3 billion gallons based on an 

EIA projection, and that the cellulosic 

ethanol production volume would be 

0.25 billion gallons based on the Energy 

Act’s requirement that 250 million 

gallons of cellulosic ethanol be 

produced starting in the next year, 2013. 

The remaining renewable fuel volumes 

in each scenario would be ethanol made 

from corn. The total volumes for all 

three scenarios are shown in Table 

IX.B.1–1. For the purposes of 

calculating the R values, we assumed 

the ethanol volumes are 5% denatured, 

and the volumes were converted to total 

Btu using the appropriate volumetric 

energy content values (76,000 Btu/gal 

for ethanol, and 118,000 Btu/gal for 

biodiesel). 


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55628 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

TABLE IX.B.1–1.—VOLUME SCENARIOS IN 2012 

[billion gallons] 

Reference 

case 

RFS 

required 

volume: 

7.5 B gal 

Projected volume: 

9.9 B gal 

Corn-ethanol ...................................................................................................................................... 3 .9 6 .95 9 .35 

Cellulosic ethanol ............................................................................................................................... 0 .0 0 .25 0 .25 

Biodiesel ............................................................................................................................................ 0 .028 0 .3 0 .3 

Total volume ............................................................................................................................... 3 .928 7 .5 9 .9 

Since the impacts of increased 

renewable fuel use were measured 

relative to the 2012 reference case, the 

value of R actually represented the 

incremental amount of renewable fuel 

between the reference case and each of 

the two other scenarios. 

2. Lifecycle Impacts of Conventional 

Fuel Use (LC) 

In order to determine the lifecycle 

impact that increased renewable fuel 

volumes may have on any particular 

endpoint (fossil fuel consumption or 

emissions of GHGs), we also needed to 

know the conventional fuel inventory 

on a lifecycle basis. Since available 

sources of GHG emissions are provided 

on a direct rather than a lifecycle basis, 

we converted these direct emission and 

energy estimates into their lifecycle 

counterparts. We used GREET to 

develop multiplicative factors for 

converting direct (vehicle-based) 

emissions of GHGs and energy use into 

full lifecycle factors. Table IX.B.2–1 

shows the total lifecycle petroleum and 

GHG emissions associated with direct 

use of a Btu value of gasoline and diesel 

fuel. 

TABLE IX.B.2–1.—LIFECYCLE

EMISSIONS AND ENERGY (LC VALUES) 

Gasoline Diesel 

Petroleum (Btu/ 

Btu) ................ 1.11 1.10 

Fossil fuel (Btu/ 

Btu) ................ 1.22 1.21 

GHG (Tg-CO2- 

eq/QBtu) ........ 99.4 94.5 

CO2 (Tg-CO2/ 

QBtu) ............. 94.2 91.9 

3. Displacement Indexes (DI) 

The displacement index (DI) 

represents the percent reduction in GHG 

emissions or fossil fuel energy brought 

about by the use of a renewable fuel in 

comparison to the conventional gasoline 

or diesel that the renewable fuel 

replaces. The formula for calculating the 

displacement index depends on which 

fuel is being displaced (i.e. gasoline or 

diesel), and which endpoint is of 

interest (e.g. petroleum energy, GHG). 

For instance, when investigating the 

CO2 impacts of ethanol used in gasoline, 

the displacement index is calculated as 

follows: 

DI lifecycle CO2 = −1 CO emitted for ethanol in g/Btu

lifecycl

2

e CO emitted for gasoline in g/Btu 2

The units of g/Btu ensure that the 

comparison between the renewable fuel 

and the conventional fuel is made on a 

common basis, and that differences in 

the volumetric energy content of the 

fuels is taken into account. The 

denominator includes the CO2 emitted 

through combustion of the gasoline 

itself in addition to all the CO2 emitted 

during its manufacturer and 

distribution. The numerator, in contrast, 

includes only the CO2 emitted during 

the manufacturer and distribution of 

ethanol, not the CO2 emitted during 

combustion of the ethanol. 

The combustion of biomass-based 

fuels, such as ethanol from corn and 

woody crops, generates CO2. However, 

in the long run the CO2 emitted from 

biomass-based fuels combustion does 

not increase atmospheric CO2

concentrations, assuming the biogenic 

carbon emitted is offset by the uptake of 

CO2 resulting from the growth of new 

biomass. As a result, CO2 emissions 

from biomass-based fuels combustion 

are not included in their lifecycle 

emissions results and are not used in 

the CO2 displacement index 

calculations shown above. 

Using GREET, we calculated the 

lifecycle values for energy consumed 

and GHGs produced for corn-ethanol, 

cellulosic ethanol, and soybean-based 

biodiesel. These values were in turn 

used to calculate the displacement 

indexes. The results are shown in Table 

IX.B.3–1. Details of these calculations 

can be found in Chapter 6 of the RIA. 

As noted previously, different models 

can result in different estimates. For 

example, whereas GREET estimates a 

net GHG reduction of about 26% for 

corn ethanol compared to gasoline, the 

previously cited works by Farrell et al. 

estimates around a 13% reduction. 

TABLE IX.B.3–1.—DISPLACEMENT INDEXES DERIVED FROM GREET 

Corn ethanol 

(percent) 

Cellulosic ethanol 

(percent) 

Biodiesel 

(percent) 

DIPetroleum ...................................................................................................................................... 92.3 92.7 84.6 

DIFossil Fuel ..................................................................................................................................... 40.1 96.0 47.9 

DIGHG ........................................................................................................................................... 25.8 98.1 53.4 


jlentini on PROD1PC65 with PROPOSAL2EP22SE06.005</MATH>
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55629 

95 IPCC ‘‘Climate Change 2001: The Scientific 

Basis’’, Chapter 6; Intergovernmental Panel on 

Climate Change; J. T. Houghton, Y. Ding, D. J. 

Griggs, M. Noguer, P. J. van der Linden, X. Dai, 

C. A. Johnson; and K. Maskell, eds.; Cambridge 

University Press. Cambridge, U. K. 2001. http:// 

www.grida.no/climate/ipcc_tar/wg1/index.htm. 

TABLE IX.B.3–1.—DISPLACEMENT INDEXES DERIVED FROM GREET—Continued 

Corn ethanol 

(percent) 

Cellulosic ethanol 

(percent) 

Biodiesel 

(percent) 

DICO2 ............................................................................................................................................. 43.9 110.1 56.8 

The displacement indexes in this 

table represent the impact of replacing 

a Btu of gasoline or diesel with a Btu of 

renewable fuel. Thus, for instance, for 

every Btu of gasoline which is replaced 

by corn ethanol, the total lifecycle GHG 

emissions that would have been 

produced from that Btu of gasoline 

would be reduced by 25.8 percent. For 

every Btu of diesel which is replaced by 

biodiesel, the total lifecycle petroleum 

energy that would have been consumed 

as a result of burning that Btu of diesel 

fuel would be reduced by 84.6 percent. 

Note that our DI estimates for 

cellulosic ethanol assume that the 

ethanol in question was in fact 

produced from a cellulosic feedstock, 

such as wood, corn stalks, or 

switchgrass. However, the definition of 

cellulosic biomass ethanol given in the 

Energy Act also includes ethanol made 

from non-cellulosic feedstocks if 90 

percent of the process energy used to 

operate the facility is derived from a 

renewable source. In the context of our 

cost analysis, we have assumed this 

latter definition of cellulosic ethanol. 

Further discussion of this issue can be 

found in Chapter 1, Section 1.2.2 of the 

RIA. 

C. Impacts of Increased Renewable Fuel 

Use 

We used the methodology described 

above to calculate impacts of increased 

use of renewable fuels on consumption 

of petroleum and fossil fuels and also on 

emissions of CO2 and GHGs. This 

section describes our results. 

1. Fossil Fuels and Petroleum 

We used the equation for S above to 

calculate the reduction associated with 

the increased use of renewable fuels on 

lifecycle fossil fuels and petroleum. 

These values are then compared to the 

total U.S. transportation sector 

emissions to get a percent reduction. 

The results are presented in Tables 

IX.C.1–1 and IX.C.1–2. 

TABLE IX.C.1.–1.—FOSSIL FUEL IMPACTS OF INCREASED USE OF RENEWABLE FUELS IN THE TRANSPORTATION SECTOR

IN 2012, RELATIVE TO THE 2012 REFERENCE CASE

RFS Required 

volume: 7.5 

Bgal 

Projected volume: 9.9 Bgal 

Reduction (quadrillion Btu) ...................................................................................................................................... 0.2 0.3 

Percent reduction ..................................................................................................................................................... 0.5 0.8 

TABLE IX.C.1.–2.—PETROLEUM IMPACTS OF INCREASED USE OF RENEWABLE FUELS IN THE TRANSPORTATION SECTOR IN

2012, RELATIVE TO THE 2012 REFERENCE CASE

RFS Required 

volume: 7.5 

Bgal 

Projected volume: 9.9 Bgal 

Reduction (billion gal) .............................................................................................................................................. 2.3 3.9 

Percent reduction ..................................................................................................................................................... 1.0 1.6 

2. Greenhouse Gases and Carbon 

Dioxide 

One issue that has come to the 

forefront in the assessment of the 

environmental impacts of transportation 

fuels relates to the effect that the use of 

such fuels could have on emissions of 

greenhouse gases (GHGs). The 

combustion of fossil fuels has been 

identified as a major contributor to the 

increase in concentrations of 

atmospheric carbon dioxide (CO2) since 

the beginning of the industrialized era, 

as well as the build-up of trace GHGs 

such as methane (CH4) and nitrous 

oxide (N2O). This lifecycle analysis 

evaluates the impacts of renewable fuel 

use on greenhouse gas emissions. 

The relative global warming 

contribution of emissions of various 

greenhouse gases is dependant on their 

radiative forcing, atmospheric lifetime, 

and other considerations. For example, 

on a mass basis, the radiative forcing of 

CH4 is much higher than that of CO2, 

but its effective atmospheric residence 

time is much lower. The relative 

warming impacts of various greenhouse 

gases, taking into account factors such 

as atmospheric lifetime and direct 

warming effects, are reported on a CO2- 

equivalent basis as global warming 

potentials (GWPs). The GWPs used by 

GREET were developed by the UN 

Intergovernmental Panel on Climate 

Change (IPCC) as listed in their Third 

Assessment Report 95, and are shown in 

Table IX.C.2–1. 

TABLE IX.C.2–1.—GLOBAL WARMING

POTENTIALS FOR GREENHOUSE GASES

Greenhouse gas GWP 

CO2 ............................................... 1 

CH4 ............................................... 23 

N2O ............................................... 296 

Greenhouse gases are measured in 

terms of CO2-equivalent emissions, 

which result from multiplying the GWP 

for each of the three pollutants shown 

in the above table by the mass of 

emission for each pollutant. The sum of 


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55630 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

96 Davis, Stacy C.; Diegel, Susan W., 

Transportation Energy Data Book: 25th Edition, Oak 

Ridge National Laboratory, U.S. Department of 

Energy, ORNL–6974, 2006. 

impacts for CH4, N2O, and CO2, yields 

the total effective GHG impact. 

We used the equation for S above to 

calculate the reduction associated with 

the increased use of renewable fuels on 

lifecycle emissions of CO2. These values 

are then compared to the total U.S. 

transportation sector emissions to get a 

percent reduction. The results are 

presented in Table IX.C.2–2. 

TABLE IX.C.2–2.—CO2 EMISSION IMPACTS OF INCREASED USE OF RENEWABLE FUELS IN THE TRANSPORTATION SECTOR

IN 2012, RELATIVE TO THE 2012 REFERENCE CASE

RFS Required volume: 7.5 Bgal Projected Volume: 9.9 

Bgal 

Reduction (million metric tons CO2) 12.6 19.8 

Percent reduction 0.6 % 0.9 % 

Carbon dioxide is a subset of GHGs, 

along with CH4 and N2O as discussed 

above. It can be seen from Table IX.B.3–

1 that the displacement index of CO2 is 

greater than for GHGs for each 

renewable fuel. This indicates that 

lifecycle emissions of CH4 and N2O are 

higher for renewable fuels than for the 

conventional fuels replaced. Therefore, 

reductions associated with the increased 

use of renewable fuels on lifecycle 

emissions of GHGs are lower than the 

values for CO2. The results for GHGs are 

presented in Table IX.C.2–3. 

TABLE IX.C.2–3.—GHG EMISSION IMPACTS OF INCREASED USE OF RENEWABLE FUELS IN THE TRANSPORTATION SECTOR IN 2012, RELATIVE

TO THE 2012 REFERENCE CASE

RFS Required volume: 7.5 

Bgal 

Projected 

Volume: 9.9 

Bgal 

Reduction (million metric 

tons CO2-eq.) .. 9.0 13.5 

Percent reduction ................ 0.4% 0.6% 

D. Implications of Reduced Imports of 

Petroleum Products 

This section only considers the 

impacts on imports of oil and petroleum 

products. Expanded production and use 

of renewable fuels could have other 

economic impacts such as on the 

exports of agricultural products like 

corn. See section X of the preamble for 

a discussion on agricultural sector 

impacts. 

In 2005, the United States imported 

almost 60 percent of the oil it 

consumed. This compares to just over 

35 percent oil imports in 1975.96

Transportation accounts for 70% of the 

U.S. oil consumption. It is clear that oil 

imports have a significant impact on the 

U.S. economy. Expanded production of 

renewable fuel is expected to contribute 

to energy diversification and the 

development of domestic sources of 

energy. We consider whether the RFS 

will reduce U.S. dependence on 

imported oil by calculating avoided 

expenditures on petroleum imports. 

Note that we do not calculate whether 

this reduction is socially beneficially, 

which would depend on the scarcity 

value of domestically produced ethanol 

versus that of imported petroleum 

products. 

To assess the impact of the RFS 

program on petroleum imports, the 

fraction of domestic consumption 

derived from foreign sources was 

estimated using results from the AEO 

2006. In section 6.4.1 of the DRIA we 

describe how fuel producers change 

their mix in response to a decrease in 

fuel demand. We do not expect the 

projected reductions in petroleum 

consumption (0.3 to 0.57 Quads) to 

impact world oil prices by a measurable 

amount. We base this assumption on the 

overall size of worldwide petroleum 

demand and analysis of the AEO 2006 

cases. As a consequence, domestic 

crude oil production for the 7.5 or 9.9 

cases would not be expected to change 

significantly versus the RFS reference 

case. Thus, petroleum reductions will 

come largely from reductions in net 

petroleum imports. This conclusion is 

confirmed by comparing the AEO 2006 

low macroeconomic growth case to the 

AEO 2006 reference case, as discussed 

in the RIA 6.4.1. The AEO 2006 shows 

that for a reduction in petroleum 

demand on the order of the reductions 

estimated for the RFS, net imports will 

account for approximately 95% of the 

reductions. However, if petroleum 

reductions were large enough to impact 

world oil prices, the mix of domestic 

crude oil, imports of finished products, 

and imports of crude oil used by fuel 

producers would change. We discuss 

this uncertainty in more detail in 

section 6.4.1 of the RIA and solicit 

comments to the extent by which the 

RFS may have a price effect and impact 

the imports of crude oil and refined 

products. 

We quantified the fraction of net 

petroleum imports that would be crude 

oil versus finished products. 

Comparison of same cases in the AEO 

2006 shows that finished products 

initially compose all the net import 

reductions, followed by imported crude 

oil once reductions in consumption 

reach beyond 1.2 Quads of petroleum 

product. However, there is significant 

uncertainty in quantifying how 

refineries will change their mix of 

sources with a decrease in petroleum 

demand, particularly at the levels 

estimated for the RFS. For example, a 

comparison between the AEO low price 

case (as opposed to low macroeconomic 

growth case) and the reference case 

would yield a 50–50 split between 

product and crude imports. We believe 

that the actual refinery response could 

range between these two points, so that 

finished product imports would 

compose between 50 to 100% of the net 

import reductions, with crude oil 

imports making up the remainder. For 

the purposes of this rulemaking, we 

show values for the case where net 

import reductions come entirely from 

imports of finished products, as shown 

below in Table IX.D–1. We compare 

these reductions in imports against the 

AEO projected levels of net petroleum 

imports. The range of reductions in net 

petroleum imports are estimated to be 

between 1 to 2%, as shown in Table 

IX.D–2. 

