Draft Regulatory Impact Analysis: 

Changes to Renewable Fuel Standard 

Program 
Draft Regulatory Impact Analysis: 


Changes to Renewable Fuel Standard 


Program
 

Assessment and Standards Division 

Office of Transportation and Air Quality 

U.S. Environmental Protection Agency 

NOTICE 

This technical report does not necessarily represent final EPA decisions or 

positions. It is intended to present technical analysis of issues using data 

that are currently available. The purpose in the release of such reports is to 

facilitate the exchange of technical information and to inform the public of 

technical developments. 

EPA-420-D-09-001 

May 2009 
Table of Contents 

Statement of Need.......................................................................................................iii 

Overview.....................................................................................................................iv
 

List of Acronyms and Abbreviations......................... ...............................................vi 

Chapter 1: Renewable Fuel Production and Consumption........................................11 

Chapter 2: Lifecycle GHG Analysis.........................................................................278 

Chapter 3: Impacts of the Program on Non-GHG Pollutants...................................436 

Chapter 4: Impacts on Cost of Renewable Fuels, Gasoline, and Diesel ..................516 

Chapter 5: Economic Impacts and Benefits..............................................................642 

Chapter 6: Impacts on Water.....................................................................................705 

Chapter 7: Initial Regulatory Flexibility Analysis....................................................733 

Appendix A: Biodiesel Effects on Heavy-Duty Highway Engines and Vehicles.....743 

Endnotes.....................................................................................................................771 

ii 
 

Statement of Need 

The current Renewable Fuel Standard (RFS) program was originally adopted by EPA to 

implement the provisions of the Energy Policy Act of 2005 (EPAct), which added section 211(o) 

to the Clean Air Act (CAA). With the passage of the Energy Independence and Security Act of 

2007 (EISA), Congress recently made several important revisions to these renewable fuel 

requirements. This proposal would revise the RFS program regulations to implement these EISA 

provisions. 

iii 
Overview 

Chapter 1: Renewable Fuel Production and Consumption 

This chapter describes the various feedstocks and renewable fuel types that could potentially be 

used to meet the EISA biofuel standards. The availability and challenges of harvesting, storing, 

and transporting these feedstocks are discussed, as well as the different biofuel production 

technologies, industry plans, and potential growth projections for future facilities. A discussion 

of biofuel distribution and consumption is included. 

Chapter 2: Lifecycle GHG Analysis 

This chapter describes the methodology used to determine the lifecycle greenhouse gas (GHG) 

emissions of the renewable fuels required by EISA, and to determine which qualify for the four 

GHG reduction thresholds established in EISA. Future inclusion of other feedstocks and fuel is 

discussed, as well as the overall GHG benefits of the RFS program. 

Chapter 3: Impacts of the Program on Non-GHG Pollutants 

This chapter discusses the expected impacts of this proposed program on emissions of 

hydrocarbons (HC), oxides of nitrogen (NOx), carbon monoxide (CO), particulate matter (PM10 

and PM2.5), sulfur oxides (SOx), ammonia (NH3), ethanol, and air toxic emissions of benzene, 

1,3-butadiene, acetaldehyde, formaldehyde, acrolein, and naphthalene. Emissions from vehicles 

and off-road equipment, as well as emissions from the entire fuel production and distribution 

chain are considered. 

Chapter 4: Impacts on Cost of Renewable Fuels, Gasoline, and Diesel
 

The impact of the proposed program on the production and distribution costs of ethanol, 

biodiesel, gasoline and diesel are discussed. Per-gallon and nationwide costs are presented with 

and without ethanol subsidies. 

Chapter 5: Economic Impacts and Benefits of the Program 

This chapter summarizes the impacts of the RFS2 proposal on the U.S. and international 

agricultural sector, U.S. petroleum imports, and the consequences of reduced oil imports on U.S. 

energy security. Also, it examines the greenhouse gas benefits and the co-pollutant health and 

environmental impacts from the wider use of biofuels in the U.S. from this proposal. 

Chapter 6: Impacts on Water 

The impacts of this proposed program on different bodies of water are discussed. Aspects 

include feedstock production, ecological impacts, climate change, ethanol production, biodiesel 

production, and drinking water and public health issues. 

Chapter 7: Initial Regulatory Flexibility Analysis 

The Initial Regulatory Flexibility Analysis (IRFA) evaluates the potential impacts of the 

proposed standards on small entities. In developing the IRFA, we conducted outreach and held 

meetings with representatives from the various small entities that could be affected by the 

rulemaking. Small business recommendations are discussed. 

iv 
Appendix
 

EPA conducted a comprehensive analysis of the emission impacts of biodiesel using heavy-duty, 

in-use diesel chassis and engine exhaust emissions data. The emission impacts on NOx, PM, 

HC, and CO of 20 volume percent biodiesel fuels produced from various animal- and plantbased feedstock materials tested under several cycles in this analysis. 

v 
 

 

 

List of Acronyms and Abbreviations 

ACE American Coalition for Ethanol 

ACS American Cancer Society 

ADM Archer Daniels Midland 

AEO Annual Energy Outlook (an EIA publication) 

AHC Aromatic hydrocarbons 

ARMS Agricultural Resource Management Survey 

ASTM American Society of Testing and Materials 

B0, B5, B20, etc Percent of biodiesel, e.g., B5= 5% biodiesel, 95% diesel 

bbl Barrel 

BEA Bureau of Economic Analysis 

Bgal, bgal, bilgal, bg Billions of gallons 

BGY Billions of gallons per year 

BPCD Barrels Per calendar day 

BPSD Barrels per stream day 

bpd, bbls/day Barrels Per Day 

Brix A measurement of the sugar content of a solution at a given temperature 

BTL Biomass-to-liquid 

BTU British Thermal Unit 

BU Bushel 

Bu/acre Bushels per acre 

BZ Benzene 

C Carbon 

C&D Construction and Demolition 

CA California 

CAA Clean Air Act 

CAIR Clean Air Interstate Rule 

CARB California Air Resources Board 

CaRFG3 California Phase 3 RFG 

CBG Cleaner Burning Gasoline 

CBI Caribbean Basin Initiative 

CB05 Carbon Bond 05 

CD Census Division 

CFEIS EPA’s Certification and Fuel Economy Information System 

CFR Code of Federal Regulations 

c/gal Cents per gallon 

CG Conventional Gasoline 

CH3CHO Acetaldehyde 

CH3C(O)OO· Acetyl peroxy radical 

CH3C(O)OONO2 Peroxyacetyl nitrate 

CHF Congestive heart failure 

CHP Combined Heat and Power Technology 

CIMT Carotid intima-media thickness 

CMAQ Community Multi-scale Air Quality model 

CO Carbon Monoxide 

CO2 Carbon Dioxide 

COHb Carboxyhemoglobin 

Co-op Cooperative 

CRC Coordinating Research Council 

CRGNSA Columbia River Gorge National Scenic Area 

CRP Conservation Reserve Program 

vi 
 

 

 

 

 

CTL Coal-to-liquid 

DDGS Distillers’ Dried Grains with Solubles 

DGS Distillers’ Grains with Solubles 

DHHS Department of Health and Human Services 

DOE Department of Energy 

DRIA Draft Regulatory Impact Analysis 

dt Dry ton 

E&C Engineering and Construction 

E0 Gasoline Blend which Does Not Contain Ethanol 

E10 Gasoline Blend containing a nominal 10 percent ethanol by volume 

E85 Gasoline Blend containing 85 percent ethanol by volume 

E200 Percent of Fuel Evaporated at 200 Degrees F (ASTM D 86) 

E300 Percent of Fuel Evaporated at 300 Degrees F (ASTM D 86) 

EIA Energy Information Administration (part of the U.S. Department of Energy) 

EISA Energy Independence and Security Act 

Energy Act Energy Policy Act of 2005 (also the Act) 

EPA Environmental Protection Agency 

EPAct Energy Policy Act of 2005 (also ‘the Energy Act’ or ‘the Act’) 

ETBE Ethyl Tertiary Butyl Ether 

ETOH Ethanol 

EU European Union 

ex CA Excluding California 

F, °F Fahrenheit 

F-T Fischer-Tropsch 

FAME Fatty acid methyl ester 

FAPRI Farm and Agricultural Policy Research Institute 

FASOM Forestry and Agriculture Sector Optimization Model 

FBP Feed Boiling Point (also Final Boiling Point) 

FCC Fluidized Catalytic Cracker 

FCCU Fluidized Catalytic Cracking Unit 

FHWA Federal Highway Administration 

FOEB Fuel Oil Equivalent Barrel 

FR Federal Register 

FRM Final Rulemaking 

FRTP Fixed Reduction Trigger Point 

FFV Flexible Fuel Vehicle 

FTP Federal test procedure 

g/Btu Grams per Btu 

g/day Grams per day 

Gal, gal Gallon 

GDP Gross Domestic Product 

GEOS Goddard Earth Observing System 

GHG Greenhouse Gases 

GPA Geographic Phase-in Area 

GREET Greenhouse Gas, Regulated Emissions, and Energy Use in Transportation model 

GWP Global warming potentials 

ha Hectare 

H2O Water 

HC Hydrocarbon(s) 

HCO Heavy Cycle Oil (a refinery stream) 

HCHO Formaldehyde 

HDN Naphtha Hydrotreater (also Hydro-Denitrogenation Unit) 

HEI Health Effects Institute 

vii 
 

 

 

HNO3 Nitric acid 

HSR Heavy Straight Run (a refinery stream) 

HVGO Heavy Vacuum Gas Oil (a refinery stream) 

IARC International Agency for Research on Carcinogens 

IBP Initial Boiling Point 

IRFA Initial Regulatory Flexibility Analysis 

k Thousand 

kbbl Thousand barrels 

kg kilogram 

kwh Kilowatt Hour 

L, l Liter 

Lb, lb Pound 

LCC Land Capability Classification 

LCO Light Cycle Oil (a refinery stream) 

LEV Low emission vehicle 

LLE Liquid-Liquid Extraction 

LNS Light Naphtha Splitter 

LP Linear Programming (a type of refinery model) 

LSR Light Straight Run (a refinery stream) 

m2

 Square meter 

MCIP Meteorology-Chemistry Interface Processor 

mg/m3 Milligrams per cubic meter 

MGY, MMgy Million Gallons per Year 

mm Millimeter 

MM Million 

MMBTU Million British Thermal Units 

MMbbls/cd Millions of barrels per calendar day 

MMGal/yr Millions of gallons per year 

MOBILE (5, 6, 6.2) EPA’s Motor Vehicle Emission Inventory Model (versions) 

MON Motor Octane Number 

MOVES Motor Vehicle Emissions Simulator 

MOVES2006 EPA’s Next Generation Highway Vehicle Emission Model 

MSAT Mobile Source Air Toxics 

MSAT1 2001 Mobile Source Air Toxics Rule 

MSAT2 2006 Proposed Mobile Source Air Toxics Rule 

MSW Municipal Solid Waste 

Mt Metric ton 

MTBE Methyl Tertiary-Butyl Ether 

N Nitrogen 

NAAQS National Ambient Air Quality Standards 

NAICS North American Industrial Classification System 

NASS National Agricultural Statistics Service 

NATA National Air Toxic Assessment 

NBB National Biodiesel Board 

NCGA National Corn Growers Association 

NCI National Cancer Institute 

NCLAN National Crop Loss Assessment Network 

NCSU North Carolina State University 

NGL Natural gas plant liquids 

NH3 Ammonia 

NIOSH National Institute of Occupational Safety and Health 

NMHC Non-Methane Hydrocarbons 

NMIM National Mobile Inventory Model (EPA software tool) 

viii 
 

 

 

 

NMOG Non-methane organic gases 

NONROAD EPA’s Non-road Engine Emission Model 

NONROAD2005 EPA’s Non-road Engine Emission Model Released in 2005 

NO Nitric oxide 

NO2 Nitrogen dioxide 

NOx Oxides of nitrogen 

NPRM Notice of Proposed Rulemaking 

NRC National Research Council 

NRCS Natural Resource Conservation Service 

NREL National Renewable Energy Laboratory 

O3 Ozone 

OA Organic aerosol 

OC Organic carbon 

·OH Hydroxyl radical 

OM Organic mass 

OMB Office of Management and Budget 

OMHCE Organic Material Hydrocarbon Equivalent 

ORD Office of Research and Development 

ORNL Oak Ridge National Laboratory 

OTAQ Office of Transportation and Air Quality 

Oxy-fuel, oxyfuel Winter oxygenated fuel program 

PADD Petroleum Administration for Defense District 

PAHs Polycyclic aromatic hydrocarbons 

PAN Peroxyacetyl nitrate 

PM Particulate Matter 

PM10 Coarse Particle 

PM2.5 Fine Particle 

PM AQCD Particulate Matter Air Quality Criteria Document 

PMA Petroleum Marketing Annual (an EIA publication) 

POM Polycyclic Organic Matter 

PONA Paraffin, Olefin, Naphthene, Aromatic 

ppb Parts per billion 

ppm Parts Per million 

PPN Peroxypropionyl nitrate 

PRTP Percentage Reduction Trigger Point 

PSI Pounds per Square Inch 

QBtu Quadrillion btu 

Quadrillion 1015 

(R+M)/2 Octane calculation (RON+MON)/2 

R&D Research and Development 

RBOB Reformulated Blendstock for Oxygenate Blending 

rd Renewable diesel 

RFA Regulatory Flexibility Act 

RFG Reformulated Gasoline 

RFS Renewable Fuels Standard 

RFS1 Renewable Fuels Standard Program promulgated in 2007. 

RFS2 Renewable Fuels Standard Changes 

RIA Regulatory Impact Analysis 

RIMS Regional Input-Output Modeling System 

RIN Renewable Identification Number 

RON Research octane number 

RPMG Renewable Products Marketing Group 

RSM Response Surface Model 

ix 
 

 

RVP Reid Vapor Pressure 

S Sulfur 

SBA Small Business Administration 

SBAR Panel, or ‘the Panel’ Small Business Advocacy Review Panel 

SBREFA Small Business Regulatory Enforcement Fairness Act (of 1996) 

scf Standard cubic feet 

SER Small Entity Representative 

SI Spark Ignition 

SOA Secondary Organic Aerosol 

SOC Secondary organic carbon 

SOC Soil organic carbon 

SOx Oxides of Sulfur 

SULEV Super ultra low emission vehicle 

SVOC Semi-volatile organic compound 

T50 Temperature at which 50% (by volume) of fuel evaporates (ASTM D 86) 

T90 Temperature at which 90% (by volume) of fuel evaporates (ASTM D 86) 

TAME Tertiary Amyl Methyl Ether 

Ton 2000 lbs 

Tonne Metric tonne (equivalent to 1.1 tons); also metric ton 

TRQ Tariff rate quotas 

ULEV Ultra low emission vehicle 

U.S.C. United States Code 

USDA U.S. Department of Agriculture 

VGO Vacuum Gas Oil (a refinery stream) 

VMT Vehicle Miles Traveled 

VOC Volatile Organic Compound 

vol% Percent by volume, volume percent 

WDGS Wet Distillers Grain w/ Solubles 

wt% Percent by weight, weight percent 

yr, y Year 

x 
11 

 

 

 

Chapter 1: Renewable Fuel Production and Consumption 

1.1 Biofuel Feedstock Availability 

Currently, the main feedstocks used for renewable fuel production are corn for ethanol 

and soy for biodiesel. As technologies improve, we expect more emphasis on using cellulosic 

feedstocks such as agricultural residues, forestry residues, etc. However, limitations may occur 

due to concerns over sustainable removal rates for initial cellulosic feedstocks. Thus, dedicated 

energy crops which are touted as requiring low fertilizer and energy inputs as well as having the 

ability of being grown on marginal lands may also enter the market. The following sections 

discuss the current and potential availability of biofuel feedstocks and the potential challenges 

that must be overcome in order for enough feedstock to be collected to meet the EISA 

requirement of 36 billion gallons of renewable fuel by 2022. 

1.1.1 Starch/Sugar Feedstocks 

The following sections describe starch and sugar feedstocks that can be used to produce 

ethanol. Currently, the majority of ethanol is produced from corn/grain. Recently, there have 

also been plans to convert sugarcane grown in the U.S. into ethanol. We also describe 

feedstocks used in the production of ethanol outside the U.S. 

1.1.1.1 Corn/Grain Ethanol 

Today’s ethanol is primarily corn-based ethanol, which accounts for the majority of the 

estimated 9.0 billion gallons of domestic fuel ethanol produced in 2008. According to multiple 

sources, anywhere from 12-18 billion gallons of corn ethanol could be produced by the 2015-16 

timeframe, see Table 1.1-1.1

 Studies indicate, however, that current sustainable production of 

corn for fuel in the U.S. may be no more than 15 billion gallons per year at most, and perhaps 

only 12-14 billion gallons.2,3 For this proposal, we modeled 15 billion gallons of corn ethanol as 

required to meet the EISA standards using the agricultural models FASOM and FAPRI in order 

to assess the impact on crop acreage, crop allocation to fuel vs. other uses, and costs. See 

Chapter 5 of the DRIA for more details on the modeling. In addition to acres harvested and crop 

allocation, factors such as crop yields and ethanol yield per bushel of feedstock impact the 

amount of biofuel that can be produced. 
 

 

 

Table 1.1-1. Corn Ethanol Production Forecast Parameters and Corresponding Years 

Source 

(cited in text above) 

Fuel Volumes/Year 

(billion gallons) 

Acres Planted 

(millions) 

Yield 

(bu/acre) 

Corn Allocation 

to Ethanol 

Ethanol Conversion 

(gal/bu)b 

USDA Baseline 12/2016 90 170 31% 2.76 

USDA Study 15/2016 92 170 37% 2.8 

NCGA Analysisc

 12.8-17.8/2016 76-78a 178-193 33-40% 2.9-3.0 

This Proposal 15/2022 92/87a 183 35% 2.85 a

Acres harvested 

b

Our proposed scenarios assume all figures include denaturant, but most references do not specify; Differences also 

occur depending on whether dry or wet mills are assumed, wet mills have slightly lower yields 

c

National Corn Growers Association 

Corn is mainly grown in 12 states within the United States: Illinois, Indiana, Iowa, 

Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, Ohio, South Dakota, and 

Wisconsin. See Table 1.1-2. 

Table 1.1-2. 

U.S. Corn Harvested in 2007 by State 

Total Harvested 

State (Acres) 

Total 72,222,500 

Illinois 13,050,000 

Indiana 6,351,700 

Iowa 13,850,000 

Kansas 3,700,000 

Kentucky 1,360,000 

Michigan 2,315,900 

Minnesota 7,784,500 

Missouri 3,239,200 

Nebraska 9,199,700 

Ohio 3,604,300 

South Dakota 4,488,400 

Wisconsin 3,278,800 

Corn yield per acre has been increasing at an average rate of about 1.7 percent per year 

for the past three decades.A,4 See Figure 1.1-1. In our economic modeling assessment, the 

national average corn yield is approximately 183 bu/acre in 2022, although yields are calculated 

at the regional level. Therefore, the national average depends on crop production in each region 

in a given year (see Chapter 5 of this DRIA). These yield increases over time are generally 

consistent with the United States Department of Agriculture (USDA) projections.5 

A Calculated from 1977-2007. 

12
 
Figure 1.1-1. U.S. Corn Yields (1978-2008) 

The percent of U.S. corn produced allocated to ethanol has increased in recent years. In 

2006, the percent of U.S. corn used for ethanol was around 20 percent and in 2007 the percent 

had increased to 23 percent. Today, the majority of corn is still being used as animal feed (44 

percent), with smaller portions going to ethanol (33 percent), exports (16 percent), human food, 

and seed.6 The FASOM projects that approximately 35 percent of corn would need to be 

allocated to the ethanol industry by 2022. The amount of corn allocated to fuel vs. other uses has 

caused much controversy over the production and use of corn-based ethanol in the past few 

years. There is concern that the use of corn for fuel could potentially divert corn needed to feed 

people. On the other hand, it is entirely possible that other countries (e.g. Argentina or Brazil) 

could increase their production of corn to match the increase in demand for food and fuel, thus 

meeting both needs. As many factors are in play, we can not be certain of the future. We rely on 

our modeling results to help inform us of the potential impacts. 

Over the last 15 years, ethanol industry optimization of cooking, mashing, and 

fermentation conditions has increased the amount of ethanol produced from a bushel of corn. 

According to USDA reports, by about 2010 we can expect all plants on-line to yield an average 

of 2.76 gallons per bushel.7,8

 In addition, based on discussions with USDA, we believe it is 

reasonable to expect an increase in corn kernel starch content of 2-4 percent over the next 

decade. Combining these figures, we project industry average denatured ethanol yields to reach 

2.85 gallons per bushel by 2022 for dry mills and 2.63 gallons per bushel for wet mills. See 

section 1.4 of this DRIA for more information on corn ethanol biofuel production technologies, 

e.g. dry mill vs. wet mill. 

1.1.1.2 Sugar Ethanol 

Currently, there are no U.S. plants producing ethanol from sugar feedstocks.9 Brazil and 

several other countries are producing ethanol from sugarcane, sugar beets, and molasses, 

13
 
 

 

showing that it is economically feasible to convert these feedstocks into ethanol (see section 

1.1.1.3). However, the economics of producing ethanol from sugar feedstocks in these countries 

is not directly comparable to the economics of producing ethanol from sugar feedstocks in the 

U.S. Over the longer term, the profitability of producing ethanol from sugarcane, sugar beets, 

and molasses depends on the prices of these crops, the costs of conversion, and the price of 

gasoline. 

Recent news indicates that there are plans in the U.S. to produce ethanol from sugar 

feedstocks. For instance, sugarcane has been grown in California’s Imperial Valley specifically 

for the purpose of making ethanol and using the cane’s biomass to generate electricity to power 

the ethanol distillery as well as export excess electricity to the electric grid.10 There are at least 

two projects being developed at this time that could result in several hundred million gallons of 

ethanol produced. One company is California Ethanol and Power which is currently in the 

development stage and plans to build a facility that produces 60 million gallon per year of 

sugarcane ethanol and 50 megawatts of electricity.11 The company plans to break ground by late 

2009 and be operational by 2011. The sugarcane is being grown on marginal and existing 

cropland that is unsuitable for food crops and will replace forage crops like alfalfa, Bermuda 

grass, Klein grass, etc. Harvesting is expected to be fully mechanized. Another company is 

Pacific West Energy LLC which plans to produce 12-15 million gallons per year of ethanol on 

the island of Kauai in Hawaii, perhaps as early as 2010. Hawaii is well suited for sugarcane 

ethanol production due to several factors, including lower costs for feedstock compared to those 

in the continental U.S., high prices for electricity and liquid fuels, and state production 

incentives.12 Thus, there is potential for these projects and perhaps others to help contribute to 

the EISA biofuels mandate. 

1.1.1.3 Imported Ethanol 

In 2006, around 47% of world fuel ethanol production was produced from sugar crops, 

i.e. sugarcane and sugar beets, with the remainder mostly from grains.13 Sugar beets are mainly 

grown in France, Germany, and in the U.S., with the majority of the feedstock typically used to 

produce sugar for food and feed. Compared to sugar beets, sugarcane is produced in much 

higher volume and has been able to support a growing sugar and ethanol market. Due to a higher 

availability of sugarcane feedstock for ethanol production, we expect that imported ethanol to the 

U.S. will likely come from sugarcane. 

World production of sugarcane is approximately 1.4 billion metric tons (MT) and is 

concentrated mainly in tropical regions, particularly in Latin America, Africa, and South and 

Southeast Asia. Roughly 100 countries produce sugarcane today.14 Brazil is currently the 

world’s largest producer of sugarcane (487 million MT in the 2007/8 harvest season) and offers 

the greatest potential for growth, due primarily to the availability of suitable lands for expanding 

sugarcane cultivation.15 

As far as land availability is concerned, Brazil has large potential for expanding 

sugarcane production. Sugarcane area in Brazil is forecasted to grow by 50% by 2010, with 

construction and extension of mills especially in the Centre-South. Currently expansions have 

mainly been into pastureland areas and not into native scrubland. In Brazil, just 20% of the 

14
 
arable land is cultivated, totaling 156 million acres. The following Table 1.1-3., describes the 

land available/used in 2007. As there are 494 million acres of pastureland and a considerable 

area of unused arable land (190 million acres), it is believed that there could be a large expansion 

in sugarcane.16 

Table 1.1-3. Brazil Land Areas in 2007.17 

Million Acres 

Brazil (Total Area) 2100 

Total Preserved Areas and Other Uses* 1260 

Total Arable Area 840 

Cultivated Land (All Crops) 156 

Soybeans 51 

Corn 35 

Oranges 2 

Sugar Cane 19 

Sugar Area 11 

Ethanol Area 8 

Pastureland 494 

Available land (ag, livestock) 190 

*Areas include Amazon Rain Forest, protected areas, conservation 

and reforestation areas, cities and towns, roads, lakes, and rivers. 

The statistics above, however, do not indicate whether the land available requires any 

additional usage of water or has the proper soil and climate conditions for sugar cane. According 

to one study, there is at least 148 million acres of additional land available with proper soil and 

climate conditions for sugar cane without utilizing environmentally protected land (i.e. Amazon 

and native reserves) and without the use of irrigation.18 This translates to approximately 90 

billion gallons of ethanol potential (using a yield of approximately 600 gal/acre which is a 

conservative estimate based on existing technology). Although it is not probable that all this 

land will be converted to sugar cane ethanol, the estimate puts into prospective the large potential 

for sugarcane ethanol to be produced in Brazil. 

Another study commissioned by the Brazilian Government produced an analysis in which 

Brazil’s arable land was evaluated for its suitability for cane. The benefit of this study is that it 

provides more detail on the land quality and yield assumptions used in its estimates than the 

study and statistics shown above.19 The study eliminated areas protected by environmental 

regulations and those with a slope greater than 12% (those not suitable for mechanized farming). 

The following Table 1.1-4 shows the available land calculated for sugarcane expansion at 

various crop yields with and without irrigation and the potential volumes that could be attained. 

As can be seen, there are potentially large areas of land available for sugarcane expansion in 

Brazil. 

15
 
 

 

 

Table 1.1-4. 

Potential Volumes Utilizing Available Land for Sugarcane ExpansionB,19,20 

Potential 

Ethanol Yield 

(gal/acre) 

Potential Area 

(million acres) 

Potential Ethanol Volume 

(billion gallons) 

w/o irrigation w/ irrigation w/o irrigation w/ irrigation 

High 

Good 

Average 

Inadequate 

659 

592 

524 

0 

20 94 

281 242 

369 414 

224 143 

13 62 

166 143 

193 217 

0 0 

Total 894 894 373 422 

The actual potential for ethanol from sugarcane will, however, be further limited by the 

amount of sugarcane diverted towards food and other uses. Taking into account demands for 

food and feed, the Oak Ridge National Laboratory (ORNL) Biofuel Feedstock Assessment for 

Selected Countries report suggests that perhaps more than 20 billion gallons of gasoline 

equivalent fuel could be produced from available sugarcane supply by 2017. Brazil is estimated 

to produce approximately 2/3 of the potential supply. The majority of this supply would likely 

be consumed within the country, with the leftover potentially available for export to the U.S. and 

other countries. Recent government and industry estimates indicate that approximately 3.8-4.2 

bgal of ethanol could be available for export from Brazil by 2022 (with close to 17 billion 

gallons being produced and 13 billion gallons consumed domestically). See section 1.5.2.1.1 of 

this DRIA for further details on Brazilian ethanol production and consumption. Thus, there 

appears to be a large enough potential for Brazil to increase production of sugarcane to meet its 

internal demands as well as export to the United States and other countries. 

Countries other than Brazil lack the land resources, appropriate soils, and climate for 

large expansion of sugarcane production.21 India and China are the second and third largest 

producers, however, most of the cultivatable land area is already in use and government policies 

discourage reallocation of arable land for biofuel production. Although Argentina and Columbia 

have significant underutilized lands available, these resources generally do not have suitable soil 

and climate characteristics for sugarcane production. Due to these factors, Brazil is the most 

likely country able to produce substantial volumes of sugarcane for biofuel production in the 

future. 

1.1.2 Cellulosic Biofuel Feedstocks 

Various cellulosic feedstocks can potentially be used to produce cellulosic biofuel. These 

include agricultural residues, forest residues, urban waste, and dedicated energy crops. We 

describe each type in the following sections. 

B Adapted from CGEE, ABDI, Unicamp, and NIPE, Scaling Up the Ethanol Program in Brazil. Assumed a 

conversion factor of 20 gallons of ethanol per tonne of sugarcane feedstock to compute gal/acre. A “high” potential 

refers to ethanol yields that are higher than current industry averages, while “good” refers to good quality land and 

productivity that is about equal to the current average. Explanations for “Average” and “Inadequate” were not 

provided. 

16
 
1.1.2.1 Agricultural Residues 

We estimated how much crop residue could potentially be produced, and of that, how 

much could be removed or harvested to determine the total amount that will be available to 

produce ethanol in 2022. The amount of residue that can be harvested is limited by how much 

residue must be left on the field to maintain soil health and by the mechanical efficiency 

(inefficiency) of the harvesting operation. We discuss harvesting limitations due to maintaining 

soil health below, while mechanical efficiencies, storage, and transport issues are discussed in 

section 1.3 of this DRIA. Feedstock costs are discussed in Chapter 4 of the DRIA. 

 Corn (Zea mays L.) and wheat are receiving the most attention across the industry due to 

their concentrated production areas and because between them they generate about the majority 

of total residue that’s produced. This also means they will more likely be able to support 

commercial scale production. In aggregate, the other residues provide fairly significant 

quantities of material, but because they are spread out, e.g., less densely planted both in the field 

and in a county or state, they are viewed as less likely to support commercial operations. Later, 

we discuss how these other lower-quantity residue crops may supplement the larger operations. 

We analyzed various reports on the availability of agricultural residues. These are 

summarized in Table 1.1-5. The agricultural residue estimates in Table 1.1-5 are based on 

historical/recent data, and thus, could be considered conservative in comparison to the future 

(2022) which would typically have higher crops yields or increases in acres harvested. 

Table 1.1-5. Estimated Agricultural Residue Feedstock Availability (per year)22,23,24,25,26 

Source Total Available Total Sustainably Removable Crops Analyzed 

USDA > 500 million tons not specified 

Eight leading U.S. crops, e.g. corn, wheat, 

soy, oats, barley, rice (did not specify other 

two) 

NREL 495 million tons 173 million tons 

Corn, wheat, soybeans, cotton, sorghum, 

barley, oats, rice, rye, canola, beans, peas, 

peanuts, potatoes, safflower, sunflower, 

sugarcane, and flaxseed 

Gallagher not specified 156 million tons Corn, wheat, sorghum, barley, oats, rice 

Walsh not specified 

144 million tons at $40/dry ton, ~150 

million tons at >$40/dry ton for corn; 7 

million tons at $40/dry ton, ~10-11 million 

tons at >$40/dry ton for wheat Corn and wheat 

Graham 216 million tons 

65 million tons at 30% removal rate and 

current conditions; 112 million tons at 50% 

removal rate using no-till conditions Corn 

Based on our FASOM modeling, corn stover was chosen as the most economical 

agricultural feedstock to be used to produce ethanol in order to meet the 16 Bgal EISA cellulosic 

biofuel requirement. We estimate that by 2022 greater than 400 million tons of corn stover could 

be produced. Approximately 82 million tons would be needed to produce 7.8 billion gallons of 

17 
 

cellulosic biofuel that our modeling projects to come from corn stover by 2022.C See Table 1.1­

6. Smaller amounts will be required from sugarcane (bagasse) as well as sweet sorghum pulp to 

produce another 1.3 billion gallons of cellulosic biofuel.D Thus, the residue collected to meet 

EISA would be a small fraction of the total residue produced. See section 1.5.3.4 for more 

details on the use of agricultural residues for our cellulosic plant siting analysis. 

C

 Assuming conversion yield of 94 gal/dry ton 

D Bagasse is technically a by-product of the sugarcane process and not an agricultural residue, we include it here for 

simplification. Sweet sorghum pulp is also a by-product of sweet sorghum processing. 

18
 
 

Table 1.1-6. 

FASOM Estimated Agricultural Residue Feedstock Availability in 2022 (million tons)E
 

State/Region Barley Corn Oats Rice Sorghum Wheat Total 

Alabama 0.0 1.9 0.0 0.0 0.1 0.2 2.2 

Arizona 0.1 0.1 0.0 0.0 0.0 0.4 0.7 

Arkansas 0.0 2.7 0.0 6.3 1.5 2.8 13.3 

California 0.4 1.6 0.1 1.9 0.1 3.1 7.3 

Colorado 0.3 5.5 0.0 0.0 0.4 7.7 13.9 

Connecticut 0.0 0.0 0.0 0.0 0.0 0.0 0.0 

Delaware 0.0 0.2 0.0 0.0 0.0 0.0 0.3 

Florida 0.0 0.2 0.0 0.0 0.0 0.0 0.2 

Georgia 0.0 5.7 0.1 0.0 0.1 0.3 6.2 

Idaho 1.3 0.4 0.0 0.0 0.0 4.5 6.2 

Illinois 0.0 70.6 0.0 0.0 0.4 4.1 75.1 

Indiana 0.0 34.6 0.0 0.0 0.0 1.8 36.4 

Iowa 0.0 79.2 0.4 0.0 0.2 0.1 79.9 

Kansas 0.0 16.1 0.0 0.0 7.5 23.2 47.0 

Kentucky 0.1 7.5 0.0 0.0 0.1 1.6 9.3 

Louisiana 0.0 0.5 0.0 4.0 0.1 0.1 4.8 

Maine 0.0 0.1 0.0 0.0 0.0 0.0 0.2 

Maryland 0.1 2.0 0.0 0.0 0.0 0.6 2.8 

Massachusetts 0.0 0.0 0.0 0.0 0.0 0.0 0.0 

Michigan 0.0 9.6 0.1 0.0 0.0 2.6 12.3 

Minnesota 0.2 40.3 0.3 0.0 0.0 3.8 44.6 

Mississippi 0.0 4.6 0.0 0.7 0.5 1.2 7.0 

Missouri 0.0 12.9 0.1 0.4 3.0 2.4 18.8 

Montana 1.1 0.0 0.1 0.0 0.0 6.5 7.8 

Nebraska 0.0 59.6 0.1 0.0 1.2 6.7 67.5 

Nevada 0.0 0.0 0.0 0.0 0.0 0.0 0.1 

NewHampshire 0.0 0.0 0.0 0.0 0.0 0.0 0.0 

NewJersey 0.0 0.2 0.0 0.0 0.0 0.1 0.3 

NewMexico 0.0 0.5 0.0 0.0 0.7 1.6 2.8 

NewYork 0.0 2.1 0.3 0.0 0.0 0.5 3.0 

NorthCarolina 0.1 4.6 0.1 0.0 0.1 1.5 6.4 

NorthDakota 1.8 5.7 0.2 0.0 0.0 14.0 21.7 

Ohio 0.0 18.2 0.2 0.0 0.0 4.0 22.4 

Oklahoma 0.0 0.3 0.0 0.0 0.8 9.7 10.9 

Oregon 0.2 0.2 0.1 0.0 0.0 0.6 1.1 

Pennsylvania 0.1 3.2 0.2 0.0 0.0 0.7 4.2 

RhodeIsland 0.0 0.0 0.0 0.0 0.0 0.0 0.0 

SouthCarolina 0.0 1.1 0.0 0.0 0.0 1.0 2.2 

SouthDakota 0.1 17.1 0.2 0.0 0.5 6.8 24.7 

Tennessee 0.0 2.7 0.0 0.0 0.1 0.9 3.8 

Texas 0.0 15.2 0.1 1.2 5.5 3.5 25.6 

Utah 0.1 0.1 0.0 0.0 0.0 1.0 1.2 

Vermont 0.0 0.2 0.0 0.0 0.0 0.0 0.2 

Virginia 0.1 1.2 0.0 0.0 0.0 0.7 1.9 

Washington 1.1 0.8 0.0 0.0 0.0 6.9 8.8 

WestVirginia 0.0 0.1 0.0 0.0 0.0 0.0 0.1 

Wisconsin 0.0 14.2 0.2 0.0 0.0 1.2 15.7 

Wyoming 0.2 0.3 0.0 0.0 0.0 0.4 0.9 

Total 7.7 444.4 3.1 14.6 23.1 128.8 621.8 

E

 Assumes straw to grain ratio for barley and wheat (1.5:1) and for corn, oats, rice, and sorghum (1:1); Also assumes 

0.024 ton/bu for barley and oats, 0.028 ton/bu for corn, 0.05 ton/cwt for rice and sorghum, and 0.03 on/bu for wheat. 