TABLE IX.D–1.—REDUCTIONS IN

IMPORTS OF FINISHED PRODUCTS

[barrels per day] 

Cases 2012 

7.5 ............................................. 145,454 

9.9 ............................................. 240,892 


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Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55631 

97Leiby, 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 1, 1997. 

(http://pzl1.ed.ornl.gov/energysecurity.html). 

98US DOT, NHTSA 2006. ‘‘Final Regulatory 

Impact Analysis: Corporate Average Fuel Economy 

and CAFE Reform for MY 2008–2011 Light Trucks,’’

Office of Regulatory Analysis and Evaluation, 

National Center for Statistics and Analysis, March. 

(http://www.nhtsa.dot.gov/staticfiles/DOT/NHTSA/ 

Rulemaking/Rules/Associated%20Files/ 

2006_FRIAPublic.pdf). 

99For instance, the 1997 ORNL study gave a range 

for the ‘‘oil premium’’ $0 to $13 per barrel (adjusted 

to $2004) based on 1994 market conditions. The 

actual value depended on assumptions about the 

market power of foreign exporters and the 

monopsony power of the U.S., the risk of future oil 

price shocks and the employment of hedging 

strategies, and the connections between oil shocks 

and GNP. 100Stanford Energy Modeling Forum, Phillip C. 

Beccue and Hillard G. Huntington, 2005. ‘‘An 

Assessment of Oil Market Disruption Risks,’’ FINAL 

REPORT, EMF SR 8, October 3. (http:// 

www.stanford.edu/group/EMF/publications/ 

search.htm). 

101EIA (September 1997), ‘‘Petroleum 1996: 

Issues and Trends’’, Office of Oil and Gas, DOE/ 

EIA–0615, p. 71. (http://tonto.eia.doe.gov/ 

FTPROOT/petroleum/061596.pdf) 

102The average taxes per gallon of gasoline and 

diesel have stayed relatively constant. For 2000–

2006, gasoline taxes were $0.44/gallon ($2004) 

while for 2002–2006, diesel taxes were $0.49/ 

gallon. The average was taken from available EIA 

data (http://tonto.eia.doe.gov/oog/info/gdu/ 

gasdiesel.asp). 

103For reference, the U.S. Bureau of Economic 

Analysis (BEA) reports that the 2005 import 

expenditures. on energy-related petroleum products 

totaled $235.5 billion (2004$) while petroleum 

exports totaled $13.6 billion—for a net of $221.9 

billion in expenditures. Net petroleum expenditures 

made up a significant fraction of the $591.3 billion 

current account deficit in goods and services for 

2005 (2004$). (http://www.bea.gov/) 

TABLE IX.D–2.—PERCENT REDUCTIONS IN PETROLEUM IMPORTS COMPARED TO AEO2006 IMPORT PROJECTIONS

Cases 2012 

7.5 ..................................................... 1.1% 

9.9 ..................................................... 1.7% 

One of the effects of increased use of 

renewable fuel is that it diversifies the 

energy sources used in making 

transportation fuel. To the extent that 

diverse sources of fuel energy reduce 

the dependence on any one source, the 

risks, both financial as well as strategic, 

of potential disruption in supply or 

spike in cost of a particular energy 

source is reduced. 

To understand the energy security 

implications of the RFS, EPA will work 

with Oak Ridge National Laboratory 

(ORNL). As a first step, ORNL will 

update and apply the approach used in 

the 1997 report Oil Imports: An 

Assessment of Benefits and Costs, by 

Leiby, Jones, Curlee and Lee.97 This 

paper was cited and its results utilized 

in previous DOT/NHTSA rulemakings, 

including the 2006 Final Regulatory 

Impact Analysis of CAFE Reform for 

Light Trucks.98 This approach is 

consistent with that used in the 

Effectiveness and Impact of Corporate 

Average Fuel Economy (CAFE) 

Standards Report conducted by the 

National Research Council/National 

Academy of Sciences in 2002. Both 

reports estimate the marginal benefits to 

society, in dollars per barrel, of reducing 

either imports or consumption. This 

‘‘oil premium’’ approach emphasizes 

identifying those energy-security related 

costs that are not reflected in the market 

price of oil, and which may change in 

response to an incremental change in 

the level of oil imports or 

consumption.99

Since the 1997 publication of this 

report changes in oil market conditions, 

both current and projected, suggest that 

the magnitude of the ‘‘oil premium’’

may have changed. Significant factors 

that should be reconsidered include: Oil 

prices, current and anticipated levels of 

OPEC production, U.S. import levels, 

potential OPEC behavior and responses, 

and disruption likelihoods. ORNL will 

apply the most recently available careful 

quantitative assessment of disruption 

likelihoods, from the Stanford Energy 

Modeling Forum’s 2005 workshop 

series, as well as other assessments 100. 

ORNL will also revisit the issue of the 

macroeconomic consequences of oil 

market disruptions and sustained higher 

oil prices. Using the ‘‘oil premium’’

calculation methodology which 

combines short-run and long-run costs 

and benefits, and accounting for 

uncertainty in the key driving factors, 

ORNL will provide an updated range of 

estimates of the marginal energy 

security implications of displacing oil 

consumption with renewable fuels. The 

results of this work effort are not 

available for this proposal but will be 

part of the assessment of impacts of the 

RFS in the final rule. Although not 

directly applicable, financial economics 

literature has examined risk 

diversification. The agency is interested 

in ways to examine changes in risks 

associated with diversifying energy 

sources in general and solicits 

comments as such. 

We also calculate the decreased 

expenditures on petroleum imports and 

compare this with the U.S. trade 

position measured as U.S. net exports of 

all goods and services economy-wide. 

All reductions in petroleum imports are 

expected to be from finished petroleum 

products rather than crude oil. The 

reduced expenditures in petroleum 

product imports were calculated by 

multiplying the reductions in gasoline 

and diesel imports by their 

corresponding price. According to the 

EIA, the price of imported finished 

products is the market price minus 

domestic local transportation from 

refineries and minus taxes.101 An 

estimate was made by using the AEO 

2006 gasoline and distillate price 

forecasts and subtracting the average 

Federal and state taxes based on 

historical data.102

We compare these avoided petroleum 

import expenditures against the 

projected value of total U.S. net exports 

of all goods and services economy-wide. 

Net exports is a measure of the 

difference between the value of exports 

of goods and services by the U.S. and 

the value of U.S. imports of goods and 

services from the rest of the world. For 

example, according to the AEO 2006, 

the value of total import expenditures of 

goods and services exceeds the value of 

U.S. exports of goods and services to the 

rest of the world by $695 billion for 

2006 (for a net export level of minus 

$695 billion).103 This net exports level 

is projected to diminish to minus $383 

billion by 2012. In Table IX.D–3, we 

compare the avoided expenditures in 

petroleum imports versus the total value 

of U.S. net exports of goods and services 

for the whole economy for 2012. 

Relative to the 2012 projection, the 

avoided petroleum expenditures due to 

the RFS would represent 0.9 to 1.5% of 

economy-wide net exports. 


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55632 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

104 ‘‘USDA Agricultural Baseline Projections to 

2015.’’

TABLE IX.D–3.—AVOIDED PETROLEUM IMPORT EXPENDITURES FOR 2012 

[$2004 billion] 

AEO2006 total net exports RFS Cases 

Avoided expenditures 

in petroleum 

imports 

Percent 

versus total 

net exports 

(Percent) 

¥$383 ..................................................................................................................................................... 7.5 

9.9 

3.5 

5.8 

0.9 

1.5 

X. Agricultural Sector Economic 

Impacts 

As described in more detail in the 

Draft Regulatory Impact Analysis 

accompanying this proposal, we plan to 

evaluate the economic impact on the 

agricultural sector. However, due to the 

timing of that analysis, it will not be 

completed until the final rule. In the 

meantime, we briefly describe here (and 

in more detail in the draft RIA) our 

planned analyses and the sources of 

assumptions which could critically 

impact those assessments. Finally, we 

ask for specific comment on the best 

sources of information we use in these 

analyses. 

We will be using the Forest and 

Agricultural Sector Optimization Model 

(‘‘FASOM’’) developed over the past 30 

years by Bruce McCarl, Texas A&M 

University and others. This is a 

constrained optimization model which 

seeks to allocate resources and 

production to maximize producer plus 

consumer surpluses. We have consulted 

with a range of experts both within EPA 

as well as at our sister agencies, the U.S. 

Departments of Agriculture and Energy 

and they support the use of this model 

for assessing the economic impacts on 

the agricultural sector of various 

renewable fuel pathways evaluated in 

this rule. The objective of this modeling 

assessment is to predict the economic 

impacts that will directly result from the 

expanded use of farm products for 

transportation fuel production. We 

anticipate that the growing demand for 

corn for ethanol production in 

particular but also soybeans and other 

agricultural crops such as rapeseed and 

other oil seeds for biodiesel production 

will increase the production of these 

feedstocks and impact farm income. The 

additional corn to produce ethanol may 

come from several sources, including (1) 

more intensive cultivation of existing 

land that currently produces corn, (2) 

switching production from soybean and 

cotton to corn, (3) additional acres of 

land being cultivated, or (4) diversion 

from corn exports. The implications to 

U.S. net exports and environment 

effects partially depend on which 

source supplies more corn. Eventually 

various cellulose sources such as corn 

stover and switchgrass for cellulosebased ethanol production may well 

become highly demanded and also 

significantly impact the agricultural 

sector. 

Using the FASOM model, we will 

estimate the direct impact on farm 

income resulting from higher demand 

for corn and soybeans, for example. 

Additionally, we will estimate impacts 

on farm employment. Since we expect 

the higher demand for feedstock will 

increase both the supply and cost of 

feedstock, we will also consider how the 

higher renewable fuel feedstock cost 

impacts the cost of other agricultural 

products (corn and soy meal are 

important sources not only for directly 

making food for human consumption 

but also as feed for farm animals). As an 

estimate of the impact on corn and 

soybeans prices, we are relying on the 

estimates provided by the U.S. 

Department of Agriculture 104 rather 

than using the FASOM model to derive 

these price impacts. Additionally, we 

will rely on the Energy Information 

Agency’s estimates for fuel mix in 

predicting the amount of ethanol and 

biodiesel in the fuel pool. Other than 

these external constraints, we expect to 

use FASOM as the basic model for 

estimating economic impacts on farm 

sector and how these might more 

generally impact the U.S. economy. 

Note that this FASOM analysis is a 

partial equilibrium analysis, focusing 

almost exclusively on impacts in the 

U.S. agricultural sector. As a result, it 

cannot be utilized to make broader 

assessments of net social benefits 

resulting from this rulemaking, which 

for example would require evaluation of 

the transfer payments to farmers and 

ethanol producers from consumers and 

refiners. 

XI. Public Participation 

We request comments on all aspects 

of this proposal. The comment period 

for this proposed rule will be November 

12, 2006. Comments can be submitted to 

the Agency through any of the means 

listed under ADDRESSES above. 

We will hold a public hearing on 

October 13, 2006. The public hearing 

will start at 10 a.m. (Central) at the 

Sheraton Gateway Suites Chicago 

O’Hare, 6501 North Mannheim Road, 

Rosemont, Illinois 60018. If you would 

like to present testimony at the public 

hearing, we ask that you notify the 

contact person listed under FOR FURTHER

INFORMATION CONTACT above at least ten 

days beforehand. You should estimate 

the time you will need for your 

presentation and identify any needed 

audio/visual equipment. We suggest 

that you bring copies of your statement 

or other material for the EPA panel and 

the audience. It would also be helpful 

if you send us a copy of your statement 

or other materials before the hearing. 

We will arrange for a written 

transcript of the hearing and keep the 

official record of the hearing open for 30 

days to allow for the public to 

supplement the record. You may make 

arrangements for copies of the transcript 

directly with the court reporter. 

XII. Administrative Requirements 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under Executive Order (EO) 12866, 

(58 FR 51735, October 4, 1993) this 

action is a ‘‘significant regulatory 

action’’ because of the policy 

implications of the proposed rule. Even 

though EPA has estimated that 

renewable fuel use through 2012 will be 

sufficient to meet the levels required in 

the standard, the proposed rule reflects 

the first renewable fuel mandate at the 

Federal level. 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. 

B. Paperwork Reduction Act 

The information collection 

requirements in this proposed rule have 

been submitted for approval to the 

Office of Management and Budget 

(OMB) under the Paperwork Reduction 


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Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55633 

Act, 44 U.S.C. 3501 et seq. The 

Information Collection Request (ICR) 

document prepared by EPA has been 

assigned EPA ICR number 2242.01. 

The information is planned to be 

collected to ensure that the required 

amount of renewable fuel is used each 

year. The credit trading program 

required by the Energy Act will be 

satisfied through a program utilizing 

Renewable Identification Numbers 

(RIN), which serve as a surrogate for 

renewable fuel consumption. Our 

proposed RIN-based program would 

fulfill all the functions of a credit 

trading program, and thus would meet 

the Energy Act’s requirements. For each 

calendar year, each obligated party 

would be required to submit a report to 

the Agency documenting the RINs it 

acquired, and showing that the sum of 

all RINs acquired were equal to or 

greater than its renewable volume 

obligation. The Agency could then 

verify that the RINs used for compliance 

purposes were valid by simply 

comparing RINs reported by producers 

to RINs claimed by obligated parties. 

The Agency will then calculate the total 

amount of renewable fuel produced 

each year. 

For fuel standards, Section 208(a) of 

the Clean Air Act requires that 

manufacturers provide information the 

Administrator may reasonably require to 

determine compliance with the 

regulations; submission of the 

information is therefore mandatory. We 

will consider confidential all 

information meeting the requirements of 

Section 208(c) of the Clean Air Act. 

The annual public reporting and 

recordkeeping burden for this collection 

of information is estimated to be 3.1 

hours per response. Burden means the 

total time, effort, or financial resources 

expended by persons to generate, 

maintain, retain, or disclose or provide 

information to or for a Federal agency. 

This includes the time needed to review 

instructions; develop, acquire, install, 

and utilize technology and systems for 

the purposes of collecting, validating, 

and verifying information, processing 

and maintaining information, and 

disclosing and providing information; 

adjust the existing ways to comply with 

any previously applicable instructions 

and requirements which have 

subsequently changed; train personnel 

to be able to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

A document entitled ‘‘Information 

Collection Request (ICR); OMB–83 

Supporting Statement, Environmental 

Protection Agency, Office of Air and 

Radiation,’’ has been placed in the 

public docket. The supporting statement 

provides a detailed explanation of the 

Agency’s estimates by collection 

activity. The estimates contained in the 

docket are briefly summarized here: 

Estimated total number of potential 

respondents: 4,945. 

Estimated total number of responses: 

4,970. 

Estimated total annual burden hours: 

15,560. 

Estimated total annual costs: 

$2,911,000, including $1,806,240 in 

purchased services. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. 

To comment on the Agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, including the use of 

automated collection techniques, EPA 

has established a public docket for this 

rule, which includes this ICR, under 

Docket ID number EPA–OAR–2005–

0161. Submit any comments related to 

the ICR for this proposed rule to EPA 

and OMB. See the ADDRESSES section at 

the beginning of this notice for where to 

submit comments to EPA. Send 

comments to OMB at the Office of 

Information and Regulatory Affairs, 

Office of Management and Budget, 725 

17th Street, NW., Washington, DC 

20503, Attention: Desk Office for EPA. 

Since OMB is required to make a 

decision concerning the ICR between 30 

and 60 days after publication in the 

Federal Register, a comment to OMB is 

best assured of having its full effect if 

OMB receives it by October 30, 2006. 

The final rule will respond to any OMB 

or public comments on the information 

collection requirements contained in 

this proposal. 

C. Regulatory Flexibility Act 

1. Overview 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201 (see table below); (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. The following 

table provides an overview of the 

primary SBA small business categories 

potentially affected by this regulation: 

Industry Defined as small entity by SBA if: NAICS 

codesa

Gasoline refiners ........................ ≤1,500 employees and a crude capacity of ≤125,000 bpcdb ......................................................... 324110 

a North American Industrial Classification System. 

b barrels of crude per day. 

2. Background—Small Refiners Versus 

Small Refineries 

Title XV (Ethanol and Motor Fuels) of 

the Energy Policy Act provides, at 

Section 1501(a)(2) [42 U.S.C. 