19 
 

 

Soil Health 

In terms of soil health, residues perform many positive functions for agricultural soils. 

Recent studies and reviews have attempted to address these issues. Despite a few shortcomings, 

existing research can be used to some extent to guide practices or make estimates, especially for 

corn stover harvest in the Corn Belt, which has been studied more extensively than the other 

residues except, perhaps, wheat. 

In a review by five USDA Agricultural Research Service (ARS) scientists, Wilhelm et al. 

acknowledged the complexity of interactions between soil type, climate, and management when 

considering crop residue effects on soil. They recommended that removal rates be based on 

regional yield, climatic conditions and cultural practices, with no specific rates given.27 Using 

the Revised Universal Soil Loss Equation (RUSLE) technology and the Wind Erosion Equation 

(WEQ), Nelson predicted safe residue removal rates for minimizing soil loss in the Eastern and 

Midwestern U.S. These predictions varied widely over time and location as a result of the 

complex interactions discussed by Wilhelm et al. 28,29 In another recent review, sponsored by the 

U.S. Department of Energy (DOE), Mann et al. concluded that before specific recommendations 

could be made, more information was needed on the long term effects of residue harvest, 

including: 1) water quality; 2) soil biota; 3) transformations of different forms of soil organic 

carbon (SOC); and 4) subsoil SOC dynamics.30 Current USDA Natural Resource Conservation 

Service (NRCS) practice standards for residue management shy away from specific residue 

quantities and point to the use of the RUSLE2 model for guidance (without specifics on how to 

do so).31 Despite broad recognition of the need for specific guidelines for residue removal, none 

yet exist. 

With the upsurge in biofuels and the obvious prospects of removing significant quantities 

of residue, many questions remain regarding the long-term effects on soils of residue removal. 

Residues haven’t yet been removed at the contemplated rates over a period sufficiently long for 

the effects to be clearly determined. Another difficulty is that while the effects of removing a 

residue may appear to one observer to have affected the soil in a certain manner, it may not be 

completely clear that the observed effects were totally related to the residue removal or, were in 

fact related to a change or to combinations of changes in other variables that were simply missed. 

A second observer may view the same results in an honest, but different manner. There are so 

many variables with so many different interactions among them that assigning effects is very 

difficult at best. There simply are no real-world data available for determining long-term effects. 

Nevertheless, we can describe some of the interactions that take place and how they can 

potentially affect soil health. 

Soil Erosion 

Soil erosion is an extremely important national issue. Most, if not all, agricultural 

cropland in the United States experiences some degree of soil erosion each year due to rainfall 

(water) and/or wind forces. Rainfall erosion (sheet and rill) occurs when rain directly strikes the 

soil, dislodging particles in the top layer.F

 When soil becomes saturated, particles are 

F

 rill: A small intermittent watercourse with steep sides, usually only a few inches deep; 

www.hancockcoingov.org/surveyor/drainage_glossary_of_terms.asp. 

20
 
 

 

transported down the slope of the field. Soil erosion due to wind occurs in much the same 

manner as rainfall with wind forces dislodging soil particles and carrying them along and above 

the field surface (creep and saltation) or suspending them above the field.G While eroded soil 

does not disappear, the erosion process moves soil particles to other locations in the field (either 

downslope or downwind) where they can be transferred into waterways or onto non-croplands. 

The amount of soil erosion that agricultural cropland experiences is a function of many 

factors: field operations (field preparation, tillage, etc.) in preparation for the next crop, timing of 

field operations, present throughout the year, soil type, field characteristics such as field slope, 

and the amount of residue (cover) left on the field from harvest until the next crop planting. Crop 

rotation cover provided by agricultural crop residues, both fallen and standing, helps to minimize 

rainfall and wind energy as it strikes or blows across the ground as well as helping to keep soil 

particles from being transported after they have been dislodged. Climatic conditions such as 

rainfall, wind, temperature, etc. must be accounted for. Studies predict that up to 30% of surface 

residue can be removed from some no-till systems without increased erosion or runoff. 

The NRCS has established tolerable soil loss limits (T values) for all soil types in all 

counties throughout the United States. The tolerable soil loss values denote the maximum rate of 

soil erosion that can occur for a particular soil type that does not lead to prolonged soil 

deterioration and/or loss of productivity. Tolerable soil loss limits take into account the rate of 

topsoil formation, role of topsoil formation, loss of nutrients, erosion rate at which gully erosion 

would commence, and potential erosion-control factors that farmers would be able to implement. 

However, T values are not a function of the type of crop grown. 

Soil Tilth 

Another important aspect associated with soil conservation involves soil tilth. Soil tilth is 

defined as the physical condition of the soil as related to its ease of tillage, fitness as a seed bed, 

impedance to seedling emergence and root penetration, and all other physical conditions that 

influence crop development. Tilth depends upon soil granulation and its stability (soil 

workability) as well as organic matter content, moisture content, porosity, water retention, degree 

of aeration, rate of water infiltration, drainage, and capillary-water capacity, all of which are 

affected by crop residue removal. Preliminary values of required tilth have been estimated by 

the NRCS. 

Tillage 

Various tillage operations are associated with management of agricultural crop residues 

and planting preparation throughout the year. Type and number of tillage operations employed 

for any particular crop from the time of harvest until the next planting have a tremendous effect 

on the amount of soil lost to erosion during the year, and hence, the amount of residue that can 

possibly be removed for energy purposes. It must be noted that even though crop residues may 

be used for energy purposes, the farmer is, first and foremost, in the business of producing grain. 

Therefore, he will be concerned with using those tillage operations that will provide him with the 

G saltation: the movement of sand-sized particles by a skipping and bouncing action in the direction the wind is 

blowing uizlet.com/print/10948/ 

21
 
highest possible yield at the next harvest, and not necessarily those that tend to maximize erosion 

control on his lands.32 

In summary, all agricultural cropland upon which nearly any crop is grown within a 

particular county can exhibit a wide variation in soil erodbility, field slope and length, climate 

conditions, and management practices. Within any one particular county there can be many 

different soil types (50 or more) used to grow agricultural crops. In addition, and possibly more 

importantly, not all soil types within a county may be suitable for agricultural crop production. 

Some soils possess characteristics that make them highly susceptible to erosion that may not be 

able to sustain certain cropping practices. Production of conventional agricultural crops on these 

lands may severely and/or permanently reduce the soil’s ability to provide sustained, economical 

production. For this reason, the NRCS implemented a land capability classification (LCC) that 

ranges from I (one) to VIII (eight) that is applied to all soils within a county. 

Organic Matter, Carbon, and Nutrients 

With added nitrogen fertilizers, residues can increase soil organic matter (SOM). 

However, roots appear to be the largest contributor to new SOM, making residues less important 

for carbon accrual. Residue removal leading to higher erosion and runoff rates would greatly 

decrease SOM and nutrients. Residue harvest would also require increased fertilizer inputs to 

make up for nutrients removed in the plant material. When returned to the land, crop residue 

also replenishes soil organic carbon (SOC) that typically has already been reduced 30 to 50% of 

precultivation levels through crop production activities. Soil organic carbon retains and recycles 

nutrients, improves soil structure, enhances water exchange characteristics and aeration, and 

sustains microbial life within the soil. It’s been reported that crop yield and the value of 

environmental services (C and N sequestration) were greater for soils with greater SOC. Limited 

research has shown that removing stover reduces grain and stover yield of subsequent crops and 

further lowers soil organic matter levels.33 

Beneficial and Deleterious Soil Organisms 

Residue removal can result in detrimental changes in many biological soil quality 

indicators including soil carbon, microbial activity, fungal biomass and earthworm populations, 

indicating reduced soil function. Some disease-producing organisms are enhanced by residue 

removal, others by residue retention, depending on crop and region. 

Available Water and Drought Resistance 

Residue cover can reduce evaporation from the soil surface, thereby conserving moisture 

and increasing the number of days a crop can survive in drought conditions. Improved soil 

physical properties related to crop residues, such as reduced bulk density, e.g., the soil is looser 

and lighter, and greater aggregate stability, also lead to better water infiltration and retention. 

22
 
Soil Temperature and Crop Yield 

In colder climates, residues are linked to reduced yields due to lower soil temperatures 

resulting in poor germination. Stubble mulching, as opposed to residue chopping, can help 

overcome this problem. Even though residue-associated yield reductions have been found on 

poorly drained, fine–textured soils, these soils often have low erosion risk and residues might 

safely be removed. 

Summary 

Despite the many important benefits of crop residues, research shows their effects can 

vary. For instance, some reports showed lower yields in systems with high crop residues due to 

increased disease or poor germination; others reported higher yields when soil moisture is 

limiting. Other studies suggest that residues do not contribute significantly to soil carbon. Many 

studies found that additional N fertilizer is needed when residues are left on soils to avoid N 

uptake (immobilization) from soil or allow for soil carbon accrual. For appropriate residue 

removal recommendations, the conditions leading to these varied effects of residues must be 

elucidated. 

Soil health as related to residue removal is an extremely complex issue for which, as yet, 

there are no specific guidelines for residue removal. Wrong decisions, carried out over extended 

periods could have far reaching deleterious effects. Sustainable residue removal rates for biofuel 

production vary by system, according to such factors as management and cropping practice, crop 

yield, climate, topography, soil type and existing soil quality. Keeping in mind that gravimetric 

rates are not the same as percent soil cover (% mass is not the same as % coverage), appropriate 

conversion is necessary and varies by crop and region. While areas with low slopes and high 

yields may support residue harvest, in many areas the residue amounts required to maintain soil 

quality could be even higher than current practices. What is meant by ‘high’ and ‘low’ slopes 

has yet to be absolutely determined, which determination also depends on soil type and other 

cropping practices. Removal rates will need to be reduced as climates become warmer or more 

humid, for lower C:N residue or lower yielding crops, as soil disturbance (e.g. tillage) increases, 

or as soils become coarser textured, compared to the conditions in which most studies occurred 

(in the U.S. Midwest Corn Belt for no-till corn).34 The most important aspect of this is that any 

or all of the interacting variables that determine how much residue can be removed, can, and 

usually do, change from year-to-year, across both wide regions of the country as well as across 

single counties and farms. A change in one variable nearly always changes how all the variables 

interact. 

Given all the issues we’ve discussed regarding residue removal and soil health, rather 

than try to predict, county-by-county how much residue will be available, we assumed in our 

FASOM modeling that the available amount will be somewhere between 0% and 50%, at least 

until the issues we’ve been discussing are settled. We based the amount removable based on the 

tillage practice: 0% removed for conventional tillage, 35% removed for conservational tillage, 

and 50% removed for no-till for corn stover.35 Removal rates for wheat straw were based on the 

billion-ton study.36 We believe that given the uncertainties in removal rates, our assumptions are 

reasonable. 

23
 
 

 

 

1.1.2.2 Forest Residues 

There is a substantial amount of forestland here in the U.S. It is estimated that 749 

million acres, or one-third, of the U.S. land area is forested. Of this forested land, two-thirds (504 

million acres) is considered timberland which contains more than 20 ft3

 of woody material per 

acre – the other one-third of the forest land contains less than 20 ft3 of woody material per acre. 

Most of this forested land, 58 percent, is privately owned, another 29 percent of the forest land is 

publicly owned, and 13 percent is owned by the forest industry. A higher percentage of the land 

is privately owned in the East, and a higher percentage of the land is publicly owned in the West. 

Of the 749 million acres of forestland, 77 are reserved as parks or wilderness and would 

likely be considered off limits for harvesting for biomass. Also, 168 million acres of timberland 

is believed to be not suitable for harvesting for biomass because of poor soil, lack of moisture, 

high elevation, or rockiness.37 

The U.S. forestry industry harvests a portion of this forest land to produce its products, 

and in the process of doing so, it generates woody residues that can be recovered for the purpose 

of producing cellulosic biofuels. Major sources of solid waste wood generated in the U.S. 

include forestry residues, primary and secondary mill residues, and urban wood residues. In 

addition, forests which are not currently harvested for wood could be thinned. This thinning of 

the forests would not just be to provide biomass, but as part of a strategy which may be 

beneficial for the forests, or to avoid external costs such as forest fires. Each of these categories 

is further described below: 

Forestry residues 

In-forest operations generally include four major sources of materials: logging residues, 

other removals, fuelwood, and fuel treatment wood.38 In the process of removing, or logging, 

the larger woody portion of the trees (5 inch diameter and greater), the logging industry creates 

logging residues. Logging residues typically include tops of harvested trees and unwanted trees 

cut or knocked down and left on site, including dead and cull trees. Other removals are growing 

stock and other sources cut and burned or otherwise destroyed in the process of converting forest 

land to non-forest uses, such as for making way for new housing or industrial developments. 

They also include growing stock removed in forestry cultural operations. Forest residues are 

also available from fuelwood, which is harvested wood used in the residential and industrial 

sectors for energy. Thus, forest residues are already being created or harvested today. 

Primary and secondary mill residues 

Harvested wood from forests is converted into consumer products at wood processing 

mills. Primary mills convert roundwood products (i.e., tree trunks and logs) into other wood 

products, including sawmills that produce lumber, pulp mills, veneer mills, etc. Secondary mills 

use the products from primary mills to produce other products such as millwork, containers and 

pallets, buildings and mobile homes, furniture, flooring and paper and paper products. While 

primary and secondary mills are typically separate facilities, both primary wood processing and 

secondary conversion to finished consumer products can occur in the same facility.39 

24
 
 

Both primary and secondary mills produce residue and waste woody material. For 

example, the residue generated by primary mills includes bark, slabs and edgings, sawdust and 

peeler cares. This waste material could be used as feedstock to produce biofuels. 

Urban wood residues 

The two principal sources of urban wood residues are municipal solid waste (MSW) and 

construction and demolition (C&D) debris. Municipal solid waste contains solid wood from 

both wastewood and yard trimmings. Yard trimmings include herbaceous material and woody 

trimmings. Information on the composition of MSW is limited. However, it has been assumed in 

one report that approximately two thirds of the total volume consists of woody material.40 

Construction waste is made of contemporary building materials with little contamination. 

Sources include new residential construction, new nonresidential building construction and 

repair and remodeling of existing buildings. Demolition waste, on the other hand, is a 

heterogeneous mixture of material from demolishing buildings and structures and is difficult to 

separate as it is often contaminated. The potential contribution of urban wood residues to the 

production of biofuels will be addressed in the section 1.1.2.3 of this DRIA. 

The Thinning of Forests 

While the above categories are associated with existing forest harvesting or other removal 

activities, the thinning of forests would largely be a new activity. Many U.S. forests have 

become overgrown and very dense with forest material, and a portion of this overgrown forest 

will die, dry out and decay. This decaying forest material can provide a source of fuel for forest 

fires that are expensive to fight or contain. Over the previous 10 years forest fires have 

consumed 49 million acres and cost the U.S. taxpayer $8.2 billion. 41 This cost does not include 

the additional cost due to the loss of human life, the loss of personal property and the impact on 

the environment. Thinning forests involves the removal of excess forest material from the 

forests that could help to prevent some of these forest fires, or at least help to reduce their 

impact. Also, thinning these forests to prevent them from becoming overly dense could 

potentially help them to remain healthier. There are many thinning operations today, but the 

material is burned or left to decompose instead. The removed excess woody material from 

overgrown forests could provide a source of biomass for producing biofuels. 

Despite the availability of woody residues for producing cellulosic biofuels, there are 

several obstacles for woody residues that are not present when utilizing feedstocks such as 

agricultural residues. For instance, forestlands will likely be managed less intensively than 

agricultural lands because forests provide multiple-use benefits (e.g., wildlife habitat, recreation, 

and ecological and environmental services).42 This in effect makes it more difficult to take steps 

to increase the productivity of forest areas. Also, there are factors or site conditions that can 

affect tree growth, including poor soils, lack of moisture, high elevation, and rockiness. The 

limits caused by some of these factors would likely not be overcome, resulting in lower 

productivity than what could be theoretically possible. Also, a couple of these factors, the high 

elevation and rockiness, results in areas of forestland which is inaccessible by forestry 

equipment. Forestry residues are also demanded for other purposes other than for production of 

25
 
a transportation fuel (e.g. for process fuel). These reasons would make it more challenging to 

collect and use woody residues in large quantities compared to agricultural residues. 

On the other hand, there may be some benefits to the use of woody residues. One 

example is the removal of excess forestry biomass to reduce the risk of fires and/or to improve 

forest health. In addition, resources such as primary and secondary mill residues and urban 

wood residues are already collected at the processing facility and it seems probable that some 

cellulosic facilities could be co-located to mills and/or landfills to increase the likelihood of 

having close and steady feedstocks readily available. Some states may also be endowed with 

larger wood resources than agricultural residues. 

The following sections further describe some of the additional factors to consider when 

determining the potential availability of woody feedstocks. 

Harvest, Transport, and Storage 

The largest portion of woody material to produce biofuels is available as forestry 

residues. However, unlike residues such as primary or secondary mill residues and urban wood 

residues that could be available on-site at a processing facility, forestry residues would need to 

be collected and transported similarly to conventional forest products. The amount of residues 

potentially available is a function of harvest amount, logging method, and type and location of 

timberlands.43 In addition, residue availability is limited by economic factors. According to one 

study, “the actual operations of harvesting, collecting, processing and transporting loose forest 

residues are costly and present an economic barrier to recovery and utilization of wood for 

energy”.44 Thus, there are still challenges that need to be addressed before large-scale use of 

forestry residues is possible. 

Currently, the most cost-effective method of recovering forest residue for biomass is inwoods chipping.45 This method is suitable for operations where there is whole-tree skidding to 

roadside, good road access to chip vans and chippers, and sufficient biomass volume per acre. 

However, in-woods chipping systems are not as effective when ground-based skidding is 

restricted or when there are no merchantable products other than biomass. In addition, the chip 

vans designed to haul wood chips were built for highway use and often do not have sufficient 

suspension systems for remote forest roads. There are also high costs for wood grinders with 

low production rates.46 Fortunately, there have been developments in alternative methods to 

reduce the costs of biomass collection systems. 

Much of the focus has been on developing methods of densifying residues in order to 

increase productivity of handling operations (i.e. hauling, skidding, and loading). New 

approaches to removing forestry residues are currently being evaluated (e.g. slash bundling 

machines, horizontal grinders, and roll on/off container transport). One of the advantages of 

using slash bundling machines, for example, is the ability to store biomass longer than in chip 

form. Storing biomass at roadside in the form of biomass bundles could provide a more secure 

and stable biomass supply than with chips which are smaller and have greater surface area for 

potential weathering. The use of horizontal grinders was also found to be the best at reducing 

26
 
 

 

bundles. Utilizing roll on/off containers allows for recovery of residue from difficult-to-access 

locations and in such situations could be competitive with regular highway chip vans. 

While these are just some of the ways to improve recovery operations for forestry 

residues, these methods still have challenges. For example, there are some difficulties with 

bundling of brittle residues or short, large diameter pieces. In addition, some residues may 

include rocks or trash that can result in additional saw maintenance and reduced utilization. 

With millions of acres of forest, there is no single residue treatment option that will meet the 

needs of all situations. Forest land managers will need to weigh the different options for dealing 

with forest residues to determine the most cost-effective means for residue removal in their 

specific locations. 

In making estimates of potential forest residue availability, certain assumptions about 

accessibility and recoverability are typically made. For example, some studies assume that 

residue collection is completed at the same time as harvesting, meaning that all residues are 

regarded as one hundred percent accessible.47 This might become possible due to integrated 

harvesting systems which could harvest forest biomass in a single pass operation such that 

residual forest residue for producing biofuels could be produced along with conventional forest 

products.48 Other estimates for accessibility have been lower, with about sixty percent of North 

American temperate forest considered accessible (not reserved or high-elevation and within 15 

miles of major transportation infrastructure).49 In terms of recoverability, some studies have 

assumed sixty-five percent of logging residues and fifty percent of other removal residues as 

being recoverable while others report an average potential recovery of sixty percent and as much 

as sixty-five percent when utilizing newer technology. 50 

Sustainable Removal 

While there has been some discussion of sustainable removal practices for crop residues, 

there has been less review on the topic for woody residues. As forest residues have been 

traditionally left in the forest to decompose, there remains much to be learned about the 

harvesting of forest residues in a sustainable way that still leaves sufficient nutrients to maintain 

the forest and to replenish the soil. This is reiterated in reports on woody residue removal which 

emphasize the need for more detailed studies on the range of ecological effects, from wildlife to 

soils. 

Currently, practices for how much forest residue shall be maintained in the forest to 

maintain forest health vary substantially. For example, a district for one study on the removal of 

forestry residues required about 5 tons per acre be left whereas other districts had no such 

requirements.51 In a different source, a summary of national forest land management plans from 

1995 indicated about 60 percent of western national forest timberland base to be suitable for 

timber production operations.52 This issue is not only applicable in the United States, but also in 

Europe, where the use of forest biomass for energy is also being considered. A Swedish study 

showed that the main incentive for forest owners not to sell forestry residues was concerns for 

soil fertility.53 Therefore, although there have been limitations to the amount of residue suitable 

for removal there has yet to be consensus over the optimal amount. 

27
 
 

Yet another issue regarding sustainable removal is the affect of forest residue extraction 

on biodiversity. The removal of forest residue may affect biodiversity because lower amounts of 

wood in the forest imply fewer habitats for species using wood for breeding. Species may also 

be threatened because certain insects colonize in wood that may be burned for energy purposes. 

Quantitative predictions about how much habitat loss various species can tolerate are almost 

impossible to make. Instead, one study recommended making qualitative predictions on which 

types of habitats or wood types are most threatened. For instance, this study examined Sweden’s 

forest fuel extractions and concluded that coniferous wood can be harvested to a rather large 

extent, whereas deciduous tree species should be retained to a larger degree.54 As different 

regions will certainly have species specific to their own regions, more research is necessary to 

determine appropriate recommendations on maintaining biodiversity. 

Another issue that has been considered is the occurrence of soil disturbance due to the 

use of forest residue collection equipment. Studies have shown that the growth of woody plants 

and yields of harvestable plant products are decreased by soil compaction from residue collection 

equipment, because of the combined effects of high soil strength, decreased infiltration of water 

and poor soil aeration.55 In another study, the use of a residue bundling machine caused some 

measurable amounts of soil disturbance and an increase in “soil exposed” area at some 

locations.56 Thus, it is important to limit the severity of soil disturbances with minimal passes 

and relatively low ground pressure. 

Energy Content of Forest Residue and Biofuel 

Woody material obtained by the harvesting or thinning of forest is somewhat more 

energy dense compared to other forms of biomass. On its Biomass Program webpage, the 

Department of Energy lists the higher heating values (lower heating values were not available) 

for many different types of biomass for dry samples.57 These values for woody biomass are 

summarized in Table 1.1-7. 

Table 1.1-7. Energy Content of Forest Material 

Tree name Higher Heating Value 

(BTU/lb dry wood) 

Hybrid Popular 8,384 - 8,491 

Black Locust 8,409 - 8,582 

Eucalyptus 8,384 - 8,432 

American Sycamore 8,354 - 8,481 

Eastern Cottonwood 8,431 

Monterey Pine 8,422 

Because woody material is energy dense, it can produce a large amount of renewable 

fuels per ton of feedstock. Based on the data in FASOM, we assumed that 89 gallons of ethanol 

could be produced per each ton of dry (15 percent moisture) woody feedstock in 2022. 

28
 
Quantity of Forest Residue 

The quantity of forest residue available to produce biofuels was estimated by two 

different studies. We summarize those two studies, and then summarize data which we received 

directly from the U.S. Forest Service 

Billion Ton Study 

A landmark assessment of the potential biomass available from existing forest land in the 

U.S. was recently conducted by the USDA and the Department of Energy (DOE).58 This 

landmark assessment was titled “Biomass as Feedstock for a Bioenergy and Bioproducts 

Industry: The Technical Feasibility of a Billion Ton Supply,” which is also known as the Billion 

Ton Study. We reviewed this study and are summarizing much of the information contained in 

that report here because it is very useful background about U.S. forest land and its potential 

contribution to biofuels. 

The total forest inventory is estimated to be about 20.2 billion dry tons. The report 

authors estimated that about 2.2 percent of the total forest inventory is harvested each year, 

which corresponds to 444 million dry tons. This removal rate is estimated to be less than the 

annual average forest growth, which suggests, at least on an aggregate basis, that this removal 

rate is sustainable. It is estimated that 78 percent of this removal was for roundwood products 

(sawlogs, pulpwood, veneer logs and fuel wood), 16 percent was logging residue and about 6 

percent was classified as other removals. Thus, the Billion Ton study authors estimate that 67 

million dry tons of logging residue would potentially be available for biofuel production, which 

is comprised of 49 million dry tons of primary logging residue, and 18 million dry tons of other 

removals. The Billion Ton study estimates that 65 percent of the total logging and other residue 

would be recovered for use. The two reasons cited for not collecting the other 35 percent is that 

some of the logging residue is comprised of small pieces, such as small branches and leaves, 

which would not be economically recoverable, and that it would be necessary leave behind a 

portion of the logging residue would be to protect the sustainability of the forest as well as the 

wildlife which thrives in the forest. For these reasons, the Billion Ton Study authors estimated 

that 41 million dry tons of forest residue could be sustainably removed from the U.S. forests as 

byproduct from existing logging operations. Virtually all this removal is from privately owned 

land where the logging operations occur today. 

Additional forest residue is available downstream of the logging operations at mills. In 

the process of making their products, primary wood processing mills create some waste or 

residue. However, almost all of this waste wood is recovered or burned for process heat. For 

example, the bark from the logged wood is burned as fuel or converted into mulch. However, 

the Billion Ton authors estimated that just under 2 million dry tons per year of residue would be 

available from the primary wood processing mills as feedstock for producing biofuels. 

The Billion Ton study estimates that additional wood waste could also be available from 

secondary wood processing mills, which refine crude wood into more refined products. The 

report authors could not find any data on how much residue is produced by these secondary 

wood processing mills, however, a study of these facilities did provide an estimate. 

29
 
 

Approximately 15.6 million dry tons per year would be available from the smaller of these 

secondary wood processing mills, however, the report estimated that only 40 percent, or 6 

million dry tons per year, would be available for biofuels production. 

Another industry which processes the harvested wood is the pulp and paper mills. These 

companies process wood into fiber to make paper and cardboard. Most of the pulp and paper 

mills use the Kraft process or sulfate pulping process which converts half of the woody material 

into fiber, while the other half is a byproduct termed black liquor. The black liquor contains a 

substantial amount of biomass. The pulp and paper industry is already using all of this black 

liquor, plus purchasing and using some fossil fuels, to generate the electricity and heat that it 

needs for its plants. Therefore, the authors of the Billion Ton Study estimated that there would 

not be any residue available from the pulp and paper industry to produce biofuels. 

The Billion Ton study estimates that another potential source of biomass from forests 

would be the selective thinning of forests to help reduce the risk of fire, or to facilitate the 

fighting of fires in the case that fires break out (as discussed above). Using a forest evaluation 

tool called the Fuel Treatment Evaluator, the Forest Service has estimated tree densities for 

forests all across the U.S. and has identified forests which contain excess woody material. The 

forests which contain excess woody material are candidates for providing additional biomass for 

producing biofuels. The Forest Service has estimated that the total amount of excess woody 

material to be 8.4 billion dry tons. 

The Forest Service next estimated the portion of this excess woody material that could be 

harvested for biofuels production. Despite the fact that this inventory exists today, the Billion 

Ton Study authors assumed that this excess woody inventory would be used over a 30 year 

period to reflect a sustainable removal rate. This assumption reduces the total yearly available 

amount of excess woody biomass to 280 million dry tons per year. Another limiting factor is 

that much of our nations forest is remote, thus, only 60 percent of this excess woody material 

was estimated to be removable for use. The next assumption made is that the best of this woody 

material, which is the woody material more than 5 inches in diameter and which comprises 70 

percent of this material, would be used for feedstock for the logging industry. Thus, the 

remaining 30 percent would be residue that would serve as feedstock for the biofuels industry. 

Finally, the last assumption made is that of the excess woody material harvested, 15 percent 

would be lost between harvesting and use, thus the total amount of woody biomass was adjusted 

to be 15 percent lower. These assumptions result in 18 million dry tons of additional woody 

biomass that could be used to supply the biofuels industry annually, and 42 million dry tons that 

would supply the logging industry. 

As shown below in Table 1.1-8, the Billion Ton Study estimates that a total of 67 million 

try tonnes per year would be available from non-urban forests. 

30
 
Table 1.1-8. 

Quantity of Forest Biomass Available for Producing Biofuels 

Quantity 

(million dry tons) 

Logging Residue 41 

Primary Mill Residue 2 

Secondary Mill Residue 6 

Forest Thinnings 18 

Total 67 

The Billion Ton Study authors projected that forest harvesting and mill activity will 

increase in the future, thus increasing the amount of forest residues that would be available for 

producing biofuels. The authors estimated the future forest residue supply in the year 2050 and 

concluded that the logging residue is expected to increase from 41 million dry tons to 64 million 

dry tons. Also in 2050, the primary and secondary mill residue quantity is projected to increase 

from a total of 8 million dry tons per year to a total of 24 million dry tons per year. No estimate 

was provided for any increase, or decrease, in the amount of forest woody material that would be 

available from thinning forests. If the projected 39 million dry ton increases in forest residue 

comes to fruition, then the total amount of forest residue that would be available for producing 

biofuels in 2050 would be 106 million dry tons per year. We are primarily interested in 

compliance with the RFS2 biofuels standard in 2022, which is just over 1/3rd of the way between 

today and 2050. Thus, by interpolating the projected future forest residue in 2022 relative to 

current levels and those in 2050, the report supports the conclusion that 79 million dry tons of 

forest residue would be available in 2022 . 

U.S. Cellulosic Biomass Study 

Another estimate for the amount of forest residue that could be used to produce biofuels 

was made by Marie Walsh, formerly of the Oak Ridge National Laboratory (ORNL).59 The 

report was titled “US Cellulosic Biomass Supplies and Distribution” and it is dated January of 

2008. This report also uses the Forest Service data base for its estimates, so its conclusions 

resemble those of the Billion Ton study. However, an important difference between this 

Cellulosic Biomass Study and the Billion Ton Study is that Marie Walsh estimated a cost curve 

for amount of biomass available for her Cellulosic Biomass study for multiple future years. 

In this report, Marie Walsh estimates that 63 million dry tons of logging residue is 

created in the lower 48 states. Of this total amount of logging residue, 65 percent is estimated to 

be accessible by roads, and not all the accessible logging residue is considered recoverable 

because some of it is too small to recover. This study also estimates the cost for recovering this 

available logging residue for future years for five year intervals through 2030. The amount of 

logging residue available at different price points and for different years is summarized in Table 

1.1-9. 

31
 
 

 

Table 1.1-9. Quantity of Logging Residue Available at Varying Prices 

$20/dt $25/dt $30/dt $35/dt $40/dt $45/dt $50/dt $75/dt $100/dt 

2007 0.06 1.84 6.22 10.89 24.02 31.29 31.29 36.19 38.50 

2010 0.065 1.81 6.41 13.23 29.37 38.70 38.70 45.02 47.89 

2015 0.065 1.95 6.80 13.62 29.99 39.35 39.35 45.71 48.60 

2020 0.067 2.10 7.22 14.41 31.51 41.20 41.20 47.79 50.77 

2025 0.067 2.17 7.46 14.81 32.32 42.19 42.19 48.90 51.95 

2030 0.068 2.25 7.70 15.22 33.12 43.17 43.17 50.01 53.13 

Marie Walsh also identified the quantity of woody material that would be available at 

specific prices from other removal supplies – trees removed to make way for the construction of 

buildings. Marie Walsh estimates that a total of approximately 24 million dry tons of forest 

residue falls within this category. She estimated that perhaps 50 percent of this material would 

be available for biofuel production. Marie Walsh added the other removal supplies to the 

logging residue and estimated their availability at different price points, increasing the available 

biomass by 25 percent. The combined total is summarized in Table 1.1-10. 

Table 1.1-10. 

Quantity of Forest Residue and Other Removals Available at Varying Prices 

$20/dt $25/dt $30/dt $35/dt $40/dt $45/dt $50/dt $75/dt $100/dt 

2007 0.09 2.63 10.49 15.16 32.16 41.62 41.62 47.71 50.49 

2010 0.09 2.63 10.76 17.59 38.08 49.17 49.17 56.68 60.03 

2015 0.09 2.79 11.26 18.08 38.87 50.00 50.00 57.56 60.93 

2020 0.09 2.96 11.80 19.00 40.58 52.04 52.04 59.84 63.31 

2025 0.10 3.07 12.15 19.50 41.56 53.21 53.21 61.15 64.68 

2030 0.10 3.17 12.51 30.02 42.55 54.39 54.39 62.47 66.07 

This report also estimates the amount of primary and secondary mill residues available 

for biofuels production. Like the Billion Ton study, Marie Walsh also concludes that only a very 

small amount of primary mill residue is estimated to be currently unused and available for 

producing biofuels. She concludes that out of the 88.7 million dry tons of primary mill residue 

which are generated, that only 1.3 million dry tons is not used for fuel, fiber or other sources as 

discussed above. However, she provides an additional assessment that, at the right price, the 

primary mill residue could be drawn away from these other users of the primary mill residue. 

The assumption is that for fiber uses, the primary mill residue could be drawn away from the 

current users at 35% of the product price. For other uses, including for fuel, it is assumed that at 

65% of the market price of the raw wood value, the primary mill residue could be purchased 

away from the current users. Table 1.1-11 below estimates the price that specific estimated 

primary mill residue volumes could be available for producing biofuels. 

32
 
 

 

Table 1.1-11. 

Quantity of Primary Mill Residue is Available at Varying Prices
 

$20/dt $25/dt $30/dt $35/dt $40/dt $45/dt $50/dt $75/dt $100/dt 

2007 0.43 4.93 6.03 19.34 20.14 41.46 42.38 50.31 51.04 

2010 0.55 5.70 7.29 21.91 22.80 46.03 47.37 56.29 57.33 

2015 0.56 5.93 7.51 22.88 23.77 48.00 49.34 58.55 59.61 

2020 0.58 6.16 7.74 23.85 24.73 49.97 51.31 60.82 61.88 

2025 0.59 6.34 7.93 24.58 25.47 51.46 52.82 62.55 63.61 

2030 0.60 6.52 8.12 25.31 26.20 52.96 54.31 64.28 65.35 

The author also attempted to estimate the amount of secondary mill residue that could be 

available for producing biofuels. She observed that data is scant on the amount of secondary 

mill residue. She referenced a study (Rooney, 1998) that estimated that only a very small 

volume of secondary mill residue would be available for producing biofuels. Of 12.5 million dry 

tons of secondary mill residue which is generated, only 1.2 million dry tons is available for 

producing biofuels. Unlike the analysis conducted for primary mill residue, the author did not 

attempt to estimate the extent that biofuels producers could bid the secondary mill residue away 

from the current users. 

Marie Walsh also assumes that three very difficult-to-quantify sources of forest material 

could be available as biomass for producing biofuels. One of these potential sources is the forest 

material that could be available through the thinning of overgrown forests to help reduce the fire 

risk within these forests. Marie Walsh referenced one study which estimated that 100 to 200 

million acres of overgrown forest could be harvested. No estimate, however, was provided for 

the amount of this forest material that could be available from forest thinning. 

Another potential source of forest material for biofuel production that the study discussed 

is a portion of the estimated 35.4 million tons of fuel wood used to heat homes and to provide 

heat for industries. The author cited a report which estimated that fuel wood use decreased from 

1986 to 2000, but began to increase again and is expected to increase through 2050. This 

presumably means that if the demand for fuel wood is lower than previously, that some of that 

fuel wood could be available for producing biofuels. However, in this report, Marie Walsh did 

not make any firm estimate for this. 