7545(o)(9)(A)–(D)], special provisions 

for ‘‘small refineries’’, such as a 

temporary exemption from the 

standards until calendar year 2011. The 

Act defines the term ‘‘small refinery’’ as 

‘‘* * * a refinery for which the average 

aggregate daily crude oil throughput for 

a calendar year * * * does not exceed 

75,000 barrels.’’ This term is different 

from a small refiner, which is what the 

Regulatory Flexibility Act is concerned 

with. A small refiner is a small business 

that meets the criteria set out in SBA’s 

regulations at 13 CFR 121.201; whereas 

a small refinery, per the Energy Policy 

Act, is a refinery where the annual 

crude throughput is less than or equal 

to 75,000 barrels (i.e., a small-capacity 

refinery), and could be owned by a 


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55634 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

larger refiner that exceeds SBA’s small 

entity size standards. 

Previous EPA fuel regulations have 

afforded regulatory flexibility provisions 

to small refiners, as we believe that 

refineries owned by small businesses 

generally face unique economic 

challenges, compared to larger refiners. 

As small refiners generally lack the 

resources available to larger companies 

(including those larger companies that 

own small-capacity refineries) to raise 

capital for any necessary investments 

for meeting regulatory requirements, 

these flexibility provisions were 

provided to reduce the disproportionate 

burden on those refiners that qualified 

as small refiners. 

3. Summary of Potentially Affected 

Small Entities 

The refiners that are potentially 

affected by this proposed rule are those 

that produce gasoline. For our recent 

proposed rule ‘‘Control of Hazardous 

Air Pollutants From Mobile Sources’’

(71 FR 15804, Wednesday, March 29, 

2006), we performed an industry 

characterization of potentially affected 

gasoline refiners; we used that industry 

characterization to determine which 

refiners would also meet the SBA 

definition of a small refiner under this 

proposal. From the industry 

characterization, we determined that 

there were 20 gasoline refiners that met 

the definition of a small refiner. Of these 

20 refiners, 17 owned refineries that 

also met the Energy Policy Act’s 

definition of a small refinery. 

4. Impact of the Regulations on Small 

Entities 

As previously stated, many aspects of 

the RFS program, such as the required 

amount of annual renewable fuel 

volumes, were specified in the Energy 

Policy Act. As shown above in Table 

III.D.3.c–2, the annual projections of 

ethanol production exceed the required 

annual renewable fuel volumes. When 

the small refinery exemption ends, it is 

anticipated that there will be over one 

billion gallons in excess RINs available. 

We believe that this large volume of 

excess RINs will also lower the costs of 

this program. If there were a shortage of 

RINs, or if any party were to ‘hoard’

RINs, the cost of a RIN could be high; 

however with excess RINs, we believe 

that this program will not impose a 

significant economic burden on small 

refineries, small refiners, or any other 

obligated party. Further, we have 

determined that this proposed rule will 

not have a significant economic impact 

on a substantial number of small 

entities. 

When the Agency certifies that a rule 

will not have a significant economic 

impact on a substantial number of small 

entities, EPA’s policy is to make an 

assessment of the rule’s impact on any 

small entities and to engage the 

potentially regulated entities in a dialog 

regarding the rule, and minimize the 

impact to the extent feasible. The 

following sections discuss our outreach 

with the potentially affected small 

entities and proposed regulatory 

flexibilities to decrease the burden on 

these entities in compliance with the 

requirements of the RFS program 

5. Small Refiner Outreach 

Although we do not believe that the 

RFS program would have a significant 

economic impact on a substantial 

number of small entities, EPA 

nonetheless has tried to reduce the 

impact of this rule on small entities. We 

held meetings with small refiners to 

discuss the requirements of the RFS 

program and the special provisions 

offered by the Energy Policy Act for 

small refineries. 

The Energy Policy Act set out the 

following provisions for small 

refineries: 

• A temporary exemption from the 

Renewable Fuels Standard requirement 

until 2011; 

• An extension of the temporary 

exemption period for at least two years 

for any small refinery where it is 

determined that the refinery would be 

subject to a disproportionate economic 

hardship if required to comply; 

• Any small refinery may petition, at 

any time, for an exemption based on 

disproportionate economic hardship; 

and, 

• A small refinery may waive its 

temporary exemption to participate in 

the credit generation program, or it may 

also ‘‘opt-in’’, by waiving its temporary 

exemption, to be subject to the RFS 

requirement. 

During these meetings with the small 

refiners we also discussed the impacts 

of these provisions being offered to 

small refineries only. As stated above, 

three refiners met the definition of a 

small refiner, but their refineries did not 

meet the Act’s definition of a small 

refinery; which naturally concerned the 

small refiners. Another concern that the 

small refiners had was that if this rule 

were to have a significant economic 

impact on a substantial number of small 

entities a lengthy SBREFA process 

would ensue (which would delay the 

promulgation of the RFS rulemaking, 

and thus provide less lead time for these 

small entities prior to the RFS program 

start date). 

Following our discussions with the 

small refiners, they provided three 

suggested regulatory flexibility options 

that they believed could further assist 

affected small entities in complying 

with the RFS program standard: (1) That 

all small refiners be afforded the Act’s 

small refinery temporary exemption, (2) 

that small refiners be allowed to 

generate credits if they elect to comply 

with the RFS program standard prior to 

the 2011 small refinery compliance 

date, and (3) relieve small refiners who 

generate blending credits of the RFS 

program compliance requirements. 

We agreed with the small refiners’’

suggestion that small refiners be 

afforded temporary exemption that the 

Act specifies for small refineries. 

Regarding the small refiners’ second and 

third suggestions regarding credits, our 

proposed RIN-based program will 

automatically provide them with credit 

for any renewables that they blend into 

their motor fuels. Until 2011, small 

refiners will essentially be treated as 

oxygenate blenders and may separate 

RINs from batches and trade or sell 

these RINs. 

6. Conclusions 

After considering the economic 

impacts of today’s proposed rule on 

small entities, we certify that this action 

will not have a significant economic 

impact on a substantial number of small 

entities. 

While the Energy Policy Act provided 

for a temporary exemption for small 

refineries from the requirements of 

today’s proposed rule, these parties will 

have to comply with the requirements 

following the exemption period. 

However, we still believe that small 

refiners generally lack the resources 

available to larger companies, and 

therefore find it necessary to extend the 

small refinery temporary exemption to 

all small refiners. Thus, we are 

proposing to allow the small refinery 

temporary exemption, as set out in the 

Act, to all qualified small refiners. In 

addition, past fuels rulemakings have 

included a provision that, to qualify for 

EPA’s small refiner flexibilities, a 

refiner must have no more than 1,500 

total corporate employees and have a 

crude capacity of no more than 155,000 

bpcd (slightly higher than SBA’s crude 

capacity limit of 125,000 bpcd). To be 

consistent with these previous rules, we 

are also proposing to allow those 

refiners that meet these criteria to be 

considered small refiners for this 

rulemaking. Lastly, we are proposing 

that small refiners may separate RINs 

from batches and trade or sell these 

RINs prior to 2011 if the small refiner 

operates as a blender 


jlentini on PROD1PC65 with PROPOSAL2
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55635 

We continue to be interested in the 

potential impacts of this proposed rule 

on small entities and welcome 

comments on issues related to such 

impacts. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and tribal governments and the private 

sector. Under Section 202 of the UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to State, local, 

and tribal governments, in the aggregate, 

or to the private sector, of $100 million 

or more in any one year. Before 

promulgating an EPA rule for which a 

written statement is needed, Section 205 

of the UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most costeffective or least burdensome alternative 

that achieves the objectives of the rule. 

The provisions of Section 205 do not 

apply when they are inconsistent with 

applicable law. Moreover, Section 205 

allows EPA to adopt an alternative other 

than the least costly, most cost-effective 

or least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. 

Before EPA establishes any regulatory 

requirements that may significantly or 

uniquely affect small governments, 

including tribal governments, it must 

have developed under Section 203 of 

the UMRA a small government agency 

plan. The plan must provide for 

notifying potentially affected small 

governments, enabling officials of 

affected small governments to have 

meaningful and timely input in the 

development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

EPA has determined that this rule 

does not contain a Federal mandate that 

may result in expenditures of $100 

million or more for State, local, and 

tribal governments, in the aggregate, or 

the private sector in any one year. EPA 

has estimated that renewable fuel use 

through 2012 will be sufficient to meet 

the required levels. Therefore, 

individual refiners, blenders, and 

importers are already on track to meet 

rule obligations through normal marketdriven incentives. Thus, today’s rule is 

not subject to the requirements of 

Sections 202 and 205 of the UMRA. 

This rule contains no Federal 

mandates for State, local, or tribal 

governments as defined by the 

provisions of Title II of the UMRA. The 

rule imposes no enforceable duties on 

any of these governmental entities. 

Nothing in the rule would significantly 

or uniquely affect small governments. 

E. Executive Order 13132: Federalism 

Executive Order 13132, entitled 

‘‘Federalism’’ (64 FR 43255, August 10, 

1999), requires EPA to develop an 

accountable process to ensure 

‘‘meaningful and timely input by State 

and local officials in the development of 

regulatory policies that have Federalism 

implications.’’ ‘‘Policies that have 

Federalism implications’’ is defined in 

the Executive Order to include 

regulations that have ‘‘substantial direct 

effects on the States, on the relationship 

between the national government and 

the States, or on the distribution of 

power and responsibilities among the 

various levels of government.’’

This proposed rule does not have 

Federalism implications. It will not 

have substantial direct effects on the 

States, on the relationship between the 

national government and the States, or 

on the distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. Thus, Executive 

Order 13132 does not apply to this rule. 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between EPA 

and State and local governments, EPA 

specifically solicits comment on this 

proposed rule from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

‘‘Consultation and Coordination with 

Indian Tribal Governments’’ (65 FR 

67249, November 9, 2000), requires EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’

This proposed rule does not have 

tribal implications, as specified in 

Executive Order 13175. This rule would 

be implemented at the Federal level and 

collectively apply to refiners, blenders, 

and importers. EPA expects these 

entities to meet the standards on a 

collective basis through 2012 even 

without imposition of any RFS 

obligations on any individual party. 

Tribal governments will be affected only 

to the extent they purchase and use 

regulated fuels. Thus, Executive Order 

13175 does not apply to this rule. EPA 

specifically solicits additional comment 

on this proposed rule from tribal 

officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

Executive Order 13045: ‘‘Protection of 

Children from Environmental Health 

Risks and Safety Risks’’ (62 FR 19885, 

April 23, 1997) applies to any rule that: 

(1) Is determined to be ‘‘economically 

significant’’ as defined under Executive 

Order 12866, and (2) concerns an 

environmental health or safety risk that 

EPA has reason to believe may have a 

disproportionate effect on children. If 

the regulatory action meets both criteria, 

the Agency must evaluate the 

environmental health or safety effects of 

the planned rule on children, and 

explain why the planned regulation is 

preferable to other potentially effective 

and reasonably feasible alternatives 

considered by the Agency. 

EPA interprets Executive Order 13045 

as applying only to those regulatory 

actions that are based on health or safety 

risks, such that the analysis required 

under Section 5–501 of the Order has 

the potential to influence the regulation. 

This proposed rule is not subject to 

Executive Order 13045 because it does 

not establish an environmental standard 

intended to mitigate health or safety 

risks and because it implements specific 

standards established by Congress in 

statutes. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This rule is not a ‘‘significant energy 

action’’ as defined in Executive Order 

13211, ‘‘Actions Concerning Regulations 

That Significantly Affect Energy Supply, 

Distribution, or Use’’ (66 FR 28355 (May 

22, 2001)) because it is not likely to 

have a significant adverse effect on the 

supply, distribution, or use of energy. 

EPA expects the provisions to have 

very little effect on the national fuel 

supply, since normal market forces 

alone are promoting greater renewable 

fuel use than required by the RFS 

mandate. Nevertheless, the rule is an 

important part of the nation’s efforts to 

reduce dependence on foreign oil. We 

discuss our analysis of the energy and 

supply effects of the increased use of 

renewable fuels in Sections VI and X of 

this preamble. 


jlentini on PROD1PC65 with PROPOSAL2
55636 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

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. The NTTAA directs EPA to 

provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. 

This proposed rulemaking does not 

involve technical standards. Therefore, 

EPA is not considering the use of any 

voluntary consensus standards. 

XIII. Statutory Authority 

Statutory authority for the rules 

proposed 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 proposal, including 

the proposed recordkeeping 

requirements, come from Sections 114, 

208, and 301(a) of the CAA, 42 U.S.C. 

7414, 7542, and 7601(a). 

List of Subjects in 40 CFR Part 80 

Environmental protection, Air 

pollution control, Fuel additives, 

Gasoline, Imports, Incorporation by 

reference, Labeling, Motor vehicle 

pollution, Penalties, Reporting and 

recordkeeping requirements. 

Dated: September 7, 2006. 

Stephen L. Johnson, 

Administrator. 

40 CFR part 80 is proposed to be 

amended as follows: 

PART 80—REGULATION OF FUELS 

AND FUEL ADDITIVES 

1. The authority citation for part 80 

continues to read as follows: 

Authority: 42 U.S.C. 7414, 7542, 7545, and 

7601(a). 

2. Section 80.1100 is revised to read 

as follows: 

§ 80.1100 How is the statutory default 

requirement for 2006 implemented? 

(a) Definitions. The definitions of 

§ 80.2 and the following additional 

definitions apply to this section only. 

(1) Renewable fuel. (i) Renewable fuel 

means motor vehicle fuel that is used to 

replace or reduce the quantity of fossil 

fuel present in a fuel mixture used to 

operate a motor vehicle, and which: 

(A) Is produced from grain, starch, oil 

seeds, vegetable, animal, or fish 

materials including fats, greases, and 

oils, sugarcane, sugar beets, sugar 

components, tobacco, potatoes, or other 

biomass; or 

(B) Is natural gas produced from a 

biogas source, including a landfill, 

sewage waste treatment plant, feedlot, 

or other place where decaying organic 

material is found. 

(ii) The term ‘‘renewable fuel’’

includes cellulosic biomass ethanol, 

waste derived ethanol, biodiesel, and 

any blending components derived from 

renewable fuel. 

(2) Cellulosic biomass ethanol means 

ethanol derived from any lignocellulosic 

or hemicellulosic matter that is 

available on a renewable or recurring 

basis, including dedicated energy crops 

and trees, wood and wood residues, 

plants, grasses, agricultural residues, 

fibers, animal wastes and other waste 

materials, and municipal solid waste. 

The term also includes any ethanol 

produced in facilities where animal 

wastes or other waste materials are 

digested or otherwise used to displace 

90 percent or more of the fossil fuel 

normally used in the production of 

ethanol. 

(3) Waste derived ethanol means 

ethanol derived from animal wastes, 

including poultry fats and poultry 

wastes, and other waste materials, or 

municipal solid waste. 

(4) Small refinery means a refinery for 

which the average aggregate daily crude 

oil throughput for a calendar year (as 

determined by dividing the aggregate 

throughput for the calendar year by the 

number of days in the calendar year) 

does not exceed 75,000 barrels. 

(5) Biodiesel means a diesel fuel 

substitute produced from nonpetroleum 

renewable resources that meets the 

registration requirements for fuels and 

fuel additives established by the 

Environmental Protection Agency under 

section 211 of the Clean Air Act. It 

includes biodiesel derived from animal 

wastes (including poultry fats and 

poultry wastes) and other waste 

materials, or biodiesel derived from 

municipal solid waste and sludges and 

oils derived from wastewater and the 

treatment of wastewater. 

(b) Renewable fuel standard for 2006. 

The percentage of renewable fuel in the 

total volume of gasoline sold or 

dispensed to consumers in 2006 in the 

United States shall be a minimum of 

2.78 percent on an annual average 

volume basis. 

(c) Responsible parties. Parties 

collectively responsible for attainment 

of the standard in paragraph (b) of this 

section are refiners (including blenders) 

and importers of gasoline. However, a 

party that is a refiner only because he 

owns or operates a small refinery is 

exempt from this responsibility. 

(d) EPA determination of attainment. 

EPA will determine after the close of 

2006 whether or not the requirement in 

paragraph (b) of this section has been 

met. EPA will base this determination 

on information routinely published by 

the Energy Information Administration 

on the annual domestic volume of 

gasoline sold or dispensed to U.S. 

consumers and of ethanol produced for 

use in such gasoline, supplemented by 

readily available information 

concerning the use in motor fuel of 

other renewable fuels such as cellulosic 

biomass ethanol, waste derived ethanol, 

biodiesel, and other non-ethanol 

renewable fuels. 

(1) The renewable fuel volume will 

equal the sum of all renewable fuel 

volumes used in motor fuel, provided 

that: 

(i) One gallon of cellulosic biomass 

ethanol or waste derived ethanol shall 

be considered to be the equivalent of 2.5 

gallons of renewable fuel; and 

(ii) Only the renewable fuel portion of 

blending components derived from 

renewable fuel shall be counted towards 

the renewable fuel volume. 

(2) If the nationwide average volume 

percent of renewable fuel in gasoline in 

2006 is equal to or greater than the 

standard in paragraph (b) of this section, 

the standard has been met. 

(e) Consequence of nonattainment in 

2006. In the event that EPA determines 

that the requirement in paragraph (b) of 

this section has not been attained in 

2006, a deficit carryover volume shall be 

added to the renewable fuel volume 

obligation for 2007 for use in calculating 

the standard applicable to gasoline in 

2007. 

(1) The deficit carryover volume shall 

be calculated as follows: 

DC = Vgas* (Rs–Ra) 

Where: 

DC = Deficit carryover in gallons of 

renewable fuel. 

Vgas = Volume of gasoline sold or dispensed 

to U.S. consumers in 2006, in gallons. 

Rs = 0.0278. 

Ra = Ratio of renewable fuel volume divided 

by total gasoline volume determined in 

accordance with paragraph (d)(2) of this 

section. 

(2) There shall be no other 

consequence of failure to attain the 

standard in paragraph (b) of this section 

in 2006 for any of the parties in 

paragraph (c) of this section. 


jlentini on PROD1PC65 with PROPOSAL2
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55637 

3. Section 80.1101 is added to read as 

follows: 

§ 80.1101 Definitions. 

The definitions of § 80.2 and the 

following additional definitions apply 

for purposes of this subpart. 

(a) Cellulosic biomass ethanol means 

either of the following: 

(1) Ethanol derived from any 

lignocellulosic or hemicellulosic matter 

that is available on a renewable or 

recurring basis, which includes any of 

the following: 

(i) Dedicated energy crops and trees. 

(ii) Wood and wood residues. 

(iii) Plants. 

(iv) Grasses. 

(v) Agricultural residues. 

(vi) Animal wastes and other waste 

materials. 

(vii) Municipal solid waste. 

(2) Ethanol made at facilities at which 

animal wastes or other waste materials 

are digested or otherwise used onsite to 

displace 90 percent or more of the fossil 

fuel that is combusted to produce 

thermal energy integral to the process of 

making ethanol and which comply with 

the recordkeeping requirements of 

§ 80.1151(a)(4). 

(b) Other waste materials means 

either of the following: 

(1) Waste materials that are residues 

rather than being produced solely for 

the purpose of being combusted to 

produce energy (e.g., residual tops, 

branches, and limbs from a tree farm 

could be waste materials while wood 

chips used as fuel and which come from 

plants grown solely for such purpose 

would not be waste materials). 

(2) Waste heat that is captured from 

an off-site combustion process (e.g., 

furnace, boiler, heater, or chemical 

process). 

(c) Otherwise used means either of the 

following: 

(1) The direct combustion of the waste 

materials to make thermal energy. 

(2) The use of waste heat as a source 

of thermal energy. 

(d) Waste derived ethanol means 

ethanol derived from either of the 

following: 

(1) Animal wastes, including poultry 

fats and poultry wastes, and other waste 

materials. 

(2) Municipal solid waste. 

(e) Biogas means methane or other 

hydrocarbon gas produced from 

decaying organic material, including 

landfills, sewage waste treatment plants, 

and animal feedlots. 

(f) Renewable fuel. (1) Renewable fuel 

is motor vehicle fuel that is used to 

replace or reduce the quantity of fossil 

fuel present in a fuel mixture used to 

operate a motor vehicle, and is 

produced from either of the following: 

(i) Grain. 

(ii) Starch. 

(iii) Oilseeds. 

(iv) Vegetable, animal or fish 

materials including fats, greases and 

oils. 

(v) Sugarcane. 

(vi) Sugar beets. 

(vii) Sugar components. 

(viii) Tobacco. 

(ix) Potatoes. 

(x) Other biomass; or is natural gas 

produced from a biogas source, 

including a landfill, sewage waste 

treatment plant, feedlot, or other place 

where decaying organic material is 

found. 

(2) The term ‘‘Renewable fuel’’

includes cellulosic biomass ethanol, 

waste derived ethanol, biodiesel (monoalkyl ester), non-ester renewable diesel, 

and blending components derived from 

renewable fuel. 

(3) Small volume additives less than 

1.0 percent of the total volume of a 

renewable fuel shall be counted as part 

of the total renewable fuel volume. 

(4) A fuel produced by a renewable 

fuel producer that is used in boilers or 

heaters is not a motor vehicle fuel, and 

therefore is not a renewable fuel. 

(g) Blending component has the same 

meaning as ‘‘Gasoline blending stock, 

blendstock, or component’’ as defined at 

§ 80.2(s), for which the portion that can 

be counted as renewable fuel is 

calculated as set forth in § 80.1115(a). 

(h) Motor vehicle has the meaning 

given in Section 216(2) of the Clean Air 

Act (42 U.S.C. 7550). 

(i) Small refinery means a refinery for 

which the average aggregate daily crude 

oil throughput for the calendar year 

2004 (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. 

(j) Biodiesel (mono-alkyl ester) means 

a motor vehicle fuel or fuel additive 

which: 

(1) Is registered as a motor vehicle 

fuel or fuel additive under 40 CFR part 

79; 

(2) Is a mono-alkyl ester; 

(3) Meets ASTM D–6751–02a; 

(4) Is intended for use in engines that 

are designed to run on conventional 

diesel fuel, and 

(5) Is derived from nonpetroleum 

renewable resources (as defined in 

paragraph (o) of this section). 

(k) Non-ester renewable diesel means 

a motor vehicle fuel or fuel additive 

which: 

(1) Is registered as a motor vehicle 

fuel or fuel additive under 40 CFR part 

79; 

(2) Is not a mono-alkyl ester; 

(3) Is intended for use in engines that 

are designed to run on conventional 

diesel fuel; and 

(4) Is derived from nonpetroleum 

renewable resources (as defined in 

paragraph (o) of this section). 

(l) Biocrude means plant oils or 

animal fats that are used as feedstocks 

to any production unit in a refinery that 

normally processes crude oil to make 

gasoline or diesel fuels. 

(m) Biocrude-based renewable fuels 

are renewable fuels that are gasoline or 

diesel products resulting from the 

processing of biocrudes in atmospheric 

distillation or other process units at 

refineries that normally process 

petroleum-based feedstocks. 

(n) Importers, for the purposes of this 

subpart only, are those persons who: 

(1) Are considered importers under 

§ 80.2(r); and 

(2) Are persons who bring gasoline 

into the 48 contiguous states of the 

United States from areas that have not 

chosen to opt in to the program 

requirements of this subpart (per 

§ 80.1143). 

(o) Nonpetroleum renewable 

resources include, but are not limited to, 

either of the following: 

(1) Plant oils. 

(2) Animal fats and animal wastes, 

including poultry fats and poultry 

wastes, and other waste materials. 

(3) Municipal solid waste and sludges 

and oils derived from wastewater and 

the treatment of wastewater. 

(p) Export of renewable fuel means: 

(1) Transfer of a batch of renewable 

fuel to a location outside the United 

States; and 

(2) Transfer of a batch of renewable 

fuel from the contiguous 48 states to 

Alaska, Hawaii, or a United States 

territory, unless that state or territory 

has received an approval from the 

Administrator to opt-in to the renewable 

fuel program pursuant to § 80.1143. 

(q) Renewable Identification Number 

(RIN), is a unique number generated to 

represent a volume of renewable fuel in 

accordance with § 80.1126. 

(r) Standard-value is a RIN generated 

to represent renewable fuel with an 

equivalence value up to and including 

1.0. 

(s) Extra-value RIN is a RIN generated 

to represent renewable fuel with an 

equivalence value greater than 1.0. 

(t) Batch-RIN is a RIN that represents 

a batch of renewable fuel containing 

multiple gallons. A batch-RIN uniquely 

identifies all of the gallon-RINs in that 

batch. 

(u) Gallon-RIN is a RIN that represents 

an individual gallon of renewable fuel. 


jlentini on PROD1PC65 with PROPOSAL2
55638 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

§§ 80.1102–80.1103 [Added and Reserved] 

4. Sections 80.1102 and 80.1103 are 

added and reserved. 

5. Sections 80.1104 through 80.1107 

are added to read as follows: 

§ 80.1104 What are the implementation 

dates for the Renewable Fuel Standard 

Program? 

The RFS standards and other 

requirements of this subpart are 

effective beginning the day after [DATE 

60 DAYS AFTER PUBLICATION OF 

THE FINAL RULE IN THE FEDERAL 

REGISTER. 

§ 80.1105 What is the Renewable Fuel 

Standard? 

(a) The annual value of the renewable 

fuel standard for 2007 shall be 3.71 

percent. 

(b) Beginning with the 2008 

compliance period, EPA will calculate 

the value of the annual standard and 

publish this value in the Federal 

Register by November 30 of the year 

preceding the compliance period. 

(c) EPA will base the calculation of 

the standard on information provided 

by the Energy Information 

Administration regarding projected 

gasoline volumes and projected volumes 

of renewable fuel expected to be used in 

gasoline blending for the upcoming 

year. 

(d) EPA will calculate the annual 

renewable fuel standard using the 

following equation: 

RFStd RFV Cell

G R GS RS GE i

i i

ii i i i

= × −

( ) − + − ( ) − 100

Where: 

RFStdi = Renewable Fuel Standard in year i, 

in percent. 

RFVi = Nationwide annual volume of 

renewable fuels required by section 

211(o)(2)(B) of the Act (42 U.S.C. 7545) 

for year i, in gallons. 

Gi = Amount of gasoline projected to be used 

in the 48 contiguous states, in year i, in 

gallons. 

Ri = Amount of renewable fuel blended into 

gasoline that is projected to be used in 

the 48 contiguous states, in year i, in 

gallons. 

GSi = Amount of gasoline projected to be 

used in noncontiguous states or 

territories (if the state or territory optsin) in year i, in gallons. 

RSi = Amount of renewable fuel blended into 

gasoline that is projected to be used in 

noncontiguous states or territories (if the 

state or territory opts-in) in year i, in 

gallons. 

GEi = Amount of gasoline projected to be 

produced by exempt small refineries and 

small refiners in year i, in gallons 

(through 2010 only). 

Celli = Beginning in 2013, the amount of 

renewable fuel that is required to come 

from cellulosic sources, in year i, in 

gallons (250,000,000 gallons minimum). 

(e) Beginning with the 2013 compliance 

period, EPA will calculate the value 

of the annual cellulosic standard 

and publish this value in the 

Federal Register by November 30 of 

the year preceding the compliance 

period. 

(f) EPA will calculate the annual 

cellulosic standard using the 

following equation: 

RFCell Cell

G R GS RS i

i

ii i i

= × ( ) − + − ( ) 100

Where: 

RFCelli = Renewable Fuel Cellulosic 

Standard in year i, in percent. 

Gi = Amount of gasoline projected to be used 

in the 48 contiguous states, in year i, in 

gallons. 

Ri = Amount of renewable fuel blended into 

gasoline that is projected to be used in 

the 48 contiguous states, in year i, in 

gallons. 

GSi = Amount of gasoline projected to be 

used in noncontiguous states or 

territories (if the state or territory optsin) in year i, in gallons. 

RSi = Amount of renewable fuel blended into 

gasoline that is projected to be used in 

noncontiguous states or territories (if the 

state or territory opts-in) in year i, in 

gallons. 

Celli = Amount of renewable fuel that is 

required to come from cellulosic sources, 

in year i, in gallons (250,000,000 gallons 

minimum). 

§ 80.1106 To whom does the Renewable 

Volume Obligation apply? 

(a)(1) An obligated party is a refiner 

or blender which produces gasoline 

within the 48 contiguous states, or an 

importer which imports gasoline into 

the 48 contiguous states. 

(2) If the Administrator approves a 

petition of Alaska, Hawaii, or a United 

States territory to opt-in to the 

renewable fuel program under the 

provisions in § 80.1143, then ‘‘obligated 

party’’ shall include any refiner or 

blender which produces gasoline within 

that state or territory, or an importer 

which imports gasoline into that state or 

territory. 

(b)(1) For each calendar year starting 

with 2007, any obligated party is 

required to demonstrate, pursuant to 

§ 80.1127, that they have satisfied the 

Renewable Volume Obligation for that 

calendar year, as specified in 

§ 80.1107(a), except as otherwise 

provided in this section. 

(2) The deficit carryover provisions in 

§ 80.1127(b) only apply if all of the 

requirements specified in § 80.1127(b) 

are fully satisfied. 

(c) Any blender whose sole blending 

activity in a calendar year is to blend a 

renewable fuel (or fuels) into gasoline, 

RBOB, CBOB, or diesel fuel is not 

required to meet the renewable volume 

obligation specified in § 80.1107(a) for 

that gasoline for that calendar year. 

§ 80.1107 How is the Renewable Volume 

Obligation calculated? 

For the purposes of this section, all 

reformulated gasoline, conventional 

gasoline and blendstock, collectively 

called ‘‘gasoline’’ unless otherwise 

specified, is subject to the requirements 

under this subpart, as applicable. 

(a) The Renewable Volume Obligation 

for an obligated party is determined 

according to the following formula: 

RVOi = RFStdi × GVi + Di¥1

Where: 

RVOi = The Renewable Volume Obligation 

for a refiner, blender, or importer for 

calendar year i, in gallons of renewable 

fuel. 

RFStdi = The renewable fuel standard for 

calendar year i from § 80.1105, in 

percent. 

GVi = The non-renewable gasoline volume, 

determined in accordance with 

paragraphs (b), (c), and (d) of this 

section, which is produced or imported, 

in year i, in gallons. 

Di-1 = Renewable fuel deficit carryover from 

the previous year, per § 80.1127(b), in 

gallons. 

(b) The non-renewable gasoline 

volume for a refiner, blender, or 

importer for a given year, GVi, specified 

in paragraph (a) of this section is 

calculated as follows: 

GV G RB ix x

x

n

x

n

= − ∑ ∑

Where: 

x = Batch. 

n = Total number of batches of gasoline 

produced or imported. 

Gx = Total volume of gasoline produced or 

imported, per paragraph (c) of this 

section, in gallons. 

RBx = Total volume of renewable fuel 

blended into gasoline, in gallons. 


jlentini on PROD1PC65 with PROPOSAL2EP22SE06.006</MATH> EP22SE06.007</MATH> EP22SE06.008</MATH>
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(c) For the purposes of this section, all 

of the following products that are 

produced or imported during a calendar 

year are to be included in the volume 

used to calculate a party’s renewable 

volume obligation under paragraph (a) 

of this section, except as provided in 

paragraph (d) of this section: 

(1) Reformulated gasoline. 

(2) Conventional gasoline. 

(3) Reformulated gasoline blendstock 

for oxygenate blending (‘‘RBOB’’). 

(4) Conventional gasoline blendstock 

that becomes finished conventional 

gasoline upon the addition of oxygenate 

(‘‘CBOB’’). 

(5) Gasoline treated as blendstock 

(‘‘GTAB’’). 

(6) Blendstock that has been 

combined with other blendstock or 

finished gasoline to produce gasoline. 

(d) The following products are not 

included in the volume of gasoline 

produced or imported used to calculate 

a party’s renewable volume obligation 

under paragraph (a) of this section: 

(1) Any renewable fuel as defined in 

§ 80.1101(f). 

(2) Blendstock that has not been 

combined with other blendstock or 

finished gasoline to produce gasoline. 

(3) Gasoline produced or imported for 

use in Alaska, Hawaii, 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 § 80.1143. 