The Marie Walsh report also discussed that forest pulpwood supply is exceeding demand 

in the Southeast. The demand of forest pulpwood decreased from 131 to 121 million tons per 

year from 1993 to 2003, and this demand is expected to further decrease through 2020, and some 

have projected that this decrease in demand will continue beyond 2020. During the period 

between 1993 and 2003, pulpwood acreage and management intensity have increased, which 

suggests that the Southeast is and will continue to be over supplied. This oversupply of forest 

pulpwood could potentially provide additional biomass to the biofuels industry, although she did 

not provide any firm estimate for this. 

While both of these studies provide quality assessments for the total amount of forest 

residue available for producing biomass, they both have an important limitation as well. The 

33
 
limitation is that these reports did not assess whether the forest residue in any particular area, 

along with other potential biomass, is of sufficient density to adequately supply a potential 

cellulosic biofuel plant. This feedstock density assessment must also consider the feedstock 

availability requirements made by cellulosic plant investors or banks, which may choose to 

require that a certain excess amount of feedstock be available to justify the use of that biomass in 

a cellulosic ethanol plant. Without considering these limitations, these studies may overestimate 

the quantity of biomass that would be truly usable and also the ultimate amount of biofuel that 

could be produced. 

U.S. Forest Service Data 

To assess forest residue supply within the feedstock density and supply constraints, we 

obtained county-by-county forest residue data from the U.S. Forest Service.60 The information 

was provided by the subcategories of logging residue, primary mill residue, timberland 

thinnings, and other removals. The information also included urban forest residue, however, 

because that material is included with the other MSW, we did not consider it here. Like the 

studies discussed above, the national forest lands are omitted from consideration, and the urban 

forest residue is not considered here, but in the section discussing MSW. The information was 

also provided at different price points. The quantities of forest residues are summarized by 

source type in Tables 1.1-12, 1.1-13 and 1.1-14. To avoid presenting a huge amount of data, we 

aggregated the county data by state, and we are presenting the data at specific price points: 

$30/dry ton, $45/dry ton and $70/dry ton. 

34
 
 

Table 1.1-12. 

Volume of Forest Residue Available for Producing Biofuel 

Biomass Available at $30/ton 

Logging 

Residue 

Other 

Removals 

Timberland 

Thinnings 

Primary 

Mill Residue 

Total 

Quantity 

Alabama 2,405,083 507,240 867,038 7,117 3,786,478 

Arizona 17,698 44,871 66,171 1,351 130,091 

Arkansas 1,703,543 770,985 738,165 12,889 3,225,582 

California 669,740 0 1,742,702 65,088 2,477,530 

Colorado 18,405 14 0 2,302 20,721 

Connecticut 8,391 30,678 20,929 3,949 63,948 

Delaware 30,101 24,218 9,835 0 64,155 

Florida 1,070,430 515,407 481,893 2,202 2,069,932 

Georgia 3,113,907 993,262 1,107,254 45,138 5,259,561 

Idaho 253,145 0 83,095 6,006 342,247 

Illinois 278,202 235,178 230,863 18,523 762,766 

Indiana 562,483 104,173 396,225 10,627 1,073,508 

Iowa 112,098 55,160 97,983 159 265,400 

Kansas 14,658 88,405 19,353 8,720 131,136 

Kentucky 1,027,977 664,358 689,896 55,196 2,437,427 

Louisiana 2,634,279 880,585 601,848 30,075 4,146,788 

Maine 2,412,877 940 160,628 42,483 2,616,927 

Maryland 181,443 830 81,988 17,067 281,327 

Massachusetts 70,921 62,087 27,602 0 160,610 

Michigan 758,926 244,952 655,280 13,763 1,672,922 

Minnesota 697,614 662,985 265,424 26,878 1,652,900 

Mississippi 3,097,069 710,142 850,688 95,138 4,753,038 

Missouri 774,868 530,292 684,154 79,787 2,069,100 

Montana 262,670 0 133,185 9,136 404,990 

Nebraska 21,145 18,771 23,414 4,971 68,302 

Nevada 29 105 0 0 134 

New Hampshire 314,642 348 95,604 7,019 417,613 

New Jersey 5,918 77 4,847 1,437 12,279 

New Mexico 23,858 2,557 51,796 4,902 83,113 

New York 734,006 109,342 326,672 27,390 1,197,410 

North Carolina 2,026,330 1,259,265 1,121,627 12,811 4,420,033 

North Dakota 2,906 15,202 7,644 265 26,017 

Ohio 370,795 18,106 167,351 22,600 578,853 

Oklahoma 347,738 197,587 106,086 495 651,906 

Oregon 1,520,552 63 1,055,405 16,316 2,592,335 

Pennsylvania 1,087,327 1,372 449,956 170,972 1,709,626 

Rhode Island 1,769 45,721 5,600 389 53,478 

South Carolina 1,429,102 696,577 603,700 1,051 2,730,431 

South Dakota 13,944 28,873 5,986 2,294 51,096 

Tennessee 633,412 489,840 847,812 187,583 2,158,647 

Texas 1,233,553 436,927 371,437 3,021 2,044,938 

Utah 5,946 0 19,817 4,437 30,200 

Vermont 209,752 37,304 96,790 0 343,845 

Virginia 1,483,346 813,600 873,740 39,366 3,210,052 

Washington 1,282,288 44 1,850,958 21,446 3,154,736 

West Virginia 976,712 49,428 323,306 118,779 1,468,225 

Wisconsin 1,137,600 982,264 520,587 60,410 2,700,862 

Wyoming 22,685 0 28,100 34,014 84,799 

Total 37,061,885 12,330,137 18,970,435 1,295,560 69,658,018 

35
 
Table 1.1-13. 

Tons of Forest Residue Available for Producing Biofuel 

Biomass Available at $45/ton 

Logging 

Residue 

Other 

Removals 

Timberland 

Thinnings 

Primary 

Mill Residue 

Total 

Quantity 

Alabama 2,405,083 507,240 1,012,090 7,117 3,931,530 

Arizona 27,131 49,020 69,934 1,351 147,436 

Arkansas 1,703,543 770,985 858,827 12,889 3,346,244 

California 1,166,955 0 1,898,937 65,088 3,130,980 

Colorado 20,112 22 61,238 2,302 83,674 

Connecticut 8,601 32,190 20,929 3,949 65,670 

Delaware 35,863 28,290 13,400 0 77,554 

Florida 1,070,430 515,407 533,194 2,202 2,121,234 

Georgia 3,113,907 993,262 1,288,591 45,138 5,440,898 

Idaho 432,605 0 105,188 6,006 543,799 

Illinois 278,305 235,178 230,863 18,523 762,869 

Indiana 562,928 104,173 443,691 10,627 1,121,419 

Iowa 112,100 55,215 99,102 159 266,576 

Kansas 14,658 88,405 19,353 8,720 131,136 

Kentucky 1,027,977 664,358 814,743 55,196 2,562,273 

Louisiana 2,634,279 880,585 661,023 30,075 4,205,963 

Maine 2,561,023 989 204,885 42,483 2,809,379 

Maryland 189,159 842 81,988 17,067 289,054 

Massachusetts 78,254 66,382 27,602 0 172,239 

Michigan 783,465 257,201 820,603 13,763 1,875,033 

Minnesota 717,037 683,787 319,980 26,878 1,747,683 

Mississippi 3,097,069 710,142 935,870 95,138 4,838,219 

Missouri 774,868 530,292 932,163 79,787 2,317,110 

Montana 431,194 0 141,549 9,136 581,879 

Nebraska 21,419 18,867 23,414 4,971 68,672 

Nevada 44 142 0 0 186 

New Hampshire 331,037 395 115,132 7,019 453,583 

New Jersey 6,368 79 4,847 1,437 12,731 

New Mexico 34,478 2,575 53,724 4,902 95,679 

New York 768,914 113,104 379,391 27,390 1,288,799 

North Carolina 2,026,330 1,259,265 1,336,840 12,811 4,635,245 

North Dakota 2,907 15,202 7,644 265 26,018 

Ohio 372,045 18,139 177,144 22,600 589,927 

Oklahoma 347,738 197,587 125,400 495 671,220 

Oregon 2,502,187 68 1,095,253 16,316 3,613,824 

Pennsylvania 1,092,836 1,386 604,355 170,972 1,869,549 

Rhode Island 1,913 50,079 5,600 389 57,981 

South Carolina 1,429,102 696,577 704,036 1,051 2,830,767 

South Dakota 23,743 31,161 6,505 2,294 63,704 

Tennessee 633,412 489,840 1,015,395 187,583 2,326,230 

Texas 1,233,553 436,927 438,374 3,021 2,111,876 

Utah 7,515 0 21,571 4,437 33,524 

Vermont 217,084 38,363 107,673 0 363,120 

Virginia 1,483,346 813,600 1,048,745 39,366 3,385,057 

Washington 2,135,174 46 1,963,678 21,446 4,120,344 

West Virginia 976,712 49,428 482,367 118,779 1,627,287 

Wisconsin 1,153,876 998,604 654,054 60,410 2,866,943 

Wyoming 36,327 0 36,405 34,014 106,745 

Total 40,084,609 12,405,402 22,003,291 1,295,560 75,788,862 

36
 
Table 1.1-14. 

Tons of forest residue Available for Producing Biofuels 

Biomass available at $70/ton 

Logging 

Residue 

Other 

Removals 

Timberland 

Thinnings 

Primary 

Mill Residue 

Total 

Quantity 

Alabama 2,405,083 507,240 1,163,309 7,117 4,082,749 

Arizona 27,131 49,020 77,357 1,351 154,859 

Arkansas 1,703,543 770,985 984,188 12,889 3,471,605 

California 1,166,955 0 2,001,231 65,088 3,233,274 

Colorado 20,112 22 61,238 2,302 83,674 

Connecticut 8,601 32,190 20,929 3,949 65,670 

Delaware 35,863 28,290 13,400 0 77,554 

Florida 1,070,430 515,407 664,706 2,202 2,252,745 

Georgia 3,113,907 993,262 1,553,823 45,138 5,706,130 

Idaho 432,605 0 123,852 6,006 562,463 

Illinois 278,305 235,178 230,863 18,523 762,869 

Indiana 562,928 104,173 443,691 10,627 1,121,419 

Iowa 112,100 55,215 99,102 159 266,576 

Kansas 14,658 88,405 19,353 8,720 131,136 

Kentucky 1,027,977 664,358 927,808 55,196 2,675,339 

Louisiana 2,634,279 880,585 750,104 30,075 4,295,044 

Maine 2,561,023 989 332,233 42,483 2,936,728 

Maryland 189,159 842 81,988 17,067 289,054 

Massachusetts 78,254 66,382 27,602 0 172,239 

Michigan 783,465 257,201 1,066,214 13,763 2,120,643 

Minnesota 717,037 683,787 401,197 26,878 1,828,900 

Mississippi 3,097,069 710,142 1,033,196 95,138 4,935,545 

Missouri 774,868 530,292 1,287,857 79,787 2,672,803 

Montana 431,194 0 166,045 9,136 606,375 

Nebraska 21,419 18,867 23,414 4,971 68,672 

Nevada 44 142 0 0 186 

New Hampshire 331,037 395 116,195 7,019 454,646 

New Jersey 6,368 79 4,847 1,437 12,731 

New Mexico 34,478 2,575 64,375 4,902 106,330 

New York 768,914 113,104 385,701 27,390 1,295,109 

North Carolina 2,026,330 1,259,265 1,600,910 12,811 4,899,315 

North Dakota 2,907 15,202 7,644 265 26,018 

Ohio 372,045 18,139 177,144 22,600 589,927 

Oklahoma 347,738 197,587 163,268 495 709,088 

Oregon 2,502,187 68 1,133,187 16,316 3,651,758 

Pennsylvania 1,092,836 1,386 680,995 170,972 1,946,189 

Rhode Island 1,913 50,079 5,600 389 57,981 

South Carolina 1,429,102 696,577 791,111 1,051 2,917,842 

South Dakota 23,743 31,161 8,258 2,294 65,457 

Tennessee 633,412 489,840 1,033,100 187,583 2,343,935 

Texas 1,233,553 436,927 507,340 3,021 2,180,841 

Utah 7,515 0 29,434 4,437 41,386 

Vermont 217,084 38,363 142,210 0 397,658 

Virginia 1,483,346 813,600 1,260,733 39,366 3,597,045 

Washington 2,135,174 46 2,059,970 21,446 4,216,636 

West Virginia 976,712 49,428 575,278 118,779 1,720,198 

Wisconsin 1,153,876 998,604 841,550 60,410 3,054,440 

Wyoming 36,327 0 43,195 34,014 113,536 

Total 40,084,609 12,405,402 25,186,746 1,295,560 78,972,317 

37
 
The U.S. Forest Service data reveals that there is a lot of forest material in the Southeast, 

the far Northeast and the Northwest portions of the U.S. The data also shows that the price curve 

for this forest material is fairly flat over the range summarized here. This suggests that the 

forests which are already accessible by roads provide access to low cost forest material from the 

thinning of timberland. However, to access more and more of the timberland, the costs ramp up 

quickly to gain access to more of the timberland. 

Summary 

We compared the quantity of potential biomass supplies projected to be available in 2022 

by the two studies and the data that the Forest Service provided us in Table 1.1-15. 

Table 1.1-15. 

Forest Biomass Availability in 2022 at Different Prices (million dry tons/yr) 

Price ($/ton) 30 45 70 

Billion Ton Study 79 

U.S. Cellulosic 

Biofuels 20 103 118 

Forest Service Data 70 76 79 

1.1.2.3 Urban wastes 

Cellulosic feedstocks available at the lowest cost to the ethanol producer will likely be 

chosen first. This suggests that urban waste which is already being gathered today and typically 

incurs a fee for its disposal may be among the first to be used. Urban wood wastes are used 

today in a variety of ways. Most commonly, wastes are ground into mulch, dumped into 

landfills, or incinerated with other MSW or construction and demolition (C&D) debris. 

Estimating the amount of urban waste available for biofuel production involves understanding 

the types of materials that can be found in urban waste, potential competing uses of urban waste, 

and the challenges with separating a mixed feedstock. 

1.1.2.3.1 Municipal Solid Waste 

MSW consists of paper, glass, metals, plastics, wood, yard trimmings, food scraps, 

rubber, leather, textiles, etc. See Figure 1.1-2 for the percent composition of MSW generated 

(before recycling) in 2006.61 Construction and demolition debris is not included in the estimate. 

38
 
 

 

Figure 1.1-2. 

Total MSW Generation (by Material), 2006 

251 Million Tons (Before Recycling). 

The portion of MSW containing cellulosic material and typically the focus for biofuel 

production is wood and yard trimmings. In addition, paper, which made up approximately 34 

percent of the total MSW generated in 2006, could potentially be converted to cellulosic biofuel. 

Food scraps could also be converted to cellulosic biofuel, however, it was noted by an industry 

group that this feedstock could be more difficult to convert to biofuel due to challenges with 

separation and the materials degrading. 

Although recycling/recovery rates are increasing over time, there appears to still be a 

large fraction of biogenic material that ends up unused and in landfills. In order to project the 

portion of material that can potentially be used for biofuel purposes, we must understand how the 

composition of landfilled material changes over time. To do this, we first analyzed the trends 

from 1960-2006 for the percent composition of total MSW generated from paper/paperboard, 

wood, and yard trimmings over time as shown in Table 1.1-16 in order to project the percent 

composition of total MSW generated for the year 2022 for those categories (i.e. calculated to be 

26.9% paper, 5.5% wood, and 12.7% yard trimmings).62 In general, there appears to be a 

decrease in the percentage of total MSW generated from paper and yard trimmings while the 

composition of wood relatively remained stable. 

Table 1.1-16. Percent Composition of Total MSW Generated 

(including recyclable material): Paper, Wood, and Yard Trimmings 

1960 1970 1980 1990 2000 2002 2004 2005 2006 ... 2022 

Material 

Paper/paperboard 34 36.6 36.4 35.4 36.8 35.1 35.1 34.3 33.9 ... 26.9 

Wood 3.4 3.1 4.6 6.0 5.5 5.6 5.5 5.6 5.5 ... 5.5 

Yard Trimmings 22.7 19.2 18.1 17.1 12.8 13.0 12.7 12.9 12.9 ... 12.7 

We also analyzed the trends from 1960-2006 for the percent composition of total MSW 

discarded (i.e. after recycling has occurred) to project the percent compositions for the year 2022 

39 
 

 

 

(i.e. calculated to be 11% paper, 8% wood, and 2% yard trimmings), see Table 1.1-17 and Table 

1.1-18. Comparing Table 1.1-16 and Table 1.1-17, we note that there is a lower percent of paper 

and yard trimmings that is discarded than generated for MSW. This makes sense because a large 

percentage of these materials are recycled. Other than recycling, some MSW material is also 

combusted for energy use. This material we assume would be unavailable for biofuel use, and 

therefore report in Table 1.1-18 the percent composition of total MSW discarded after 

accounting for both recycling and combustion for energy use. Therefore, we have taken into 

account MSW that could potentially be diverted towards recycling instead of future biofuel 

production. 

Table 1.1-17. Percent Composition of Total MSW Discarded 

(not including recycled material): Paper, Wood, and Yard Trimmings 

1960 1970 1980 1990 2000 2002 2004 2005 2006 

Material 

Paper/paperboard 30.2 33.2 31.7 30.5 29.7 27.3 27.3 25.5 24.3 

Wood 3.7 3.3 5.1 7.0 7.0 7.2 7.3 7.4 7.4 

Yard Trimmings 24.2 20.5 20.1 17.9 8.7 9.0 7.0 7.2 7.3 

Table 1.1-18. Percent Composition of Total MSW Discarded 

(not including recycled or combusted material): Paper, Wood, and Yard Trimmings 

1960 1970 1980 1990 2000 2002 2004 2005 2006 ... 2022 

Material 

Paper/paperboard 30.2 33.1 28.8 26.1 25.5 23.5 23.5 22.1 21.3 ... 11.2 

Wood 3.7 3.3 4.6 6.0 6.0 6.2 6.3 6.4 6.5 ... 7.6 

Yard Trimmings 24.2 20.4 18.3 15.3 7.5 7.7 6.0 6.2 6.4 ... 1.9 

The total amount of MSW generated (prior to recycling) is assumed to increase over time 

due to population growth. Biocycle magazine (2006) reports MSW estimates for each state in 

the U.S. based off of 2004 population data.63 We used U.S. Census Bureau population 

projections by state to scale up or down the MSW estimates depending on whether the state 

populations increase or decrease by 2022. The total amount of MSW generated (prior to 

recycling) was estimated to be 391 million tons. As we are interested in the volume of MSW 

available for biofuel use, we focused only on waste estimated to be landfilled, which is a portion 

of the total MSW generated. We used estimates on the percentage of MSW landfilled by state 

from Biocycle in order to estimate the amount of MSW potentially available to biofuels (after 

recycling). 