(4) Gasoline produced by a small 

refinery that has an exemption under 

§ 80.1141 or an approved small refiner 

that has an exemption under § 80.1142 

during the period that such exemptions 

are in effect. 

(5) Gasoline exported for use outside 

the United States. 

(6) For blenders, the volume of 

finished gasoline, RBOB, or CBOB to 

which a blender adds blendstocks. 

(e) Compliance period. (1) For 2007, 

the compliance period is [DATE 60 

DAYS AFTER PUBLICATION OF THE 

FINAL RULE IN THE FEDERAL 

REGISTER] through December 31, 2007. 

(2) Beginning in 2008, and every year 

thereafter, the compliance period is 

January 1 through December 31. 

§§ 80.1108–80.1114 [Added and Reserved] 

6. Sections 80.1108 through 80.1114 

are added and reserved. 

7. Section 80.1115 is added to read as 

follows: 

§ 80.1115 How are equivalence values 

assigned by renewable fuel producers? 

(a) Each gallon of a renewable fuel 

shall be assigned an equivalence value. 

The equivalence value is a number 

assigned to every renewable fuel that is 

used to determine how many gallonRINs can be generated for a batch of 

renewable fuel according to § 80.1126. 

Equivalence Values for certain 

renewable fuels are assigned in 

paragraph (d) of this section. For other 

renewable fuels, the equivalence value 

shall be calculated using the following 

formula: 

EV = (R / 0.931) * (EC / 77,550) 

Where: 

EV = Equivalence Value for the renewable 

fuel. 

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, of the 

renewable fuel that comes from a 

renewable feedstock. 

EC = Energy content of the renewable fuel, 

in Btu per gallon (lower heating value). 

(b) Technical justification and 

approval of calculation of the 

Equivalence Value. 

(1) Producers of renewable fuels must 

prepare a technical justification of the 

calculation of the Equivalence Value for 

the renewable fuel including a 

description of the renewable fuel, its 

feedstock and production process. 

(2) Producers shall submit the 

justification to the EPA for approval. 

(3) The Agency will review the 

technical justification and assign an 

appropriate Equivalence Value to the 

renewable fuel based on the procedure 

in paragraph (c) of this section. 

(c) The equivalence value is assigned 

as follows: 

(1) A value rounded to the nearest 

tenth if such value is less than 0.9. 

(2) 1.0 if the calculated equivalence 

value is in the range of 0.9 to 1.2. 

(3) 1.3, 1.5, or 1.7, for calculated 

values over 1.2, whichever value is 

closest to the calculated equivalence 

value, based on the positive difference 

between the calculated equivalence 

value and each of these three values, 

except as specified in paragraphs (c)(4) 

and (c)(5) of this section. 

(4) 2.5 for cellulosic biomass ethanol 

that is produced on or before December 

31, 2012. 

(5) 2.5 for waste derived ethanol. 

(d) Equivalence values for some 

renewable fuels are as given in the 

following table: 

TABLE 1 OF § 80.1115.—EQUIVALENCE

VALUES FOR SOME RENEWABLE FUELS

Renewable fuel type 

Equivalence 

value 

(EV) 

Cellulosic biomass ethanol and 

waste derived ethanol produced 

on or before December 31, 

2012 .......................................... 2.5 

Ethanol from corn, starches, or 

sugar ......................................... 1.0 

Biodiesel (mono-alkyl ester) ......... 1.5 

Non-ester renewable diesel .......... 1.7 

Butanol .......................................... 1.3 

ETBE from corn ethanol ............... 0.4 

§§ 80.1116—80.1124 [Added and 

Reserved] 

8. Sections 80.1116 through 80.1124 

are added and reserved. 

9. Sections 80.1125 through 80.1131 

are added to read as follows: 

§ 80.1125 Renewable Identification 

Numbers (RINs). 

Each RIN is a 34 character numerical 

code of the following form: 

YYYYCCCCFFFFFBBBBBRRDKSSSSSS

EEEEEE 

(a) YYYY is the calendar year in 

which the batch of renewable fuel was 

produced or imported. YYYY also 

represents the year in which the RIN 

was originally generated. 

(b) CCCC is the registration number 

assigned according to § 80.1150 to the 

producer or importer of the batch of 

renewable fuel. 

(c) FFFFF is the registration number 

assigned according to § 80.1150 to the 

facility at which the batch of renewable 

fuel was produced or imported. 

(d) BBBBB is a serial number assigned 

to the batch which: 

(1) Is chosen by the producer or 

importer of the batch such that no two 

batches have the same value in a given 

calendar year; 

(2) Begins with the value 00001 for 

the first batch produced or imported by 

a facility in a given calendar year; and 

(3) Increases sequentially for 

subsequent batches produced or 

imported by that facility in that calendar 

year. 

(e) RR is a number representing the 

equivalence value of the renewable fuel. 

(1) Equivalence values are specified in 

§ 80.1115. 

(2) Multiply the equivalence value by 

10 to produce the value for RR. 

(f) D is a number identifying the type 

of renewable fuel, as follows: 

(1) D has the value of 1 if the 

renewable fuel can be categorized as 

cellulosic biomass ethanol. 


jlentini on PROD1PC65 with PROPOSAL2
55640 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

(2) D has the value of 2 if the 

renewable fuel cannot be categorized as 

cellulosic biomass ethanol. 

(g) K is a number identifying the type 

of RIN as follows: 

(1) K has the value of 1 if the batchRIN is a standard-value RIN. 

(2) K has the value of 2 if the batchRIN is an extra-value RIN. 

(h) SSSSSS is a number representing 

the first gallon associated with a batch 

of renewable fuel. 

(i) EEEEEE is a number representing 

the last gallon associated with a batch 

of renewable fuel. EEEEEE will be 

identical to SSSSSS in the case of a 

gallon-RIN. Assign the value of EEEEEE 

as described in § 80.1126. 

§ 80.1126 How are RINs assigned to 

batches of renewable fuel by renewable fuel 

producers or importers? 

(a) Regional applicability. (1) Except 

as provided in paragraph (b) of this 

section, every batch of renewable fuel 

produced by a facility located in the 

contiguous 48 states of the United 

States, or imported into the contiguous 

48 states, must be assigned a RIN. 

(2) If the Administrator approves a 

petition of Alaska, Hawaii, or a United 

States territory to opt-in to the 

renewable fuel program under the 

provisions in § 80.1143, then the 

requirements of paragraph (a)(1) of this 

section shall also apply to renewable 

fuel produced or imported into that 

state or territory beginning in the next 

calendar year. 

(b) Volume threshold. Pursuant to 

§ 80.1154, producers with renewable 

fuel production facilities located within 

the United States that produce less than 

10,000 gallons of renewable fuel each 

year, and importers that import less 

than 10,000 gallons of renewable fuel 

each year, are not required to generate 

and assign RINs to batches of renewable 

fuel. Such producers and importers are 

also exempt from the registration, 

reporting, and recordkeeping 

requirements of §§ 80.1150 through 

80.1152. However, for those producers 

and importers that voluntarily generate 

and assign RINs, all the requirements of 

this subpart apply. 

(c) Generation of RINs. (1) The 

producer or importer of a batch of 

renewable fuel must generate the RINs 

associated with that batch. However, a 

producer of a batch of renewable fuel for 

export is not required to generate a RIN 

for that batch if that producer is also the 

exporter and exports the renewable fuel. 

(2) A party generating a RIN shall 

specify the appropriate numerical 

values for each component of the RIN in 

accordance with the provisions of 

§ 80.1125 and this paragraph (c). 

(3) Standard-value RINs shall be 

generated separately from extra-value 

RINs, and distinguished from one 

another by the K component of the RIN. 

(4) When a standard-value batch-RIN 

or an extra-value batch-RIN is initially 

generated by a renewable fuel producer 

or importer, the value of SSSSSS in the 

batch-RIN shall be 000001 to represent 

the first gallon in the batch of renewable 

fuel. 

(5) Generation of standard-value 

batch-RINs. (i) Except as provided in 

paragraph (c)(5)(ii) of this section, a 

standard-value batch-RIN shall be 

generated to represent the gallons in a 

batch of renewable fuel. The value of 

EEEEEE when a batch-RIN is initially 

generated by a renewable fuel producer 

or importer shall be determined as 

follows: 

(A) For renewable fuels with an 

equivalence value of 1.0 or greater, the 

value of EEEEEE shall be the 

standardized volume of the batch in 

gallons. 

(B) For renewable fuels with an 

equivalence value of less than 1.0, the 

value of EEEEEE shall be the applicable 

volume, in gallons, calculated according 

to the following formula: 

Va = EV * Vs

Where: 

Va = Applicable volume of renewable fuel, in 

gallons, for use in designating the value 

of EEEEEE. 

EV = Equivalence value for the renewable 

fuel per § 80.1115. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons. 

(ii) For biocrude-based renewable 

fuels, a standard-value batch-RIN shall 

be generated to represent the gallons of 

biocrude rather than the gallons of 

renewable fuel. The value of EEEEEE 

shall be the standardized volume of the 

biocrude in gallons. 

(6) Generation of extra-value batchRINs. (i) Extra-value batch-RINs may be 

generated for renewable fuels having an 

equivalence value greater than 1.0. 

(ii) The value for EEEEEE in an extravalue batch-RIN when a batch-RIN is 

initially generated by a renewable fuel 

producer or importer shall be the 

applicable volume of renewable fuel 

calculated according to the following 

formula: 

Va = (EV¥1.0) * Vs

Where: 

Va = Applicable volume of renewable fuel, in 

gallons, for use in designating the value 

of EEEEEE. 

EV= Equivalence value for the renewable fuel 

per § 80.1115. 

Vs = Standardized volume of the batch of 

renewable fuel at 60 °F, in gallons. 

(7) Standardization of volumes. In 

determining the standardized volume of 

a batch of renewable fuel for purposes 

of generating standard-value batch-RINs 

or extra-value batch-RINs, pursuant to 

paragraphs (c)(5) and (c)(6) of this 

section, the batch volumes shall be 

adjusted to a standard temperature of 60 

°F. 

(i) For ethanol, the following formula 

shall be used: 

Vs,e = Va,e * (¥0.0006301 × T + 1.0378) 

Where: 

Vs,e = Standardized volume of ethanol at 60 

°F, in gallons. 

Va,e = Actual volume of ethanol, in gallons. 

T = Actual temperature of the batch, in °F. 

(ii) For biodiesel (mono alkyl esters), 

the following formula shall be used: 

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

Where: 

Vs,b = Standardized volume of biodiesel at 60 

°F, in gallons. 

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

T = Actual temperature of the batch, in °F. 

(iii) For other renewable fuels, an 

appropriate formula commonly 

accepted by the industry shall be used 

to standardize the actual volume to 60 

°F. 

(d) Assignment of batch-RINs to 

batches. (1) The producer or importer of 

a batch of renewable fuel must assign 

standard-value RINs to the batch of 

renewable fuel that those batch-RINs 

represent. 

(2) The producer or importer of a 

batch of renewable fuel may assign 

extra-value batch-RINs to the batch of 

renewable fuel that those batch-RINs 

represent. 

(3) A batch-RIN is assigned to a batch 

when the batch-RIN is recorded in a 

prominent location on a product 

transfer document assigned to that batch 

of renewable fuel per § 80.1153. 

§ 80.1127 How are RINs used to 

demonstrate compliance? 

(a) Renewable volume obligations. (1) 

Except as specified in paragraph (b) of 

this section, each party that is obligated 

to meet the Renewable Volume 

Obligation under § 80.1107, or an 

exporter of renewable fuels, must 

demonstrate that it has acquired 

sufficient RINs to satisfy the following 

equation: 

(SRINVOL)i + (SRINVOL)i–1 = RVOi

Where: 

(SRINVOL)i = Sum of all acquired gallonRINs that were generated in year i and 

are being applied towards the RVOi, in 

gallons. 

(SRINVOL)i–1 = Sum of all acquired gallonRINs that were generated in year i–1 and 

are being applied towards the RVOi, in 

gallons. 


jlentini on PROD1PC65 with PROPOSAL2
Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55641 

RVOi = The Renewable Volume Obligation 

for the obligated party or renewable fuel 

exporter for calendar year i, in gallons. 

(2) For compliance for calendar years 

2009 and later, the value of 

(SRINVOL)i–1 may not exceed a value 

determined by the following inequality: 

(SRINVOL)i–1 ≤ 0.20 * RVOi

Where: 

(SRINVOL)i–1 = Sum of all acquired gallonRINs that were generated in year i–1 and 

are being applied towards the RVOi, in 

gallons. 

(3) RINs may only be used to 

demonstrate compliance with the RVO 

for the calendar year in which they were 

generated or the following calendar 

year. RINs used to demonstrate 

compliance in one year cannot be used 

to demonstrate compliance in any other 

year. 

(4) A party may acquire a RIN only if 

that RIN is obtained in accordance with 

§§ 80.1128 and 80.1129. 

(5) Gallon-RINs that can be used for 

compliance with the RVO shall be 

calculated from the following formula: 

RINVOL = EEEEEE ¥ SSSSSS + 1 

Where: 

RINVOL = Gallon-RINs associated with a 

batch-RIN, in gallons. 

EEEEEE = Batch-RIN component identifying 

the last gallon associated with the batch 

of renewable fuel that the batch-RIN 

represents. 

SSSSSS = Batch-RIN component identifying 

the first gallon associated with the batch 

of renewable fuel that the batch-RIN 

represents. 

(b) Deficit carryovers. (1) An obligated 

party or an exporter of renewable fuel 

that fails to meet the requirements of 

paragraph (a)(1) 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. 

(ii) The party subsequently meets the 

requirements of paragraph (a)(1) of this 

section for calendar year i+1. 

(2) A deficit is calculated according to 

the following formula: 

Di = RVOi ¥ [(ΣRINVOL)i + 

(ΣRINVOL)i¥1] 

Where: 

Di = The deficit generated in calendar year 

i that must be carried over to year i+1 if 

allowed pursuant to paragraph (b)(1)(i) of 

this section, in gallons. 

RVOi = The Renewable Volume Obligation 

for the obligated party or renewable fuel 

exporter for calendar year i, in gallons. 

(ΣRINVOL)1 = Sum of all acquired gallonRINs that were generated in year i and 

are being applied towards the RVOi, in 

gallons. 

(ΣRINVOL)i¥1 = Sum of all acquired gallonRINs that were generated in year i¥1 

and are being applied towards the RVOi, 

in gallons. 

§ 80.1128 General requirements for RIN 

distribution. 

(a) RINs assigned to batches of 

renewable fuel. (1) Except as provided 

in § 80.1129 and paragraph (a)(3) of this 

section, as title to a batch of renewable 

fuel is transferred from one party to 

another, a batch-RIN that has been 

assigned to that batch according to 

§ 80.1126(d) must remain assigned to an 

equivalent renewable fuel volume 

having the same equivalence value. 

(i) A batch-RIN assigned to a batch 

shall be identified on product transfer 

documents representing the batch 

pursuant to § 80.1153. 

(ii) Any documentation used to 

transfer custody of or title to a batch 

from one party to another must identify 

the batch-RINs assigned to that batch. 

(2) If two or more batches of 

renewable fuel are combined into a 

single batch, then all the batch-RINs 

assigned to all the batches involved in 

the merger shall be assigned to the final 

combined batch. 

(3) If a batch of renewable fuel is split 

into two or more smaller batches, any 

batch-RINs assigned to the parent batch 

must likewise be split and assigned to 

the daughter batches. 

(i) If the Equivalence Value for the 

renewable fuel in the parent batch is 

equal to or greater than 1.0, then there 

shall be at least one gallon-RIN for every 

gallon in each of the daughter batches. 

(ii) If the Equivalence Value for the 

renewable fuel in the parent batch is 

less than 1.0, then the ratio of gallonRINs to gallons in the parent batch shall 

be preserved in all daughter batches. 

(iii) For purposes of this paragraph 

(a)(3), the volume of each parent and 

daughter batch shall be standardized to 

60 °F pursuant to § 80.1126(c)(7). 

(b) RINs not assigned to batches of 

renewable fuel. (1) Unassigned RIN 

means one of the following: 

(i) It is a RIN that contains a K value 

identifying it as an extra-value RIN and 

was not assigned to a batch of renewable 

fuel by the producer or importer of that 

batch; or 

(ii) It is a RIN that was separated from 

the batch to which it was assigned in 

accordance with § 80.1129. 

(2) Any party that has registered 

pursuant to § 80.1150 can hold title to 

an unassigned RIN. 

(3) Unassigned RINs can be 

transferred from one party to another 

any number of times. 

(4) An unassigned batch-RIN can be 

divided by its holder into two batchRINs, each representing a smaller 

number of gallon-RINs if all of the 

following conditions are met: 

(i) All RIN components other than 

SSSSSS and EEEEEE are identical for 

the parent and daughter RINs. 

(ii) The sum of the gallon-RINs 

associated with the two daughter batchRINs is equal to the gallon-RINs 

associated with the parent batch. 

§ 80.1129 Requirements for separating 

RINs from batches. 

(a)(1) Separation of a RIN from a batch 

means termination of the assignment of 

the RIN from a batch of renewable fuel. 

(2) A RIN that has been assigned to a 

batch of renewable fuel according to 

§ 80.1126(d) may be separated from a 

batch only under one of the following 

conditions: 

(i) A party that is an obligated party 

according to § 80.1106 may separate any 

RINs that have been assigned to a batch 

if they own the batch. 

(ii) Except as provided in paragraph 

(a)(2)(v) of this section, any party that 

owns a batch of renewable fuel shall 

have the right to separate any RINs that 

have been assigned to that batch once 

the batch is blended with gasoline or 

diesel to produce a motor vehicle fuel. 

(iii) Any party that exports a batch of 

renewable fuel shall have the right to 

separate any RINs that have been 

assigned to the exported batch. 

(iv) Except as provided in paragraph 

(a)(2)(v) of this section, any renewable 

fuel producer that owns a batch of 

renewable fuel shall have the right to 

separate any RINs that have been 

assigned to that batch if the renewable 

fuel is designated as motor vehicle fuel 

in its neat form and is used as motor 

vehicle fuel in its neat form. 

(v) RINs assigned to batches of 

biodiesel (mono-alkyl esters) can only 

be separated from those batches once 

the biodiesel is blended into diesel fuel 

at a concentration of 80 volume percent 

biodiesel or less. 

(b) Upon separation from its 

associated batch, a RIN shall be 

removed from all documentation that: 

(1) Is used to identify custody or title 

to the batch; or 

(2) Is transferred with the batch. 

(c) RINs that have been separated 

from batches of renewable fuel become 

unassigned RINs subject to the 

provisions of § 80.1128(b). 

§ 80.1130 Requirements for exporters of 

renewable fuels. 

(a)(1) Any party that exports any 

amount of renewable fuel shall acquire 

sufficient RINs to offset a Renewable 

Volume Obligation representing the 

exported renewable fuel. 


jlentini on PROD1PC65 with PROPOSAL2
55642 Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 

(2) Only exporters located in the 

applicable region described in 

§ 80.1126(a) are subject to the 

requirements of this section. 

(b) Renewable Volume Obligations. 

An exporter of renewable fuel shall 

determine its Renewable Volume 

Obligation from the volumes of the 

batches exported. 

(1) A renewable fuel exporter’s total 

Renewable Volume Obligation shall be 

calculated according to the following 

formula: 

RVOi = Σ(VOLk * EVk) + Di¥1

Where: 

k = Batch. 

RVOi = The Renewable Volume Obligation 

for the exporter for calendar year i, in 

gallons of renewable fuel. 

VOLk = The standardized volume of batch k 

of exported renewable fuel, in gallons. 

EVk = The equivalence value for batch k. 

Di¥1 = Renewable fuel deficit carryover from 

the previous year, in gallons. 

(2)(i) For exported batches of 

renewable fuel that have assigned RINs, 

the equivalence value may be 

determined from the RR component of 

the RIN. 

(ii) If a batch of renewable fuel does 

not have assigned RINs but its 

equivalence value may nevertheless be 

determined pursuant to § 80.1115(d) 

based on its composition, then the 

appropriate equivalence value shall be 

used in the calculation of the exporter’s 

Renewable Volume Obligation. 

(iii) If the equivalence value for a 

batch of renewable fuel cannot be 

determined, the value of EVk shall be 

1.0. 

(3) If the exporter of a batch of 

renewable fuel is also the producer of 

that batch, and no RIN was generated to 

represent that batch, then the volume of 

that batch shall be excluded from the 

calculation of the Renewable Volume 

Obligation. 

(c) Each exporter of renewable fuel 

must demonstrate compliance with its 

RVO using RINs it has acquired 

pursuant to § 80.1127. 

§ 80.1131 Treatment of invalid RINs. 

(a) Invalid RINs. An invalid RIN is a 

RIN that: 

(1) Is a duplicate of a valid RIN; 

(2) Was based on volumes that have 

not been standardized to 60 °F; 

(3) Has expired; 

(4) Was based on an incorrect 

equivalence value; or 

(5) Was otherwise improperly 

generated. 

(b) In the case of RINs that have been 

determined to be invalid, the following 

provisions apply: 

(1) Invalid RINs cannot be used to 

achieve compliance with the 

transferee’s Renewable Volume 

Obligation, regardless of the transferee’s 

good faith belief that the RINs were 

valid. 

(2) The refiner or importer who used 

the invalid RINs, and any transferor of 

the invalid RINs, must adjust their 

records, reports, and compliance 

calculations as necessary to reflect the 

deletion of invalid RINs. 

(3) Any valid RINs remaining after 

deleting invalid RINs, and after an 

obligated party applies valid RINs as 

needed to meet the RVO at the end of 

the compliance year, must first be 

applied to correct the invalid transfers 

before the transferor trades or banks the 

RINs. 

(4) In the event that the same RIN is 

transferred to two or more parties, the 

RIN will be deemed to be invalid, and 

any party to any transfer of the invalid 

RIN will be deemed liable for any 

violations arising from the transfer or 

use of the invalid RIN. 

(5) A RIN will not be deemed invalid 

where it can be determined that the RIN 

was properly created and transferred. 

§§ 80.1132–80.1140 [Added and Reserved] 

10. Sections 80.1132 through 80.1140 

are added and reserved. 

11. Sections 80.1141 through 80.1143 

are added to read as follows: 

§ 80.1141 Small refinery exemption. 

(a)(1) Pursuant to § 80.1107(d), 

gasoline produced by a refiner at a small 

refinery is qualified for an exemption 

from the renewable fuels standards of 

§ 80.1105 if that refinery meets the 

definition of a small refinery under 

§ 80.1101(i) for calendar year 2004. 

(2) This exemption shall apply 

through December 31, 2010, unless a 

refiner chooses to opt-in to the program 

requirements of this subpart (per 

paragraph (g) of this section) prior to 

this date. 

(b)(1) To apply for an exemption 

under this section, a refiner must submit 

an application to EPA containing the 

following information: 

(i) The annual average aggregate daily 

crude oil throughput for the period 

January 1, 2004, through December 31, 

2004 (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 application is true to the best of his/ 

her knowledge, and that the company 

owned the refinery as of January 1, 

2006; and 

(iii) Name, address, phone number, 

facsimile number, and E-mail address of 

a corporate contact person. 

(2) Applications must be submitted by 

September 1, 2007. 

(c) Within 60 days of EPA’s receipt of 

a refiner’s application for a small 

refinery exemption, EPA will notify the 

refiner if the exemption is not approved 

or of any deficiencies in the application. 

In the absence of such notification from 

EPA, the effective date of the small 

refinery exemption is 60 days from 

EPA’s receipt of the refiner’s 

submission. 

(d) If EPA finds that a refiner 

provided false or inaccurate information 

on its application for a small refinery 

exemption, the exemption will be void 

ab initio upon notice from EPA. 

(e) If a refiner is complying on an 

aggregate basis for multiple refineries, 

any such refiner may exclude from the 

calculation of its Renewable Volume 

Obligation (under § 80.1107(a)) gasoline 

from any refinery receiving the small 

refinery exemption under paragraph (a) 

of this section. 

(f)(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 the small refinery. 

(2) A refiner may at any time petition 

the Administrator for an extension of its 

small refinery exemption under 

paragraph (a) of this section for the 

reason of disproportionate economic 

hardship. 

(3) 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 inability of the refinery to 

produce gasoline meeting the 

requirements of § 80.1105 and the date 

the refiner anticipates that compliance 

with the requirements can be achieved 

at the small refinery. 

(4) The Administrator shall act on 

such a petition not later than 90 days 

after the date of receipt of the petition. 

(g) At any time, a refiner with an 

approved small refinery exemption 

under paragraph (a) of this section may 

waive that exemption upon notification 

to EPA. 

(1) A refiner’s notice to EPA that it 

intends to waive its small refinery 

exemption must be received by 

November 1. 

(2) The waiver will be effective 

beginning on January 1 of the following 

calendar year, at which point the 

gasoline produced at that refinery will 

be subject to the renewable fuels 

standard of § 80.1105. 


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(3) The waiver must be sent to EPA 

at one of the addresses listed in 

paragraph (m) of this section. 

(h) A refiner that acquires a refinery 

from either an approved small refiner 

(under § 80.1142) 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. 

(i) Applications under paragraph (b) 

of this section, petitions for hardship 

extensions under paragraph (f) of this 

section, and small refinery exemption 

waivers under paragraph (g) of this 

section shall be sent to one of the 

following addresses: 

(1) For U.S. mail: U.S. EPA—Attn: 

RFS Program, Transportation and 

Regional Programs Division (6406J), 

1200 Pennsylvania Avenue, NW., 

Washington, DC 20460; or 

(2) For overnight or courier services: 

U.S. EPA, Attn: RFS Program, 

Transportation and Regional Programs 

Division (6406J), 1310 L Street, NW., 6th 

floor, Washington, DC 20005. 

§ 80.1142 What are the provisions for 

small refiners under the RFS program? 

(a)(1) A refiner qualifies for a small 

refiner exemption if the refiner does not 

meet the definition of a small refinery 

under § 80.1101(i) but meets all of the 

following criteria: 

(i) The refiner produced gasoline at 

the refinery by processing crude oil 

through refinery processing units from 

January 1, 2004 through December 31, 

2004. 

(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 2004 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 2004. 

(2) The small refiner exemption shall 

apply through December 31, 2010, 

unless a refiner chooses to opt-in to the 

program requirements of this subpart 

(per paragraph (g) of this section) prior 

to this date. 

(b) To apply for an exemption under 

this section, a refiner must submit an 

application to EPA containing 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; approval of an exemption 

application will be based on all 

information submitted under this 

paragraph and any other relevant 

information: 

(1) (i) A listing of the name and 

address of each company location where 

any employee worked for the period 

January 1, 2004 through December 31, 

2004. 

(ii) The average number of employees 

at each location based on the number of 

employees for each pay period for the 

period January 1, 2004 through 

December 31, 2004. 

(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. 

(2) 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, 2004 

through December 31, 2004. 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. 

(3) A letter signed by the president, 

chief operating or chief executive officer 

of the company, or his/her designee, 

stating that the information contained in 

the application is true to the best of his/ 

her knowledge, and that the company 

owned the refinery as of January 1, 

2006. 

(4) Name, address, phone number, 

facsimile number, and e-mail address of 

a corporate contact person. 

(c) Applications under paragraph (b) 

of this section must be submitted by 

September 1, 2007. EPA will notify a 

refiner of approval or disapproval of its 

small refiner status in writing. 

(d) A refiner who qualifies as a small 

refiner under this section and 

subsequently fails to meet all of the 

qualifying criteria as set out in 

paragraph (a) of this section will have 

its small refiner exemption terminated 

effective January 1 of the next calendar 

year; however, disqualification shall not 

apply in the case of a merger between 

two approved small refiners. 

(e) If EPA finds that a refiner provided 

false or inaccurate information on its 

application for small refiner status 

under this subpart, the small refiner’s 

exemption will be void ab initio upon 

notice from EPA. 

(f) If a small refiner is complying on 

an aggregate basis for multiple 

refineries, the refiner may exclude those 

refineries from the compliance 

calculations under § 80.1125. 

(g) (1) An approved small refiner may, 

at any time, waive the exemption under 

paragraph (a) of this section upon 

notification to EPA. 

(2) An approved small refiner’s notice 

to EPA that it intends to waive the 

exemption under paragraph (a) of this 

section must be received by November 

1 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 fuels standard 

of § 80.1105. 

(3) The waiver must be sent to EPA 

at one of the addresses listed in 

paragraph (i) of this section. 

(h) A 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. 

(i) Applications under paragraph (b) 

of this section shall be sent to one of the 

following addresses: 

(1) For U.S. Mail: U.S. EPA—Attn: 

RFS Program, Transportation and 

Regional Programs Division (6406J), 

1200 Pennsylvania Avenue, NW., 

Washington, DC 20460; or 

(2) For overnight or courier services: 

U.S. EPA, Attn: RFS Program, 

Transportation and Regional Programs 

Division (6406J), 1310 L Street, NW., 6th 

floor, Washington, DC 20005. 

§ 80.1143 What are the opt-in provisions 

for noncontiguous states and territories? 

(a) A noncontiguous state or United 

States territory may petition the 

Administrator to opt-in to the program 

requirements of this subpart. 

(b) The petition must be signed by the 

Governor of the state or his authorized 

representative (or the equivalent official 

of the territory). 

(c) The Administrator will approve 

the petition if it meets the provisions of 

paragraphs (b) and (d) of this section. 

(d)(1) A petition submitted under this 

section must be received by the Agency 

by October 31 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 one of the 

following addresses: 

(i) For U.S. Mail: U.S. EPA–Attn: RFS 

Program, Transportation and Regional 

Programs Division (6406J), 1200 

Pennsylvania Avenue, NW., 

Washington, DC 20460; or 

(ii) For overnight or courier services: 

U.S. EPA, Attn: RFS Program, 

Transportation and Regional Programs 


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Division (6406J), 1310 L Street, NW., 6th 

floor, Washington, DC 20005. 

(e) Upon approval of the petition by 

the Administrator—

(1) EPA shall calculate the standard 

for the following year, including the 

total gasoline volume for the state or 

territory in question. 

(2) Beginning on January 1 of the next 

calendar year, all gasoline producers in 

the state or territory for which a petition 

has been approved shall be obligated 

parties as defined in § 80.1106. 

(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 § 80.1126(a)(2), be 

required to generate RINs and assign 

them to batches of renewable fuel. 

§§ 80.1144–80.1149 [Added and Reserved] 

12. Sections 80.1144 through 80.1149 

are added and reserved. 

13. Sections 80.1150 through 80.1154 

are added to read as follows: 

§ 80.1150 What are the registration 

requirements under the RFS program? 

(a)(1) Any obligated party as defined 

in § 80.1106 and any exporter of 

renewable fuel that is subject to a 

renewable fuels standard under this 

subpart, as of [DATE 60 DAYS AFTER 

PUBLICATION OF THE FINAL RULE 

IN THE FEDERAL REGISTER], 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. In addition, for each import 

facility, the same identifying 

information as required for each refinery 

under § 80.76(c) must be provided. 

Registrations must be submitted by no 

later than [DATE 90 DAYS AFTER 

PUBLICATION OF THE FINAL RULE 

IN THE FEDERAL REGISTER]. 

(2) Any obligated party, as defined in 

§ 80.1106, or any exporter of renewable 

fuel that becomes subject to a renewable 

fuels standard under this subpart after 

the date specified in paragraph (a)(1) of 

this section, must provide EPA the 

information specified for registration 

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 engaging 

in any transaction involving RINs. 

Additionally, for each import facility, 

the same identifying information as 

required for each refinery under 

§ 80.76(c) must be provided. 

(b)(1) Any producer of a renewable 

fuel that is subject to a renewable fuels 

standard under this subpart as of [DATE 

60 DAYS AFTER PUBLICATION OF 

THE FINAL RULE IN THE FEDERAL 

REGISTER], must provide EPA the 

information specified under § 80.76, if 

such information has not already been 

provided under the provisions of this 

part, by no later than [DATE 90 DAYS 

AFTER PUBLICATION OF THE FINAL 

RULE IN THE FEDERAL REGISTER] . 