Knowing the total amount of MSW landfilled is only part of the picture. We also need to 

understand the types of cellulosic material likely to make up the MSW landfilled. For this, we 

were able to gather state composition data (i.e. percent wood vs. paper vs. other materials) of 

landfills for MSW generated, however, we were in fact interested in acquiring state composition 

64,65,66,67,68,69,70,71,72,73,74 data for the MSW landfilled. Using the state composition data, we 

estimated the percent composition of MSW landfilled by state using a ratio of percent 

composition of national material generated (estimated in Table 1.1-16) and landfilled (estimated 

in Table 1.1-18) and state percent composition data for MSW generated (gathered from the 

40
 
multiple state reports). We then multiplied the volume of MSW (in tons) generated for each 

state in the year 2022 by the percent of MSW estimated to be landfilled (provided in Biocycle) 

and by the percent composition of MSW landfilled by state. Some states did not provide 

composition data, therefore, we estimated average percentages based on the states within a 

similar location in the U.S. where data was provided (e.g. if Utah data was unavailable, we 

assumed compositions would be similar to other rocky mountain states). 

Furthermore, the amount of MSW potentially available is limited by assumptions on 

percent moisture and percent contamination. We assumed that paper, wood, and yard trimmings 

have a 10%, 20%, and 40% moisture content, respectively.75,76 We also assumed that wood is 

approximately 50% contaminated, due to objects such as nails, paint, chemicals, etc. typically 

associated with such feedstocks. Paper and yard trimmings are assumed to be mostly 

uncontaminated, assuming 75% uncontaminated. We account for contamination because it is 

likely to affect the quality of the wood waste and could potentially cause problems in the 

processing steps of cellulosic material to biofuel. Thus, for this analysis we assumed that the 

estimated contaminated portions would not be used for biofuel production. In addition, not all 

yard trimming can be assumed to be wood, only 25% is assumed to be from wood. 77 We 

estimate that 22 million tons could be available from paper, 0.2 million tons from yard trimmings 

and 4 million tons from wood. 

At the time of this proposal we did not include food scraps in our estimates for urban 

wastes as this source was observed to have difficulties in separation and more easily degraded, 

making an assessment of this feedstock complex. Food scraps made up 12.4% of the total MSW 

generated in 2006, meaning that potentially 31 million tons (and perhaps more by the year 2022) 

could be available for cellulosic biofuel production. 

1.1.2.3.2 Construction and Demolition (C&D) Debris 

C&D debris mostly comes from building demolition and renovation, and the rest comes 

from new construction.78 Roughly equal percentages of building-related waste are estimated to 

come from the residential and commercial building sectors. The composition of C&D materials 

varies significantly, depending on the type of project from which it is being generated. For 

example, materials from older buildings is likely to contain plaster and lead piping, while new 

construction materials may contain significant amounts of drywall, laminates, and plastics. For 

building materials, EPA estimates the overall percentage of debris in C&D materials falls within 

the following ranges: 

41
 
Table 1.1-19. 

Percentage Composition of C&D Debris 

(by volume) 

Concrete and mixed rubble 40-50% 

Wood 20-30% 

Drywall 5-15% 

Asphalt roofing 1-10% 

Metals 1-5% 

Bricks 1-5% 

Plastics 1-5% 

In 1996, total C&D debris generated was estimated to be approximately124 million 

metric tons.79 As seen in Table 1.1-19 above, only a portion of this, however, would be made of 

woody material. We based our estimate of C&D wood in 2022 on the equation adopted from 

Wiltsee’s analysis.80 The equation estimated C&D wood based on population size. We estimated 

approximately 31 million tons could be available from this resource by 2022; however, we 

assumed that 50% of that could potentially be contaminated. Thus, we estimate that only 15.4 

million tons would be available for biofuels. 

1.1.2.4 Dedicated Energy Crops 

Crops developed and grown specifically as a renewable source of cellulosic material for 

biofuel production are not yet commercial, but have the potential for negating some of the 

problems surrounding other feedstocks. Currently, crops such as corn that are grown and 

harvested for energy uses in the United States are also used for agricultural purposes and serve 

many important uses other than biofuel production. This competition could be reduced by the 

use of non-agricultural feedstocks for cellulosic biofuel production. Urban wastes and forest and 

agriculture residues will likely be the first feedstocks used in cellulosic biofuel production; 

However, there are many uncertainties over land availability and sustainable removal rates for 

residues. 

Most energy crops will be perennial species grown from roots or rhizomes that remain in 

the ground after harvesting the above-ground biomass. While most agricultural crops are annual 

species, perennials are considered beneficial in many ways. Dedicated perennial energy crops 

have the potential to grow on marginal lands, produce high yields, and may have low input 

needs. Once a perennial crop is established costs are reduced, as the need for tillage is lowered. 

The root system that remains in the soil can also facilitate the acquisition of nutrients thus 

decreasing the need for large fertilizer inputs. In southern climates, perennials have the potential 

for higher yield per acre of land than other annual crops. This is due to the fact that perennial 

plants develop more quickly in the spring and the canopy of foliage can sustain for longer in the 

fall. This makes it possible for the plants to be more photosynthetically active and have a more 

efficient energy conversion system. Perennial energy crops also increase soil productivity, 

sequester carbon, and provide refuge for wildlife. 

42
 
 

 

 

1.1.2.4.1 Types of Energy Crops 

The following sections describe several of the most commonly discussed dedicated 

energy crops (switchgrass, miscanthus, and hybrid poplars) as well as some less familiarly 

known crops. 

1.1.2.4.1.1 Switchgrass 

The energy crop that has received the most attention is switchgrass. Switchgrass 

(Panicum virgatum) is perennial warm season grass that is native to the United States. It 

typically reaches heights of 3-5 feet, but can grow to more than 10 feet in some southern regions. 

It has a deep root system that extends many feet below the earth. It may be the ideal energy crop 

mainly because it can tolerate many soil types and climates from drought conditions to floods. It 

is also resistant to many pests and diseases. The photosynthetic pathway of switchgrass (and 

other perennials) allows it to produce high biomass yields with low amounts of chemical input. 

In the spring, switchgrass develops a photosynthetic canopy of biomass more quickly, and it also 

persists longer in the fall than annual plants, allowing for a high net conversion of solar energy 

81 per year.

Highly variable yields have been estimated at 1-12 dry tons/acre per year (3-30 dry 

tons/ha) depending on soil, location, and variety. A yield of 4-5.5 tons/acre (10-13 tons/ha) is a 

reasonable commercial average today.82 In a long term study sponsored by the DOE, average 

yield after 10 years of growth was 4.8-7.6 tons/acre (12-19 tons/ha) for switchgrass when 

harvested annually.H,83 Biannual harvests were also done experimentally to try and achieve the 

maximum yields possible but show little difference in total yield. Biannual harvests result in 

approximately 70% of the yield for the first cut and 30% for the second.84 

Water and nitrogen availability are the main resources that limit production of warmweather grasses such as switchgrass. Nitrogen accessibility for these plants depends on many 

factors. Harvesting frequency, soil content, and removal rates all affect the nitrogen available to 

the plant. In the previously mentioned study by S.B. McLaughlin, initial nitrogen fertilization 

rates were 40-120 kg/acre (36-107 lbs/acre); however they discovered that a reduction to only 20 

kg/ha (17.8 lbs/acre) of nitrogen was sufficient to produce similar yields in single cut systems in 

the mid-Atlantic region.85 Reduced nitrogen amounts were similar in other regions of the 

country. In comparison, the US fertilization rate for corn is an average of 138 lbs/acre. 

With commercial growth of switchgrass, growers would sell the crop for conversion to 

cellulosic ethanol. Our economic modeling shows that in order to meet the cellulosic biofuel 

goal of 16 Bgal set by the EISA mandates, dedicated energy crops will need to be utilized.I 

H Switchgrass variety used in this study was Alamo. Other varieties could result in different yields. 

I

 Assuming 16 Bgal cellulosic biofuel total, 2.2 Bgal from urban waste, and 3.8 Bgal from forestry biomass; 10 Bgal 

of cellulosic biofuel for ag residues and/or energy crops would be needed. 

43
 
 

 

1.1.2.4.1.2 Miscanthus 

Miscanthus is a tall perennial grass that has been evaluated as a potential energy crop 

most extensively in Europe where it is already being produced for biofuel. The genus is 

primarily tropic or sub-tropic in origin but there is a wide climactic range at the species level.86 

This characteristic makes it more suitable for establishment over the ranging climates of North 

America. Giant miscanthus (Miscanthus x gigantus) is a hybrid variety that can grow 12-14 feet 

tall. It is a cold-tolerant warm season grass and has similar characteristics of switchgrass with 

high yields and low amounts of input.87 

Research on miscanthus is currently being conducted at the University of Illinois. In the 

Midwest, the growing season is April to October. The plant grows large green foliage that 

maximizes in approximately late August. As the temperature falls the foliage fades and drops off 

leaving the stem. The stem is the commercially important part of the plant and resembles 

bamboo. Stems can reach nine feet in length, 1⁄2 to 3⁄4 in diameter, and are harvested in the winter 

after drying occurs.88 

Establishment of a crop takes approximately 2 years, with maximum yields reached in the 

third year depending on soil fertility. The grass could require 4-5 years on low quality soils. In 

established crops 5-10 shoots per square foot can be developed. Yields in various studies from 

the University of Illinois were 9-16 tons/acre in various regions in Illinois. The southern regions 

of the state with poor soil quality also saw high yields illustrating that miscanthus is suitable for 

growth and high achievable yields on marginal land.89 Yields in Europe ranged widely, with 

irrigated crops reaching12 tons/acre and un-irrigated yields of 4-10 tons/acre in the fall. 

According to trials conducted in Europe, the quality of miscanthus biomass for conversion to 

biofuel improves by delaying harvesting until after the winter months and the plant has time to 

dry sufficiently. However, this reduced yields by 30 percent. 90 In comparison to switchgrass, 

research out of Illinois also concluded that miscanthus can yield more biomass for conversion to 

biofuel because of its even higher photosynthetic efficiency and longer growing season.91 In 

terms of input, miscanthus uses nitrogen extremely efficiently and therefore does not need to be 

fertilized for high yields to be achieved. There is also no need for pesticides; however, 

herbicides have been used to control weed populations.92 

Challenges in growing and producing miscanthus crop include high establishment costs, 

problems in winter survival during the first year, and high water needs. European cost estimates 

are similar to other perennial plants at approximately $64 per dry ton; however they estimate 

that a growing cycle of 10-12 years is required to recover the start-up costs of $267 per planted 

acre.93 The bulk of the high initial cost comes from planting and harvesting machinery. 

Establishment of a stronger market for growing these energy crops, as well as increased 

knowledge of propagation of the species, will inevitably lower overhead costs.94 

1.1.2.4.1.3 Hybrid Poplar 

The poplar tree (Populus trichocarpa) is another option being investigated for use as a 

dedicated energy crop. Herbaceous or woody perennial plants have some of the same 

characteristics of the perennial grasses that make them suitable for possible use as an energy 

44
 
 

 

crop. They retain significant amounts of root biomass below ground, require little tillage thus 

decreasing labor and erosion, grow fast large canopies, and require less fertilization than their 

agricultural counterparts. 

Technological advances in harvesting and genetics must be utilized in order to produce 

species that will be more suitable for use as an energy crop. Genetic information has helped to 

understand the characteristics the poplar tree. The complex genetic information obtained from 

the genome of this plant will make possible the engineering of faster growing trees with more 

biomass available for harvest.95 

1.1.2.4.1.4 Other Potential Feedstocks 

Several other perennial plants have the possibility to be used as dedicated energy crops. 

As previously described, the characteristics of perennial species make some optimal for use in 

this capacity. Because these plants have not been grown in agricultural sectors, they have not 

been extensively researched and developed for optimization. Corn is a crop that has been 

scientifically studied for decades because of its continued importance in the market. Dedicated 

energy crops must see this type of investment to bring about further knowledge of basic biology 

which will lead to advances in breeding and eventual domestication of the species that have 

promise. The DOE along with university research have implicated several other plants as 

potential energy crops. These include additional types of grasses such as reed canary grass and 

sorghum. Hybrid willow, silver maple, black locust, sweetgum, and eucalyptus are other 

perennial woody plants that are possibilities.96 

Significantly accelerated testing and selection for populations will be necessary in 

establishing these plants. Breeding for desired traits and adaptability across a wide array of 

environments in multiple physiologic and geographic regions will be necessary. No single 

species of dedicated energy plant will be optimal for all areas of the country, especially 

considering the amount of biofuels needed. Temperature, rainfall, and soil composition are 

highly variable across the continental United States; therefore, using a diverse group of plant 

species optimal for each growing region is a likely strategy. With current information and 

characteristics of each plant, the DOE has estimated where the possible growing areas could 

occur (see Figure 1.1-3). 97 

45
 
 

 Figure 1.1-3. 

 Possible Geographic Distribution of Dedicated Biomass Crops 

A U.S Department of Energy. Breaking the Biological Barriers to Cellulosic Ethanol: 

 A Joint Research Agenda. (2006). 

1.1.2.4.2 Land Assessment 

 There is evidence that perennial species are suitable for growth on marginal lands that 

are not useful for growth of food crops. A new study by Elliot Campbell out of Stanford 

University assessed abandoned land availability and the potential for this land to be used for 

energy crops. Because of the increased demand for biomass energy, using abandoned crop or 

pasture lands to grow some of these crops could be a better alternative than converting forested 

areas or using food agriculture lands. This study estimated the amount of global abandoned land 

available, the amount of biomass that could be grown on these lands, and the corresponding 

energy that could be obtained. Historical land use data, satellite imagery, and a global ecosystem 

model were used for the estimates. They considered “abandoned land” as land that was 

previously used for pasture or crops but has since been abandoned and not converted to urban or 

forested areas. Historical land use data was obtained from the History Database of the Global 

Environment 3.0 (HYDE) which consisted of gridded maps which show the fraction of crop and 

pasture land within each grid cell for decades between 1700 and 2000. Also, the Center for 

Sustainability and the Global Environment (SAGE) land use database was used to check and 

supplement the HYDE database. They used a MODIS satellite map to exclude areas that have 

transitioned into forest or urban areas. Two different mathematical approaches were then used to 

estimate a conservative and a high estimate of total land available. Biomass production was 

estimated using the Carnegie-Ames-Stanford Approach ecosystem model which takes into 

account climate data, soil texture, land cover and the normalized difference vegetation index 

(NDVI), but does not take into account fertilizer use or irrigation, which could increase yields 

(see Figure 1.1-4).98 

46
Figure 1.1-4. Global View of Crop and Pasture Abandoned Lands 

Obtained from: Campbell, J.E. at al. The global potential of bioenergy on abandoned agriculture lands. Environ. Sci. Technology. (2008). 

(A) SAGE supplemental data showing abandoned crop lands. (B) HYDE data showing crop lands that have been 

converted to uses other than cropping. (C) HYDE data showing former pasture lands that have been converted to 

uses other than for pasture. (D) HYDE data showing an average of total abandoned agriculture land (excludes areas 

of land use transition of crop to pasture, pasture to crop, agriculture to forest, and agriculture to urban). 

The low and high estimates for global abandoned land, excluding forested and urban 

areas are 385 and 472 million hectares. The authors found that these lands could produce 

between 1.6 and 2.1 billion tons of biomass respectively. In the United States an average of 

approximately 58 million ha (146 million acres) of abandoned land was estimated. Assuming 

natural growth on these lands, approximately 321 million tons/year of biomass could be 

produced. At 80 gallons of ethanol per ton of biomass, there would be the potential to produce 

approximately 26 billion gallons from a grass crop such as switchgrass. It is pointed out that 

there will be significant differences between crop types and management styles which will effect 

growth and yields. There is not a specified crop type; however, as the author’s point out that 

growing conventional crops such as corn on this land could increase erosion and polluted runoff. 

Growing perennial grasses such as switchgrass, for use as a feedstock would be the best option.99 

Although perennial grasses are able to grow on these lands, yields may be lower than they would 

be on more suitable agricultural lands. 

On a state-by-state basis, the areas with the highest amount of available abandoned lands 

are in the West. Wyoming, Utah, Oregon, New Mexico, Nevada, Colorado and California all 

contribute over 5 million abandoned acres to the total. Texas has the largest amount of 

abandoned land estimated at 10.37 million acres. Midwestern states including Iowa, Wisconsin, 

Illinois, and Ohio have approximately 3-4 million acres of abandoned land each (see Table 1.1­

20). These lands may be more conducive to crop production than the more arid parts of the West. 

However, the condition and quality of these lands is unknown at this time. It would be difficult 

to estimate the specific types of energy crops that could be grown on these lands. Also, in the 

DOE assessment previously referenced, most of the Western states are not implicated as areas of 

possible biomass growth (above Figure 1.1-3). 