(2) Any producer of renewable fuel 

that becomes subject to a renewable 

fuels standard under this subpart after 

the date specified in paragraph (b)(1) of 

this section, must provide EPA the 

information specified for registration 

under § 80.76, if such information has 

not already been provided under the 

provisions of this part, and must receive 

EPA-issued company and facility 

identification numbers prior to 

generating or creating any RINs. 

(c) Any party not covered by 

paragraphs (a) and (b) 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 EPA-issued 

company and facility identification 

numbers prior to owning any RINs. 

(d) Registration shall be on forms, and 

following policies, established by the 

Administrator. 

§ 80.1151 What are the recordkeeping 

requirements under the RFS program? 

(a) Beginning with [DATE 60 DAYS 

AFTER PUBLICATION OF THE FINAL 

RULE IN THE FEDERAL REGISTER], 

any obligated party as defined under 

§ 80.1106 or exporter of renewable fuel 

that is subject to the renewable fuels 

standard under § 80.1105 must keep all 

the following records: 

(1) The applicable product transfer 

documents under § 80.1153. 

(2) Copies of all reports submitted to 

EPA under § 80.1152(a). 

(3) Records related to each transaction 

involving the sale, purchase, brokering, 

and trading of RINs, which includes all 

the following: 

(i) A list of the RINs owned or 

transferred. 

(ii) The parties involved in each 

transaction including the transferor, 

transferee, and any broker or agent. 

(iii) The location, time, and date of 

the transfer of the RIN(s). 

(iv) Additional information related to 

details of the transaction and its terms. 

(4) Records related to the use of RINs, 

by facility, for compliance, which 

includes all the following: 

(i) Methods and variables used to 

calculate the Renewable Volume 

Obligation pursuant to § 80.1107. 

(ii) List of RINs surrendered to EPA 

used to demonstrate compliance. 

(iii) Additional information related to 

details of RIN use for compliance. 

(5) Verifiable records of all the 

following: 

(i) The amount and type of fossil fuel 

and waste material-derived fuel used in 

producing on-site thermal energy 

dedicated to the production of ethanol 

at plants producing cellulosic ethanol as 

defined in § 80.1101(a)(2). 

(ii) The equivalent amount of fossil 

fuel (based on reasonable estimates) 

associated with the use of off-site 

generated waste heat that is used in the 

production of ethanol at plants 

producing cellulosic ethanol as defined 

in § 80.1101(a)(2). 

(b) Beginning with [DATE 60 DAYS 

AFTER PUBLICATION OF THE FINAL 

RULE IN THE FEDERAL REGISTER], 

any importer or producer of renewable 

fuel as defined under § 80.1101(e) must 

keep all the following records: 

(1) The applicable product transfer 

documents under § 80.1153. 

(2) Copies of all reports submitted to 

EPA under § 80.1152(b). 

(3) Records related to the generation 

of RINs, for each facility, including all 

of the following: 

(i) Batch Volume. 

(ii) RIN number as assigned under 

§ 80.1126. 

(iii) Identification of those batches 

meeting the definition of cellulosic 

biomass ethanol. 

(iv) Date of production or import. 

(v) Results of any laboratory analysis 

of batch chemical composition or 

physical properties. 

(vi) Additional information related to 

details of RIN generation. 

(4) Records related to each transaction 

involving the sale, purchase, brokering, 

and trading of RINs, including all of the 

following: 

(i) A list of the RINs acquired, owned 

or transferred. 

(ii) The parties involved in each 

transaction including the transferor, 

transferee, and any broker or agent. 

(iii) The location, time, and date of 

the transfer of the RIN(s). 

(iv) Additional information related to 

details of the transaction and its terms. 

(c) Beginning with [DATE 60 DAYS 

AFTER PUBLICATION OF THE FINAL 

RULE IN THE FEDERAL REGISTER], 

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) The applicable product transfer 

documents under § 80.1153. 

(2) Copies of all reports submitted to 

EPA under § 80.1152(c). 

(3) Records related to each transaction 

involving the sale, purchase, brokering, 

and trading of RINs, including all of the 

following: 

(i) A list of the RINs acquired, owned, 

or transferred. 


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(ii) The parties involved in each 

transaction including the transferor, 

transferee, and any broker or agent. 

(iii) The location, time, and date of 

the transfer of the RIN(s). 

(iv) Additional information related to 

details of the transaction and its terms. 

(d) The records required under this 

section and under § 80.1153 shall be 

kept for five years from the date they 

were created, except that records related 

to transactions involving RINs shall be 

kept for five years from the date of 

transfer. 

(e) On request by EPA, the records 

required under this section and under 

§ 80.1153 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 which shall be 

provided to the Administrator’s 

authorized representative. 

§ 80.1152 What are the reporting 

requirements under the RFS program? 

(a) Beginning with [DATE 60 DAYS 

AFTER PUBLICATION OF THE FINAL 

RULE IN THE FEDERAL REGISTER], 

any obligated party as defined in 

§ 80.1106 or exporter of renewable fuel 

that is subject to the renewable fuels 

standard under § 80.1105, and 

continuing for each year thereafter, must 

submit to EPA annual reports that 

contain the information required in this 

section and such other information as 

EPA may require: 

(1) A summary report of the annual 

gasoline volume produced or imported, 

or volume of renewable fuel exported, 

and whether the party is complying on 

a corporate (aggregate) or facility-byfacility basis. This report shall include 

all of the following: 

(i) The obligated party’s name. 

(ii) The EPA company registration 

number. 

(iii) The EPA facility registration 

number(s). 

(iv) The production volume of 

finished gasoline, RBOB as defined in 

§ 80.1107(c) and CBOB as defined in 

§ 80.1107(c). 

(v) The renewable volume obligation 

(RVO), as defined in § 80.1127(a) for 

obligated parties and § 80.1130 for 

exporters of renewable fuel, for the 

reporting year. 

(vi) Any deficit RVO carried over from 

the previous year. 

(vii) Any deficit RVO carried into the 

subsequent year. 

(viii) The total number of RINs used 

for compliance. 

(ix) A list of all RINs used for 

compliance. 

(x) Any additional information that 

the Administrator may require. 

(2) A report documenting each 

transaction of RINs traded between two 

parties, shall include all of the 

following: 

(i) The submitting party’s name. 

(ii) The submitter’s EPA company 

registration number. 

(iii) The submitter’s EPA facility 

registration number(s). 

(iv) The compliance period, 

(v) Transaction type (e.g. purchase, 

sale). 

(vi) Transaction date. 

(vii) Trading partner’s name. 

(viii) Trading partner’s EPA company 

registration number. 

(ix) Trading partner’s EPA facility 

registration number. 

(x) RINs traded. 

(xi) Any additional information that 

the Administrator may require. 

(3) A report that summarizes RIN 

activities for a given compliance year 

shall include all of the following 

information: 

(i) The total prior-years RINs carried 

over into the current year (on an annual 

basis beginning January 1). 

(ii) The total current-year RINS 

acquired. 

(iii) The total prior-years RINs 

acquired. 

(iv) The total current-year RINs sold. 

(v) The total prior-years RINs sold. 

(vi) The total current-year RINs used. 

(vii) The total prior-years RINs used. 

(viii) The total current-year RINs 

expired. 

(ix) The total prior-years RINs 

expired. 

(x) The total current-year RINs to be 

carried into next year. 

(xi) Any additional information that 

the Administrator may require. 

(4) Reports shall be submitted on 

forms and following procedures as 

prescribed by EPA. 

(5) Reports shall be submitted by 

February 28 for the previous compliance 

year. 

(6) All reports must be signed and 

certified as meeting all the applicable 

requirements of this subpart by the 

owner or a responsible corporate officer 

of the obligated party. 

(b) Beginning with [DATE 60 DAYS 

AFTER PUBLICATION OF THE FINAL 

RULE IN THE FEDERAL REGISTER], 

any producer or importer of a renewable 

fuel that is subject to the renewable 

fuels standard under § 80.1105, and 

continuing for each year thereafter, must 

submit to EPA annual reports that 

contain all of the following information: 

(1) An annual report that includes all 

of the following information on a perbatch basis, where ‘‘batch’’ means a 

discreet quantity of renewable fuel 

produced and assigned a unique RIN: 

(i) The renewable fuel producer’s 

name. 

(ii) The EPA company registration 

number. 

(iii) The EPA facility registration 

number(s). 

(iv) The 34 character RINs generated 

for each batch according to § 80.1126. 

(v) The production date of each batch. 

(vi) The renewable fuel type as 

defined in § 80.1101(f). 

(vii) Information related to the volume 

of denaturant and applicable 

equivalence value. 

(viii) The volume produced. 

(ix) Any additional information the 

Administrator may require. 

(2) A report documenting each 

transaction of RINs traded between two 

parties, shall include all of the following 

information: 

(i) The submitting party’s name. 

(ii) The submitter’s EPA company 

registration number. 

(iii) The submitter’s EPA facility 

registration number(s). 

(iv) The compliance period. 

(v) Transaction type (e.g. purchase, 

sale). 

(vi) Transaction date. 

(vii) Trading partner’s name. 

(viii) Trading partner’s EPA company 

registration number. 

(ix) Trading partner’s EPA facility 

registration number; 

(x) RINs traded. 

(xi) Any additional information the 

Administrator may require. 

(3) A report that summarizes RIN 

activities for a compliance year shall 

include all of the following information: 

(i) The total prior-years RINs carried 

over into the current year (on an annual 

basis beginning January 1). 

(ii) The total current-year RINs 

generated. 

(iii) The total current-year RINS 

acquired. 

(iv) The total prior-years RINs 

acquired. 

(v) The total current-years RINs sold. 

(vi) The total prior-years RINs sold. 

(vii) The total current-years RINs 

expired. 

(viii) The total prior-years RINs 

expired. 

(ix) The total current-year RINs to be 

carried into next year. 

(x) Any additional information the 

Administrator may require. 

(4) Reports shall be submitted on 

forms and following procedures as 

prescribed by EPA. 

(5) Reports shall be submitted by 

February 28 for the previous year. 

(6) All reports must be signed and 

certified as meeting all the applicable 


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requirements of this subpart by the 

owner or a responsible corporate officer 

of the renewable fuel producer. 

(c) Any party, other than those parties 

covered in paragraphs (a) and (b) of this 

section, who owns RINs must submit to 

EPA annual reports that contain all of 

the following information: 

(1) A report documenting each 

transaction of RINs traded between two 

parties shall include all of the following: 

(i) The submitting party’s name. 

(ii) The submitter’s EPA company 

registration number. 

(iii) The submitter’s EPA facility 

registration number(s). 

(iv) The compliance period. 

(v) Transaction type (e.g. purchase, 

sale). 

(vi) Transaction date. 

(vii) Trading partner’s name. 

(viii) Trading partner’s EPA company 

registration number. 

(ix) Trading partner’s EPA facility 

registration number. 

(x) RINs traded. 

(xi) Any additional information the 

Administrator may require. 

(2) A report that summarizes RIN 

activities for a compliance year shall 

include all of the following information: 

(i) The total prior-years RINs carried 

over into the current year (on an annual 

basis beginning January 1). 

(ii) The total current-year RINS 

acquired. 

(iii) The total prior-years RINs 

acquired. 

(iv) The total current-years RINs sold. 

(v) The total prior-years RINs sold. 

(vi) The total current-years RINs 

expired. 

(vii) The total prior-years RINs 

expired. 

(viii) The total current-year RINs to be 

carried into next year. 

(ix) Any additional information the 

Administrator may require. 

(3) Reports shall be submitted on 

forms and following procedures as 

prescribed by EPA. 

(4) Reports shall be submitted by 

February 28 for the previous year. 

(5) All reports 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. 

§ 80.1153 What are the product transfer 

document (PTD) requirements for the RFS 

program? 

(a) Any time that a person transfers 

ownership of renewable fuels subject to 

this subpart, and when RINs continue to 

accompany the renewable fuel, the 

transferor must provide to the transferee 

documents identifying the renewable 

fuel and assigned RINs which include 

all of the following information as 

applicable: 

(1) The name and address of the 

transferor and transferee. 

(2) The transferor’s and transferee’s 

EPA company registration number. 

(3) The transferor’s and transferee’s 

EPA facility registration number. 

(4) The volume of renewable fuel that 

is being transferred. 

(5) The location of the renewable fuel 

at the time of transfer. 

(6) The date of the transfer. 

(7) The RINs assigned to the volume 

of renewable fuel that is being 

transferred. 

(b) Except for transfers to truck 

carriers, retailers or wholesale 

purchaser-consumers, product codes 

may be used to convey the information 

required under paragraphs (a)(1) 

through (a)(4) of this section if such 

codes are clearly understood by each 

transferee. The RIN number required 

under paragraph (a)(7) of this section 

must always appear in its entirety. 

§ 80.1154 What are the provisions for 

renewable fuel producers and importers 

who produce or import less than 10,000 

gallons of renewable fuel per year? 

(a) Renewable fuel production 

facilities located within the United 

States that produce less than 10,000 

gallons of renewable fuel each year, and 

importers who import less than 10,000 

gallons of renewable fuel each year, are 

not required to generate RINs or to 

assign RINs to batches of renewable 

fuel. Such producers and importers that 

do not generate and/or assign RINs to 

batches of renewable fuel are exempt 

from the following requirements of 

subpart K, except as stated in paragraph 

(b) of this section: 

(1) The registration requirements of 

§ 80.1150: 

(2) The recordkeeping requirements of 

§ 80.1151; and 

(3) The reporting requirements of 

§ 80.1152. 

(b) Renewable fuel producers 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 

§§ 80.1150 through 80.1152. 

§§ 80.1155–80.1159 [Added and Reserved] 

14. Sections 80.1155 through 80.1159 

are added and reserved. 

15. Sections 80.1160 through 80.1165 

are added to read as follows: 

§ 80.1160 What acts are prohibited under 

the RFS program? 

(a) Renewable fuels producer or 

importer violation. Except as provided 

in § 80.1154, no person shall produce or 

import a renewable fuel that is not 

assigned the proper RIN value or 

identified by a RIN number as required 

under § 80.1126. 

(b) RIN generation and transfer 

violations. No person shall do any of the 

following: 

(1) Improperly generate a RIN (i.e., 

generate a RIN for which the applicable 

renewable fuel volume was not 

produced). 

(2) Transfer to any person an invalid 

RIN or a RIN that is not properly 

identified as required under § 80.1125. 

(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 party’s 

renewable fuel obligation under 

§ 80.1127. 

(2) Fail to acquire sufficient RINs to 

meet the party’s renewable fuel 

obligation under § 80.1130. 

(d) Causing a violation. No person 

shall cause another person to commit an 

act in violation of any prohibited act 

under this section. 

§ 80.1161 Who is liable for violations 

under the RFS program? 

(a) Persons liable for violations of 

prohibited acts. (1) Any person who 

violates a prohibition under § 80.1160(a) 

through (c) is liable for the violation of 

that prohibition. 

(2) Any person who causes another 

person to violate a prohibition under 

§ 80.1160(a) through (c) is liable for a 

violation of § 80.1160(d). 

(b) Persons liable 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. 

§ 80.1162 [Reserved] 

§ 80.1163 What penalties apply under the 

RFS program? 

(a) Any person who is liable for a 

violation under § 80.1161 is subject a to 

civil penalty of up to $32,500, as 

specified in sections 205 and 211(d) of 

the Clean Air Act, for every day of each 

such violation and the amount of 

economic benefit or savings resulting 

from each violation. 


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(b) Any person liable under 

§ 80.1161(a) for a violation of 

§ 80.1160(c) for failure to meet a 

renewable fuels obligation or causing 

another party to fail to meet a renewable 

fuels obligation during any averaging 

period, is subject to a separate day of 

violation for each day in the averaging 

period. 

(c) Any person liable under 

§ 80.1161(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. 

§ 80.1164 What are the attest engagement 

requirements under the RFS program? 

In addition to the requirements for 

attest engagements under §§ 80.125 

through 80.133, and other applicable 

attest engagement provisions, the 

following annual attest engagement 

procedures are required under this 

subpart. 

(a) The following attest procedures 

shall be completed for any obligated 

party as stated in § 80.1106(b) or 

exporter of renewable fuel that is subject 

to the renewable fuel standard under 

§ 80.1105: 

(1) Annual summary report. (i) Obtain 

and read a copy of the annual summary 

report required under § 80.1152(a)(1) 

which contains information regarding: 

(A) The obligated party’s volume of 

finished gasoline, reformulated gasoline 

blendstock for oxygenate blending 

(RBOB), and conventional gasoline 

blendstock that becomes finished 

conventional gasoline upon the addition 

of oxygenate (CBOB) produced or 

imported during the reporting year; 

(B) Renewable volume obligation 

(RVO); and 

(C) RINs used for compliance. 

(ii) Obtain documentation of any 

volumes of renewable fuel used in 

gasoline during the reporting year; 

compute and report as a finding the 

volumes of renewable fuel represented 

in these documents. 

(iii) Agree the volumes of gasoline 

reported to EPA in the report required 

under § 80.1152(a)(1) with the volumes, 

excluding any renewable fuel volumes, 

contained in the inventory 

reconciliation analysis under § 80.133. 

(iv) Verify that the production volume 

information in the obligated party’s 

annual summary report required under 

§ 80.1152(a)(1) agrees with the volume 

information, excluding any renewable 

fuel volumes, contained in the 

inventory reconciliation analysis under 

§ 80.133. 

(v) Compute and report as a finding 

the obligated party’s RVO, and any 

deficit RVO carried over from the 

previous year or carried into the 

subsequent year, and verify that the 

values agree with the values reported to 

EPA. 

(vi) Obtain documentation for all RINs 

used for compliance during the year 

being reviewed; compute and report as 

a finding the RIN numbers and year of 

generation of RINs represented in these 

documents; and agree with the report to 

EPA. 

(2) RIN transaction report. (i) Obtain 

and read a copy of the RIN transaction 

report required under § 80.1152(a)(2) 

which contains information regarding 

RIN trading transactions. 

(ii) Obtain contracts or other 

documents for all RIN transactions with 

another party during the year being 

reviewed; compute and report as a 

finding the transaction types, 

transaction dates and RINs traded; and 

agree with the report to EPA. 

(3) RIN activity report. (i) Obtain and 

read a copy of the RIN activity report 

required under § 80.1152(a)(3) which 

contains information regarding RIN 

activity for the compliance year. 

(ii) Obtain documentation of all RINs 

acquired, used for compliance 

(including current-year RINs used and 

previous-year RINs used) transferred, 

sold, and expired during the year being 

reviewed; compute and report as a 

finding the total RINs acquired, used for 

compliance, transferred, sold, and 

expired as represented in these 

documents; and agree with the report to 

EPA. 

(b) The following attest procedures 

shall be completed for any renewable 

fuel producer: 

(1) Annual batch report. (i) Obtain 

and read a copy of the annual batch 

report required under § 80.1152(b)(1) 

which contains information regarding 

renewable fuel batches. 

(ii) Obtain production data for each 

renewable fuel batch produced during 

the year being reviewed; compute and 

report as a finding the RIN numbers, 

production dates, types, volumes of 

denaturant and applicable equivalence 

values, and production volumes for 

each batch; and agree with the report to 

EPA. 

(iii) Verify that the proper number of 

RINs were generated for each batch of 

renewable fuel produced, as required 

under § 80.1126. 

(iv) Obtain product transfer 

documents for each renewable fuel 

batch produced during the year being 

reviewed; report as a finding any 

product transfer document that did not 

include the RIN for the batch. 

(2) RIN transaction report. (i) Obtain 

and read a copy of the RIN transaction 

report required under § 80.1152(b)(2) 

which contains information regarding 

RIN trading transactions. 

(ii) Obtain contracts or other 

documents for all RIN transactions with 

another party during the year being 

reviewed; compute and report as a 

finding the transaction types, 

transaction dates, and the RINs traded; 

and agree with the report to EPA. 

(3) RIN activity report. (i) Obtain and 

read a copy of the RIN activity report 

required under § 80.1152(b)(3) which 

contains information regarding RIN 

activity for the compliance year. 

(ii) Obtain documentation of all RINs 

owned (including RINs created and 

acquired), transferred, sold and expired 

during the year being reviewed; 

compute and report as a finding the 

total RINs owned, transferred, sold and 

expired as represented in these 

documents; and agree with the report to 

EPA. 

(c) For each averaging period, 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 each year. 

§ 80.1165 What are the additional 

requirements under this subpart for 

gasoline produced at foreign refineries? 

(a) Definitions. The following 

definitions apply for this section: 

(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) RFS–FRGAS is gasoline produced 

at a foreign refinery that has received a 

small refinery exemption under 

§ 80.1141 or a small refiner exemption 

under § 80.1142 that is imported into 

the United States. 

(4) Non-RFS–FRGAS is one of the 

following: 

(i) Gasoline produced at a foreign 

refinery that has received a small 

refinery exemption under § 80.1141 or a 

small refiner exemption under § 80.1142 

that is not imported into the United 

States. 

(ii) Gasoline produced at a foreign 

refinery that has not received a small 

refinery exemption under § 80.1141 or 

small refiner exemption under 

§ 80.1142. 

(b) General requirements for RFS–

FRGAS foreign small refiners. (1) A 

foreign refiner that has a small refinery 

exemption under § 80.1141 or a small 


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refiner exemption under § 80.1142 must 

designate, at the time of production, 

each batch of gasoline produced at the 

foreign refinery that is exported for use 

in the United States as RFS–FRGAS; 

and 

(2) Meet all requirements that apply to 

refiners who have received a small 

refinery or small refiner exemption 

under this subpart. 

(c) Designation, foreign refiner 

certification, and product transfer 

documents. (1) Any foreign refiner that 

has received a small refinery exemption 

under § 80.1141 or a small refiner 

exemption under § 80.1142 must 

designate each batch of RFS–FRGAS as 

such at the time the gasoline is 

produced. 

(2) On each occasion when RFS–

FRGAS is loaded onto a vessel or other 

transportation mode for transport to the 

United States, the foreign refiner shall 

prepare a certification for each batch of 

RFS–FRGAS that meets the following 

requirements: 

(i) The certification shall include the 

report of the independent third party 

under paragraph (d) of this section, and 

the following additional information: 

(A) The name and EPA registration 

number of the refinery that produced 

the RFS–FRGAS; 

(B) [Reserved] 

(ii) The identification of the gasoline 

as RFS–FRGAS; and, 

(iii) The volume of RFS–FRGAS being 

transported, in gallons. 

(3) On each occasion when any 

person transfers custody or title to any 

RFS–FRGAS prior to its being imported 

into the United States, it must include 

the following information as part of the 

product transfer document information: 

(i) Designation of the gasoline as RFS–

FRGAS; and 

(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–FRGAS is loaded 

onto a vessel for transport to the United 

States the small foreign refiner shall 

have an independent third party: 

(i) Inspect the vessel prior to loading 

and determine the volume of any tank 

bottoms; 

(ii) Determine the volume of RFS–

FRGAS 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–FRGAS to the United 

States; 

(v) Determine the date and time the 

vessel departs the port serving the 

foreign refinery; and 

(vi) Review original documents that 

reflect movement and storage of the 

RFS–FRGAS from the foreign refinery to 

the load port, and from this review 

determine: 

(A) The refinery at which the RFS–

FRGAS was produced; and 

(B) That the RFS–FRGAS remained 

segregated from Non-RFS–FRGAS and 

other RFS–FRGAS produced at a 

different refinery. 

(2) The independent third party shall 

submit a report to: 

(i) The foreign small refiner 

containing the information required 

under paragraph (d)(1) of this section, to 

accompany the product transfer 

documents for the vessel; and 

(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 gasoline was 

produced, assurance that the gasoline 

remained segregated as specified in 

paragraph (i)(1) of this section, and a 

description of the gasoline’s movement 

and storage between production at the 

source refinery 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 small foreign 

refiner and any United States importer 

of RFS–FRGAS 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 (j) of this section, for the 

volume of gasoline, except as specified 

in paragraph (e)(1)(ii) of this section. 

(ii) Where a vessel transporting RFS–

FRGAS off loads this gasoline 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 gasoline or blendstock between the 

first United States port of entry and the 

subsequent port of entry. 

(2) If the temperature-corrected 

volumes determined at the port of entry 

and at the load port differ by more than 

one percent, the United States importer 

shall include the volume of gasoline 

from the importer’s RFS compliance 

calculations. 

(f) Foreign refiner commitments. Any 

small foreign refiner shall commit to 

and comply with the provisions 

contained in this paragraph (f) as a 

condition to being approved for a small 

refinery or small refiner exemption 

under this subpart. 

(1) Any United States Environmental 

Protection Agency inspector or auditor 

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) Gasoline is produced; 

(B) Documents related to refinery 

operations are kept; and 

(C) RFS–FRGAS is stored or 

transported between the foreign refinery 

and the United States, including storage 

tanks, vessels and pipelines. 

(iii) Inspections and audits may be by 

EPA employees or contractors to EPA. 

(iv) Any documents requested that are 

related to matters covered by 

inspections and audits must be 

provided to an EPA inspector or auditor 

on request. 

(v) Inspections and audits by EPA 

may include review and copying of any 

documents related to: 

(A) The volume of RFS–FRGAS; 

(B) The proper classification of 

gasoline as being RFS–FRGAS or as not 

being RFS–FRGAS; 

(C) Transfers of title or custody to 

RFS–FRGAS; 

(D) Testing of RFS–FRGAS; and 

(E) Work performed and reports 

prepared by independent third parties 

and by independent auditors under the 

requirements of this section, including 

work papers. 

(vi) Inspections and audits by EPA 

may include interviewing employees. 

(vii) Any employee of the foreign 

refiner must be made available for 

interview by the EPA inspector or 

auditor, on request, within a reasonable 

time period. 

(viii) English language translations of 

any documents must be provided to an 

EPA inspector or auditor, on request, 

within 10 working days. 

(ix) English language interpreters 

must be provided to accompany EPA 

inspectors and auditors, on request. 


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(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 

gasoline under such exemption, and all 

other actions to comply with the 

requirements of this subpart relating to 

such exemption constitute actions or 

activities covered by and within the 

meaning of the provisions of 28 U.S.C. 

1605(a)(2), but solely with respect to 

actions instituted against the foreign 

refiner, its agents and employees in any 

court or other tribunal in the United 

States for conduct that violates the 

requirements applicable to the foreign 

refiner under this subpart, including 

conduct that violates the False 

Statements Accountability Act of 1996 

(18 U.S.C. 1001) and section 113(c)(2) of 

the Clean Air Act (42 U.S.C. 7413). 

(6) The foreign refiner, or its agents or 

employees, will not seek to detain or to 

impose civil or criminal remedies 

against EPA inspectors or auditors, 

whether EPA employees or EPA 

contractors, for actions performed 

within the scope of EPA employment 

related to the provisions of this section. 

(7) The commitment required by this 

paragraph (f) shall be signed by the 

owner or president of the foreign refiner 

business. 

(8) In any case where RFS–FRGAS 

produced at a foreign refinery is stored 

or transported by another company 

between the refinery and the vessel that 

transports the RFS–FRGAS 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 gasoline 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 

as benzene foreign refiner under this 

subpart. 

(1) The foreign refiner shall post a 

bond of the amount calculated using the 

following equation: 

Bond = G * $ 0.01 

Where: 

Bond = Amount of the bond in United States 

dollars. 

G = The largest volume of gasoline 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 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 gasoline 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 language, or 

shall include an English language 

translation. 

(j) Prohibitions. (1) No person may 

combine RFS–FRGAS with any NonRFS–FRGAS, and no person may 

combine RFS–FRGAS with any RFS–

FRGAS 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–FRGAS shall meet the 

following requirements: 

(1) Each batch of imported RFS–

FRGAS shall be classified by the 

importer as being RFS–FRGAS. 

(2) Gasoline shall be classified as 

RFS–FRGAS 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 gasoline batch classified 

as RFS–FRGAS, any United States 


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importer shall have an independent 

third party: 

(i) Determine the volume of gasoline 

in the vessel; 

(ii) Use the foreign refiner’s RFS–

FRGAS certification to determine the 

name and EPA-assigned registration 

number of the foreign refinery that 

produced the RFS–FRGAS; 

(iii) Determine the name and country 

of registration of the vessel used to 

transport the RFS–FRGAS to the United 

States; and 

(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–FRGAS 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 gasoline that is 

not classified as RFS–FRGAS under 

paragraph (k)(2) of this section. 

(l) Truck imports of RFS–FRGAS 

produced at a foreign refinery. (1) Any 

refiner whose RFS–FRGAS is 

transported into the United States by 

truck may petition EPA to use 

alternative procedures to meet 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; and 

(iii) Importer testing under paragraph 

(k)(3) of this section. 

(2) These alternative procedures must 

ensure RFS–FRGAS remains segregated 

from Non-RFS–FRGAS until it is 

imported into the United States. The 

petition will be evaluated based on 

whether it adequately addresses the 

following: 

(i) Provisions for monitoring pipeline 

shipments, if applicable, from the 

refinery, that ensure segregation of RFS–

FRGAS from that refinery from all other 

gasoline. 

(ii) Contracts with any terminals and/ 

or pipelines that receive and/or 

transport RFS–FRGAS that prohibit the 

commingling of RFS–FRGAS with NonRFS–FRGAS or RFS–FRGAS 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–FRGAS remains 

segregated throughout the distribution 

system. 

(3) The petition required by 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–FRGAS. Importers of 

RFS–FRGAS, for each annual 

compliance period, must arrange to 

have an attest engagement performed of 

the underlying documentation that 

forms the basis of any report or 

document required under this subpart. 

The attest engagement must comply 

with the procedures and requirements 

that apply to importers under §§ 80.125 

through 80.130, and other applicable 

attest engagement provisions, and must 

be submitted to the Administrator of 

EPA by August 31 of each year for the 

prior annual compliance period. The 

following additional procedures shall be 

carried out for any importer of RFS–

FRGAS. 

(1) Obtain listings of all tenders of 

RFS–FRGAS. Agree the total volume of 

tenders from the listings to the gasoline 

inventory reconciliation analysis in 

§ 80.128(b), and to the volumes 

determined by the third party under 

paragraph (d) of this section. 

(2) For each tender under paragraph 

(m)(1) of this section, where the gasoline 

is loaded onto a marine vessel, report as 

a finding the name and country of 

registration of each vessel, and the 

volumes of RFS–FRGAS 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–

FRGAS, in accordance with the 

guidelines in § 80.127, and for each 

vessel selected perform 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 gasoline 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 

foreign refiner adjusted its refinery 

calculations as required in paragraph (e) 

of this section. 

(ii) Obtain the documents used by the 

independent third party to determine 

transportation and storage of the RFS–

FRGAS from the refinery to the load 

port, under paragraph (d) of this section. 

Obtain tank activity records for any 

storage tank where the RFS–FRGAS is 

stored, and pipeline activity records for 

any pipeline used to transport the RFS–

FRGAS prior to being loaded onto the 

vessel. Use these records to determine 

whether the RFS–FRGAS was produced 

at the refinery that is the subject of the 

attest engagement, and whether the 

RFS–FRGAS was mixed with any NonRFS–FRGAS or any RFS–FRGAS 

produced at a different refinery. 

(4) Select a sample from the list of 

vessels identified in paragraph (m)(2) of 

this section used to transport RFS–

FRGAS, 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 separate listings of all 

tenders of RFS–FRGAS, and perform the 

following: 

(i) Agree the volume of tenders from 

the listings to the gasoline inventory 

reconciliation analysis in § 80.128(b). 

(ii) Obtain a separate listing of the 

tenders under this paragraph (m)(5) 

where the gasoline 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 gasoline was off loaded 

for the selected vessels. Determine and 

report as a finding the country where 

the gasoline was off loaded for each 

vessel selected. 

(6) In order to complete the 

requirements of this paragraph (m) an 

auditor shall: 

(i) Be independent of the foreign 

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 80.130 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 


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Federal Register / Vol. 71, No. 184 / Friday, September 22, 2006 / Proposed Rules 55651 

with the requirements of §§ 80.125 

through 80.130 and this paragraph (m). 

(n) Withdrawal or suspension of 

foreign refiner 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 (g) 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) Be 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 [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 K, 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 K, 

including 40 CFR 80.1165 apply to 

[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.’’

[FR Doc. 06–7887 Filed 9–21–06; 8:45 am] 

BILLING CODE 6560–50–P 


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