47
 
Table 1.1-20. Abandoned Agriculture Land and Potential Production by State100 

State 

Area 

(Million ha) 

Area 

(Million acres) 

Production 

(MM tons biomass/yr) 

Ethanol Production Rate 

(gallons/tons) 

Alabama 1.4 3.46 13.2 3.82 

Alaska 0.3 0.74 0.4 0.54 

Arizona 1.9 4.69 2.4 0.51 

Arkansas 1.1 2.72 11.1 4.09 

California 3.6 8.89 13.2 1.48 

Colorado 2.7 6.67 8.1 1.21 

Connecticut 0.1 0.25 0.6 2.43 

Delaware 0.1 0.25 0.5 2.02 

District of Columbia 0 0 0 0 

Florida 0.5 1.24 2.7 2.19 

Georgia 1.6 3.95 15.2 3.85 

Idaho 1.4 3.46 4.7 1.36 

Illinois 1.6 3.95 11.4 2.88 

Indiana 1.2 2.96 8.5 2.87 

Iowa 1.6 3.95 12.7 3.21 

Kansas 0.3 0.74 1.8 2.43 

Kentucky 0.8 1.98 6.7 3.39 

Louisiana 0.9 2.22 7.8 3.51 

Maine 0.1 0.25 0.8 3.24 

Maryland 0.4 0.99 2.7 2.73 

Massachusetts 0.2 0.49 1.1 2.23 

Michigan 1.5 3.71 9 2.43 

Minnesota 1.6 3.95 10.7 2.71 

Mississippi 1 2.47 9.1 3.68 

Missouri 1.5 3.71 14.1 3.81 

Montana 1.7 4.2 6.8 1.62 

Nebraska 0.4 0.99 2.2 2.23 

Nevada 2.1 5.19 3 0.58 

New Hampshire 0 0 0.3 0 

New Jersey 0.2 0.49 1.9 3.85 

New Mexico 3 7.41 5.4 0.73 

New York 1.7 4.2 10.2 2.43 

North Carolina 0.7 1.73 6.2 3.59 

North Dakota 1 2.47 4.4 1.78 

Ohio 1.4 3.46 8.9 2.57 

Oklahoma 1.1 2.72 8.8 3.24 

Oregon 2.2 5.43 8.2 1.51 

Pennsylvania 1 2.47 8.2 3.32 

Rhode Island 0 0 0.2 0 

South Carolina 0.8 1.98 7.3 3.69 

South Dakota 0.3 0.74 2 2.7 

Tennessee 1.1 2.72 10.3 3.79 

Texas 4.2 10.37 25.3 2.44 

Utah 2.6 6.42 4.7 0.73 

Vermont 0.1 0.25 1 4.05 

Virginia 0.7 1.73 6.7 3.88 

Washington 0.9 2.22 4 1.8 

West Virginia 0.1 0.25 0.5 2.02 

Wisconsin 1.4 3.46 9.9 2.86 

Wyoming 2.8 6.92 6.1 0.88 

Totals 58.9 145.5 321 

Total Ethanol Volumea 25.68 Bgal Ethanol/yr 

a. Assuming 80 gal/ton conversion rate 

48 
 

The estimates of abandoned agricultural land do not include land enrolled in the 

Conservation Reserve Program (CRP), which could be an additional source of land available for 

energy crops. Land in this program is farmland that is converted to trees, grass, and areas for 

wildlife cover, but is considered crop land by the models in the abandoned land study. 

Environmental benefits of this land include the creation of wildlife habitat, increasing soil 

productivity, reducing soil erosion and improving ground and surface water quality.101 As of 

July 2008, there were 34.67 million acres under the CRP contract which is down 2.1 million 

acres from last year.102 Approximately 28 million CRP acres are growing with native or 

introduced grasses, suggesting that there is a significant amount of switchgrass already in the 

environment. Figure 1.1-21 shows the land allocation in the United States in 2007.103 Recently, 

the 2008 Farm Bill capped the number of acres in the CRP at 32 million acres for 2010-2012. 

Following historical trends, it is assumed that some of these acres will go into crop production. 

While some of this land may go for biofuel production, the benefits of producing energy crops 

will have to be weighed against the benefits of having the land in the CRP. 

Figure 1.1-5. CRP land in 2007 

USDA. Farm Services Agency. Conservation Reserve Program Summary and Enrollment Statistics. FY 2007 

1.1.3 Biodiesel & Renewable Diesel Feedstocks 

In general, plant and animal oils are valuable commodities with many uses other than 

transportation fuel. Therefore we expect the primary limiting factor in the supply of both 

biodiesel and renewable diesel to be feedstock availability and price. Primary drivers for this are 

increasing worldwide demand as incomes rise in developing countries, as well as increased 

recognition that these materials have value based on their energy or hydrocarbon content as 

substitutes for petroleum. Expansion of biodiesel market volumes beyond the mandates is 

dependent on it being able to compete on a price basis with the petroleum diesel being displaced. 

The primary feedstock for domestic biodiesel production in the U.S. has historically been 

soybean oil, with other plant and animal fats and recycled greases making up a small portion of 

49
 
 

the biodiesel pool. We estimate that 2-4 percent of biodiesel came from waste cooking oils and 

greases in calendar year 2007. 104 

1.1.3.1 Virgin Plant Oils 

Agricultural commodity modeling we have done for this proposal (see Chapter 5 of this 

document) suggests that soybean oil production will stay relatively flat in the future, meaning 

supplies will be tight and prices supported at a high level as biofuels demand increases. 

Modeling scenarios conducted for the year 2022 with the EISA mandates indicates that domestic 

soy oil production could support about 560 million gallons of biodiesel production. The model 

also projects that some food-grade corn oil will also be directed to biodiesel production based on 

its price and availability, resulting in an additional 109 million gallons of fuel from this source in 

2022. These materials are most likely to be processed by biodiesel plants due to the large 

available capacity of these facilities and their proximity to soybean production. Compared to 

other feedstocks, virgin plant oils are most easily processed into biofuel via simple 

transesterification due to their homogeneity of composition and lack of contaminates. 

1.1.3.2 Corn Oil Extracted During Ethanol Production 

A source of feedstock which could provide significant volume is oil extracted from corn 

or fermentation co-products in the dry mill ethanol production process. Often called corn 

fractionation or dry separation, these are a collection of processes used get additional product 

streams of value from the corn. This idea is not new, as existing wet mill plants create several 

streams of product from their corn input, including oil. In a dry mill setting, the kernel can be 

separated into the bran, starch, and germ components ahead of fermentation, or alternatively, oil 

can be extracted from the distillers’ grains after fermentation. Both have advantages and 

disadvantages related to plant capital cost and energy consumption, as well as yield of ethanol 

and the other coproducts. 

Extraction of oil from the thin stillage or distillers’ grains with solubles (DGS) streams is 

a proven technology that can be retrofit to existing plants relatively cheaply. Front-end 

separation requires more intensive capital investment than is required to extract oil from the 

DGS, and therefore is best designed into the plant at the time of construction. However, it yields 

a larger array of co-products, and generally also results in ethanol process energy savings since 

less unfermentable material is going through the process train. We expect that this technology 

will be increasingly deployed in new plants in parallel to existing plants pursuing extraction of 

oil from DGS. For the sake of simplicity, for this proposal we have chosen to focus for cost and 

volume estimates on the DGS extraction process. 

Specifically, our estimates come from a process developed and marketed by GS 

Cleantech, Inc., though there are others who will likely develop and market similar processes. 

Depending on the configuration, this system can extract 20-50 percent of the oil from the 

fermentation co-products, producing a distressed corn oil stream which can be used as feedstock 

by biodiesel facilities. Since it offers another stream of revenue from the corn flowing into 

ethanol plants, we assumed approximately 40 percent of projected total ethanol production will 

implement this or other oil extraction process by 2022, generating approximately 150 million 

50
 
 

gallons per year of corn oil biofuel feedstock.105,J We expect this material to be processed in 

biodiesel plants for the same reasons given above for soy oil. At this time it is uncertain whether 

there will be third party aggregators of this extracted oil, or whether individual ethanol plants 

will contract directly with nearby biodiesel facilities, which may ultimately impact where and 

how this feedstock is processed. 

1.1.3.3 Yellow Grease and Other Rendered Fats 

Rendered animal fats and reclaimed cooking oils and greases are another potentially 

significant source of biodiesel feedstock. In 2007, Tyson Foods announced plans to produce 

renewable diesel at multiple sites in joint venture with ConocoPhillips and Syntroleum Corp, 

suggesting these operations are technologically feasible if market conditions are right. 

National Renderer’s Association gives a quantity of approximately 11 billion lbs of fats 

and greases available annually for all uses, and suggests this will grow by 1% per year.106 This 

figure is broken down into several categories, and includes “yellow grease” and “other grease” 

collected and processed by rendering companies each year. NRA defines yellow grease as 

material primarily derived from restaurant grease or cooking oil (they do not define “other 

grease” but we can assume this is trap grease or other reclaimed material). Adding together the 

NRA’s “yellow grease” and “other grease” categories, we arrive at 2.7 billion lbs per year (all 

figures there are for 2005). 

Similarly, a 2004 report prepared for New York State Energy Research and Development 

Authority by LECG, LLC describes yellow grease as material produced by restaurants and food 

service.107 (This report describes grease recovered from sewer traps as brown grease, and 

suggests it is too low in quality to be used for biodiesel production.) Based on USDA and US 

Census data, LECG shows production of yellow grease by restaurants to be on the order of 9 lbs 

per capita per year, equivalent to about 2.7 billion lbs/yr. Unfortunately, it's not clear whether 

this quantity would include or be in addition to the NRA figures, but given the similarity of 

numbers, it seems reasonable to suspect that the NRA total includes the same sources of grease 

as assessed by LECG. 

Thus, the figures we use here assume that the NRA figures already include collection of a 

large portion of restaurant and trap grease by rendering companies; we have not included 

additional waste greases that other studies have suggested might be available based on per-capita 

use of cooking oils, wastewater treatment disposal, etc. Perhaps there is some additional waste 

grease out there not being collected or counted by NRA that is, or could be, aggregated and 

funneled into biofuel production, but there is unfortunately no good way for us to determine this. 

In addition to the named sources above, there is also a written statement by David 

Meeker of the NRA asserting that not more than 30% of the 11 billion lbs could be directed to 

biofuel production on a long-term basis. 108 So, along with the total volume of fats and greases 

as estimated above, we have 0.3 x 11 billion lbs per year / 7.6 lbs per gallon = 434 million 

gallons. With 1% annual growth between 2005 (the year of the figures cited) and 2022, we 

J

 The projected fraction of plants doing corn oil extraction was based on a conversation with someone working in the 

ethanol industry, as well as Table 3 of the Mueller report referenced in this paragraph. 

51
 
arrive at a potential 514 million gallons of biodiesel per year from all available sources. Our 

projections in this proposal suggest that 375 million gallons or 73% of this will be actually be 

utilized for biofuel. This figure was derived from FASOM modeling of other sources of 

feedstock we expect to be available (such as soy oil), as well as our assumptions about corn oil 

extracted at ethanol plants, in the context of the standard set forth in the EISA. This 73% seems 

reasonable considering market inefficiencies and potential competition from other high-value, 

non-fuel uses of these feedstocks. 

Much of biodiesel production seems to rely on niches of feedstock availability and 

market outlets. Thus we could assume that the 2-4% of biodiesel volume to be produced from 

fats and greases as reported by FO Licht for 2007 will continue indefinitely. We speculate that 

much of any new fat and grease feedstock use would be routed to renewable diesel in the long 

term, however, because that process appears to have lower operating costs for this material, and 

because there have been intent or construction announcements for RD plants to utilize a 

significant portion of the 375 MMgal. Furthermore, we suspect that some of the feedstock these 

plants will use may be obtained through direct contract or joint venture with animal processing 

or rendering operations, such that it would not typically be available on the open market to 5 or 

10 or 20 MMgal/yr biodiesel plants in a different county or state. Thus we chose to assume the 

vast majority of this feedstock would be routed to RD production by the time of the fully phasedin RFS2 program, and ignored its use in biodiesel production. 

1.1.3.4 Jatropha 

Jatropha is a genus of plants, consisting of both shrubs and trees, some of which hold 

some promise as a feedstock for the production of biofuels. One species in particular, Jatropha 

curcas, yields seeds that contain between 25-45 percent lipids, which can be processed to 

produce biodiesel. Claims regarding the production potential of J. curcas have led to the 

popularity of the crop as a potential biofuel feedstock. In particular, these claims state that the 

crop: 

-grows on marginal lands and reclaims wasteland, 

-is tolerant of drought, 

-requires low nutrient input, 

-requires low labor inputs, 

-does not compete with food production, and 

-has a high oil yield. 

J. curcas has been traditionally cultivated for living fences, to conserve soil moisture, 

reclaim soil, control erosion, and used locally in soap production, insecticide, and medicinal 

application.109,110 J. curcas is also a toxic plant. Safety of large-scale J. curcas plantations is also 

a concern, especially for children. Accidental ingestion can have severe consequences. 

“Hundreds of cases have been reported from different parts of India. In Meerut (in Uttar 

Pradesh), over 50 children were recently hospitalized due to jatropha poisoning.”111 Even two J. 

curcas seeds are like a strong purgative, while four to five seeds can cause death. 

52
 
 

J. curcas has recently been cultivated as an energy crop. J. curcas originated in Central 

America, mainly growing in arid and semi-arid conditions; now it is also found in the tropical 

regions of Africa, Asia, and North and South America.112 Because of J. curcas’ deep root 

system, it can grow in lands that have been previously heavily cultivated or otherwise have low 

levels of essential minerals and nutrients in the top levels of soil; this results in the recycling of 

nutrients from deeper soil levels.113,114 In addition, because the plant is a perennial (living up to 

50 years) the root system stays in place, which can significantly reduce erosion and even reverse 

desertification.115,116 However, J. curcas may not produce efficiently on marginal lands without 

significant extra expense. 

1.1.3.4.1 Jatropha Input and Cultivation 

As a wild plant which has not yet been domesticated, J. curcas may be considered 

drought-tolerant. However, “there is little known on water use efficiency of J. curcas as a 

crop.”117 Even though J. curcas can survive moderate droughts by dropping its leaves, the effect 

of water starvation on seed yield and oil content in the seeds is mostly unknown. No studies 

relating water use and yield of Jatropha curcas were available. Water use efficiency of sister 

species Jatropha pandurifolia and Jatropha gossypifolia are reported as 3.68 and 2.52 mol CO2 / 

mol H2O, respectively.118 This is similar to that of other oil seed species like soybean, with a 

water use efficiency of 3.90 mol CO2 / mol H2O.119 Thus, it is conceivable that water 

requirements of J. curcas will be similar to that of other oil seed species; although the plant may 

survive droughts, it may not produce efficiently or economically when it is water-deprived.120 

Obviously, further studies relating water use to crop production must be performed. 

Because J. curcas has been observed growing on low quality soils with low nutrient 

amounts, it was assumed that the plant would be able to grow as a crop in these conditions. 

However, research indicates that J. curcas growth and production of seed is severely limited by 

soil fertility.121,122 In the initial growth phase of the plantation, when competition between plants 

for radiation, water, and nutrients is negligible, “nutrient content in mature leaves is not 

significantly affected by crop density.”123 However, in the competition phase, “nutrient uptake 

from the soil was negatively correlated with plant density;”124,125 fertilization with J. curcas 

seedcake significantly increased seed yield.126 This indicates that J. curcas plantations should at 

least be fertilized with remaining seedcake (bulk of seed after oil is pressed out), which is very 

nutrient rich. Thus, this seedcake cannot be sold as a fertilizer, or burned for energy production 

to make the cultivation of the plant more cost effective, as was suggested in various studies,127,128 

if J. curcas cultivation is to require low external nutrient input. Even in the case that the 

seedcake and other oil extraction by-products is recycled to maintain soil fertility, “initiating a 

plantation on low or non fertile soils ... implies the need to use other fertilizers, at least at the 

start, to boost crop growth and seed production in the initial stages.”129 The long-term impact of 

monocultures of jatropha on soil health has not been studied. Although J. curcas can potentially 

grow on marginal land, whether it is safe to plant on current crop land is still unknown. There are 

some indications that J. curcas will not be sustainable, unless specific steps are taken to ensure 

the plantations’ long term health.130,131 

Because it was observed that J. curcas thrived on marginal soils, it was assumed that the 

labor required to maintain the crop and harvest the seeds would be minimal. However, in order to 

53
 
 

prepare J. curcas for use as an energy crop, significant labor is required, including: preparing 

land, setting up nurseries, planting, irrigating, fertilizing, pruning, harvesting, and processing.132 

At present, there are no data to show that any of these labor intensive activities, which are 

assumed in the cultivation of other perennials, can be eliminated. Labor input required for crop 

maintenance actually rose from 22 person days / ha / year to 70 person days / ha / year from the 

1st to 6th year in one study, indicating that there will be no reduction in labor inputs required even 

as the plantations mature.133 Especially in the United States, where labor costs are high, this is a 

severe hindrance for the cultivation of J. curcas on a large scale. Furthermore, the development 

of any sort of mechanized harvesting will be problematic, as “continuous flowering results in a 

sequence of reproductive development stages on the same branch, from mature fruits at the base, 

to green fruits in the middle, and flowers at the top of the branch;” seeds still need to be picked 

by hand.134,135 

Because it was assumed that J. curcas could thrive on marginal land with low resource 

inputs, it was thought that the crop’s cultivation would not compete with that of food crops.136 

However, until present, most studies on the crop’s oil production have been carried out given 

optimal growing conditions that may be unrealistic in many parts of the world. “A major 

constraint for the extended use of J. curcas seems to be the lack of knowledge about its potential 

yield under sub-optimal and marginal conditions;” it is unknown whether J. curcas can produce 

economically on marginal lands.137 Even if J. curcas could be grown successfully on these 

lands, it is likely that, in order to achieve economic yields, significant resource inputs will be 

needed. In this case, food crops could likely be grown on these same lands anyways; in addition, 

the cultivation of J. curcas will draw scarce water and labor resources from food crops. There are 

examples of farmers leaving successful food crop plantations to cultivate J. curcas, leading to 

increased food scarcity.138 Finally, even if successful cultivation of J. curcas were entirely 

possible on marginal lands with low inputs, the widespread success of the crop “might lead to 

rapid expansion of production at the cost of food crops.”139 Although advances are being made 

on several of these fronts, currently, J. curcas can likely not be cultivated on a large scale 

without displacing food corps because of land, water, and labor constraints. 

1.1.3.4.2 Jatropha Yield 

Optimal seed production of 1.5-7.5 tons/ha occurs with 1200 to 1500 mm water/year 

under different trial conditions.140 However, a minimum of 500 to 600 mm water/year is 

required to produce approximately 1 seed ton/ha.141 It is unknown whether this variation is a 

result of environmental or genetic variation, or a combination of both. Maximum production is 

attained in mature plantations, about 3-5 years after planting, with a maximum productive life of 

over 30 years.142,143 

The seed of J. curcas has a lipid content of roughly 25-45 percent by weight.144,145 

However, the oil content of the seed was “significantly higher in soils that had not been used for 

arable farming before (42.3 vs 35 percent).146 Thus, assuming a seed oil content of 35 percent 

and an extraction efficiency of 75 percent, this would yield 404-2040 kg oil / ha or 439-2217 liter 

oil/ha.147 This is somewhat higher than other oil producing crops like soybean, sesame, 

sunflower, rapeseed, and castor with a range of 375-1200 liter oil/ha. However, at this time, it is 

difficult to assess production potentials on marginal land because of the lack of data. “The hype 

54
 
 

in J. curcas oil production is not sufficiently supported by hard data on crop production, well 

controlled or optimal management production conditions, and environmental 

impact.”148,149,150,151 

Table 1.1-21. Jatropha Yield152,153,154 

Conservative projection Optimistic projection 

Oil 500 liter/ha (53 gal/acre) 2000 liter/ha (213.8 gal/acre) 

Biodiesel 460 liter/ha (49 gal/acre) 1840 liter/ha (196.7 gal/acre)

(1 L/ha = 0.1069 US gallons per acre) 

J. curcas is only currently present in 2 states (Florida and Hawaii) in the United States.155 

Because of J. curcas’ intolerance to frost, only small portions of the United States can be 

considered for cultivation. Areas with the most suitable climate conditions for cultivation can 

extend as far as 30° N in latitude; this would include the southern parts of Texas and Louisiana, 

and most of Florida. 156 Assuming no irrigation (as J. curcas is assumed to be a low-input crop), 

an absolute minimum of 500 mm of rainfall is required for substantial production, this occurs in 

the easternmost portions of Texas, and all of Louisiana and Florida.157 The University of Florida 

has done some breeding and genetic manipulation of J. curcas, with the goal of increasing 

hardiness and tolerance to colder climates; no results have yet been published.158 

Table 1.1-22. Timeline (for US cultivation)159,160 

Conservative projection Optimistic projection 

Test plantations 5-10 years 2-5 years 

Commercialization 10-20 years 6 years 

Cost data for US cultivation of J curcas is not available. Because of high labor costs, the 

need to reuse seedcake as organic fertilizer (instead of selling it for further economic gain), and 

irrigation needs, J. curcas biodiesel production in the United States will likely may not be 

economic. Other countries with significantly lower labor costs may find it more economic to use 

jatropha as a biodiesel feedstock. 

1.1.3.4.3 Jatropha Conclusions 

It is unlikely that Jatropha curcas will be able to help the United States meet its energy 

needs in the future without disrupting current food crops, water resources, and other US interests. 

Currently active large projects to cultivate J. curcas around the world are based on very 

optimistic assumptions; many of the strong selling points of J. curcas a may not be valid under 

more reasonable assumptions. Still very little is known about the crop’s sustainability impacts, 

its long-term yields, or its ability to be grown economically as a monoculture. Even under 

optimal conditions, jatropha yields are unlikely to be radically different from that of other 

conventional oil plants; thus, its possible impact on US energy supply is limited. 

1.1.3.5 Algae 

Microalgae are single-celled algae species that grow quickly and have high lipid content, 

and thus are a promising feedstock for biofuel production. While the majority of algae 

55
 
 

 

 

 

companies are focusing on the use of algae for biodiesel production, it is important to note that 

algae can alternatively be used for producing ethanol or crude oil for gasoline or diesel which 

could also help contribute to the advanced biofuel mandate.K Some of the benefits of using algae 

as a biofuel feedstock are that it: 

-grows on marginal land, 

-requires low water inputs, 

-can recycle waste streams from other processes, 

-does not compete with food production, and 

-has high oil yield. 

1.1.3.5.1 Algae Overview 

Mass cultivation of microalgae has been ongoing since the 1950s for medical and 

pharmaceutical purposes. Since the 1980s, algae-to-biofuel research has been heavily funded by 

governments such as Japan, France, Germany and the United States. The research program in 

the US was especially large. The Aquatic Species Program, backed by the National Renewable 

Energy Laboratory, ran from 1978-1996 to look at the use of aquatic plants, specifically algae, as 

sources of energy. From about 1982 through the termination of the program, research 

concentrated on algae for biofuel production, specifically in open ponds.161 Two branches to 

research large scale algaculture systems were funded: the “High Rate Pond” and the “Algae 

Raceway Production System” from 1980 to 1987. By 1988 several large (1,000 m2) systems 

were designed and built at the “Outdoor Test Facility.”162 However, overall productivity of the 

ponds was lower than expected at around 10 grams algae / m2 / day, due to cold temperatures and 

native species of algae taking over the ponds. 

Recently, many small companies in the United States and Europe have begun developing 

processes for algae-to-biodiesel production, most notably, GreenFuel Technologies, Solazyme, 

LiveFuels, Solix Biofuels, and AlgaeLink.163 Even large energy corporations have shown interest 

in algae development: Chevron, for example, has partnered with NREL to collaborate on 

research to produce transportation fuel using algae.164 

Microalgae, which can have a high mass percentage of triacylglycerols, or natural oils, 

can be cultivated using either of two methods. One method that is currently in use, and was 

studied widely by the Aquatic Species Program, involves using large, open ponds to grow algae; 

these are often called “raceway” ponds, as their shape is similar to an oval racetrack. They use a 

paddle wheel to keep the water in motion around the pond. The other method of algae cultivation 

utilizes closed “photobioreactors;” these are long, clear tubes through which the algae-water 

mixture flows. The mixture is still exposed to sunlight and CO2 (through gas bubblers) but is 

shielded from contaminants that may occur in the environment. 

After the algae are grown, the oil must still be extracted from the mixture. Usually this 

involves a dewatering process, to dry the algae, which is followed by an oil extraction process. 

The oil may be extracted using presses, expellers, or chemical processes. The triacylglycerols 

KAlgenol and Sapphire Energy, see http://www.algenolbiofuels.com/ and http://www.sapphireenergy.com/ 

56
 
can then be processed into biodiesel by transesterification, a chemical process. The 

transesterification process is discussed further in section 1.4.4 of this document. 

1.1.3.5.2 Algae Input and Cultivation 

Because algae are marine species and can be grown wherever sufficient water is 

available, algaculture does not require fertile lands. While other oil crops such as soy, sunflower, 

rapeseed, and jatropha need large amounts of agricultural land in order to meet a sizable portion 

of US liquid fuel demand, algae do not displace agricultural crops. 165,166,167 Algae grow most 

effectively in regions with high solar insolation, such as the US southwest, as discussed later. 

When cultivated in enclosed photobioreactors, evaporation of water in limited, and water 

extracted during the drying process can be mostly reclaimed.168 Even in open raceway-style 

ponds where evaporation is not negligible, water requirements are still considerably lower than 

with conventional agricultural crops. It is estimated that, in order to produce enough algal 

biomass for 60 billion gallon biodiesel/year, 20-120 trillion gallons of water/year are needed. 

This is several orders of magnitude lower than the 4,000 trillion gallon/year used to irrigate the 

entire US corn crop.169 (This, if used exclusively for the production of conventional ethanol, 

would not reach the energy equivalent of 60 billion gallons of algae biodiesel). 

Algae can also thrive in brackish water, with salt concentrations up to twice that of 

seawater, which is often available in saline groundwater aquifers in the southwest.170, 171 The 

salt, other minerals, and contaminants may pose a problem to the dewatering and extraction 

process, depending on the method used. However, this is a technical, not fundamental, issue 

with the use of saltwater. Thus, water usage is not a constraint and should not displace 

conventional crops, as no water currently used for conventional crops will need to be diverted to 

algae.172,173 

Aside from sunlight, algae require two main physical inputs for growth: CO2 and 

nutrients.174 These nutrients can be obtained from conventional fertilizers, or from domestic or 

industrial waste sources, such as farm refuse and manure.175 Co-locating algae farms with animal 

husbandry, in order to directly use the manure as a nutrient, would reduce transportation costs.176 

In addition, both of these inputs can be obtained from waste streams from other energy 

processes. They can be coupled with coal-burning power plants or even ethanol plants, and can 

effectively recycle between 50% and 90% of flue gasses, depending on the size of the algae 

farm.177,178,179 The highly controlled environment of algae photobioreactors make them 

especially suitable to process and recycle CO2 in flue gasses, as the gas can be bubbled or 

channeled into the water.180 One study shows approximately 1,700 power plants in the United 

States have enough unused surrounding land to support a commercial-scale algae biofuel 

system.181 A more localized analysis of Arizona, one of the more promising algae cultivation 

states, only identified 7 coal-burning power plants suitable for co-location with algae farms. 

1.1.3.5.3 Algae Yield 

Certain species of algae can produce 80 percent of their body weight as oils, and oil 

levels of 20-50 percent are common.182,183 Thus, the projected outputs of algae farms are many 

57
 
 

 

times higher than traditional farms, on the order of 30,000 to 130,000 liter oil/ha/yr, which can 

be processed into 27,600 to 119,600 liter biodiesel/ha/yr (2,950 to 12,780 gallons 

biodiesel/acre/yr).184,185,186,187,188 See Table 1.1-23, below. 

Raceway systems are low-cost but have low productivity compared to photobioreactors. 

Most current research focuses on the photobioreactor system of cultivation for optimal pH, gas 

level, salinity, and temperature control, and to prevent contamination from invasive algae 

species.189,190 Photobioreactors also increase the concentration of algae in the water, by around 

30 times, somewhat simplifying the dewatering process.191 

Table 1.1-23. Potential Algae Yield (assuming photobioreactor system)192,193,194 

Conservative projection Optimistic projection 

Oil 30,000 liter/ha/yr (3207 gals/acre) 130,000 liter/ha/yr (13898 gals/acre) 

Biodiesel 28,000 liter/ha/yr (2993 gals/acre) 120,000 liter/ha/yr (12829 gals/acre) 

1.1.3.5.4 Algae Timeline and Cost Projections 

The projected timeline for commercial production of algae oil for biofuel varies 

depending on expert opinion. As shown in Table 1.1-24, some estimate as early as the next few 

years for algae biofuel to be produced at commercial scale. 

Table 1.1-24. Algae Timeline195,196,197,198,199 

Optimistic projection Conservative projection 

Commercialization 2-3 years 10 years 

One company, AlgaeLink, has developed the first made-to-order industrial algae 

production facility in the world, though it is currently selling it at high cost.200 Also, a company 

called XL Renewables has developed an approach to use a potentially lower cost photobioreactor 

system for algae production.201 Estimated costs are detailed in the Table 1.1-25, below. 

Table 1.1-25. Algae Costs (assuming photobioreactor system)202,203 

Conservative projection Optimistic projection 

Algae biomass $0.47/kg ($0.21/pound) $0.05/kg ($0.02/pound) 

Oil (recovered; estimate) $2.80/liter ($10.60/gallon) $0.20/liter ($0.75/gallon) 

Biodiesel $2.95/liter ($11.17/gallon) $0.35/liter ($1.32/gallon) 

Concrete information about harvesting and oil extraction costs is not available, but may 

be up to 50% of the cost of recovered algae oil. Refining of algae oil into biodiesel will add 

roughly $0.57/gallon.204 Thus, a large production facility of 10,000 tons algae biomass/year 

using current algaculture technology could produce algae oil at roughly $10.60/gallon, and algae 

biodiesel at $11.17/gallon under conservative projections. Assuming more optimistic 

projections, algae oil could be produced for $0.75/gallon and biodiesel for $1.32/gallon. In 

comparison, during 2006, the cheapest vegetable oil available (crude palm oil) cost roughly 

$1.97/gallon, and palm oil biodiesel roughly $2.50/gallon. 

58
 
 

1.1.3.5.5 Possible U.S. Locations 

The US southwest is the most promising location for economic algae-for-biofuel 

cultivation, due to its high solar insolation (see Figure 1.1-6), availability of saltwater aquifers, 

and relatively low current land use.205,206 Ideally, algae farms could be co-located with coalburning power plants in order to recycle the carbon emissions and increase algae. However, 

although one study states that 1,700 power plants throughout the United States have enough 

surrounding land to support a commercial-scale algae system, only a limited number of these are 

in the southwest, due to lower population densities.207 

Figure 1.1-6. 

PV Solar Radiation in the United States 

1.1.3.5.6 Algae Challenges 

Unlike other feedstocks that have fundamental land use, water use, and yield/efficiency 

issues, the main problem facing future development of algae-to-biodiesel systems is 

underdeveloped technology and high cost. “Producing microalgal biomass is generally more 

expensive than growing crops.”208 The high cost is due mainly to the relative complexity of 

cultivation, harvesting, and oil extraction systems needed for algae, which translates to high 

capital and operating costs.209,210,211,212 “Economics of producing microalgal biodiesel need to 

improve substantially to make it competitive with petrodiesel, but the level of improvement 

necessary appears to be attainable.”213 Specific technological hurdles include temperature 

control, dewatering methods and lipid extraction. Harvesting the algae is particularly difficult 

and energy intensive, but is made somewhat easier with photobioreactors, which yield higher 

algae concentrations in the water than open-ponds. 

1.1.3.5.7 Algae Conclusions 

Algae-to-biofuel production has significant potential because of high oil yields and 

59
 
 

ability to be cultivated on marginal land. Indeed, algae could supply the United as much as 60 

billion gallons of biodiesel/year using a land area as small as 6 million acres (about 8% of 

Arizona’s land area).214 However, several technical hurdles must still be overcome, and costs 

must come down significantly, before algae are viable as a commercial biofuel feedstock. 

1.1.3.6 Imported Biodiesel 

In 2007, the EU produced 58 percent of worldwide biodiesel. Another 20 percent was 

produced in the U.S., with the remainder split between South America and the rest of the 

world.215 

In terms of historical production, EU biodiesel output increased from 200 million gallons 

in 2000 to almost 1,500 million gallons in 2007.216 According to some analysts, however, the EU 

does not have the capacity to expand oilseed areas and in comparison to other climates, the 

climate in the EU is not particularly good for oilseed production.217 Estimates for future EU 

biodiesel production appear to be roughly 2.5 billion gallons by 2017.218 

In addition to leading production, the EU is currently the largest market for biodiesel in 

the world, consuming around 700 million gallons in 2005. Biodiesel consumption in 2007 

increased to approximately 1,800 million gallons.219 Even with the increase in domestic 

production, however, it seems likely that the EU’s future biofuels consumption goals will not be 

met. 

In 2007, the European Commission (EC) proposed a binding minimum target requiring 

10 percent biofuel use for transport by 2020.220,221 The International Energy Outlook forecasts 

OECD European countries will consume 147 billion gasoline gallons equivalent (gge) of 

transportation fuel in 2010, growing to 151 gge by 2020. Currently, approximately 60 percent of 

the EU’s transportation fuel demand is met by diesel. Assuming this split continues in the future, 

a 10 percent biofuel requirement would translate to roughly 8 billion gallons of biodiesel demand 

by 2017. Thus, it appears likely that the EU will not be able to produce enough biodiesel to meet 

its goals by 2020 and will need to depend on other countries to make up the remaining 5.8 billion 

gallon demand (after accounting for domestic production of 2.2 billion gallons as estimated from 

above). So not only will the EU, the largest current producer of biodiesel, not have any biodiesel 

available for export in the future; they will likely be a net importer competing with the U.S. for 

surplus biodiesel supplies. 

As imports of finished biodiesel (or biodiesel feedstocks) are relatively new in the U.S. 

domestic market, volumes are currently small and not well-tracked by industry groups and EIA. 

Therefore, there is limited historical data from which to better understand the U.S.’s position to 

import biodiesel. Alternatively, in order to answer these questions, we analyzed the following 

countries that have been noted as having a large potential for producing biodiesel: Brazil, 

Malaysia, Indonesia, and India. 

Currently, there is a large interest in Brazil to develop a strong biodiesel program. As 

Brazil has mandates of B2 by 2008 and B5 by 2013 much of its production of biodiesel will be 

consumed domestically before any biodiesel will be available for exports.222 If the mandates as 

60
 
well as Brazil’s biodiesel production goals are met, this would mean that approximately 500 

million gallons could be available for exports by 2010 and around 600 million gallons by 2020.

223 Although this is a relatively large amount compared to what is produced today, this volume 

is still not enough to meet all of the EU’s demand for biodiesel. Therefore, the amount of 

biodiesel exported from Brazil will likely be split among those countries demanding biodiesel, 

with the amount allocated to the U.S. uncertain at this point in time. 

We also analyzed the biodiesel situation in the top two world producers of palm oil, 

Malaysia and Indonesia. Although Malaysia and Indonesia have a large potential for biodiesel 

production from palm oil, these countries appear to be marketing their exports to European and 

Asian nations as well as implementing their own biofuels goals. In fact, Malaysia is anticipating 

biodiesel export opportunities in the European market and is expected to export biodiesel 

specifically to Europe in the range of 100-120 million gallons by 2010.224 This volume is still 

relatively small in comparison to the production of biodiesel in the U.S. from domestic sources. 

The prospect for Indonesian palm oil biodiesel is similar as most Indonesian exports of biodiesel 

are to China and other Asian markets. 

As far as mandates are concerned, Malaysia is planning on introducing a B5 mandate 

which could demand up to 166 million gallons of biodiesel.225 Indonesia has a smaller mandate 

of B2.5, as a decline in fossil fuel prices and the increase in crude palm oil prices resulted in the 

decrease from its original B5 mandate.226 In fact, historically, palm oil prices have been lower 

than soybean and rapeseed oil, suggesting that the use of palm oil could be the most costeffective.227 However, in 2006, palm oil prices began to track soybean and rapeseed oil 

prices.228 Since feedstock costs make up the largest portion of production costs for biodiesel, 

this suggests that the production of biodiesel may not be profitable if palm oil prices remain 

high. With Malaysia and Indonesia’s eyes set on importing biodiesel to the EU and Asian 

nations, possible biodiesel mandates in the future, and increases in palm oil feedstock costs, it 

seems unlikely that the U.S. will receive large volumes of biodiesel from this part of the world. 

As described above, another potential source of biofuel feedstock is jatropha. Although 

the potential for India to produce biodiesel from jatropha is large, there are still great 

uncertainties as to whether India can meet even its own biodiesel goals (i.e., B20 by 2020)229, let 

alone the goals of other nations. Historically, India has neither imported nor exported bio-fuels 

for fuel purposes, nor does the government provide any financial assistance for these products. 

Thus, India’s lack of experience in transporting large volumes of biofuels to other nations may 

limit how much is available internationally. Given that large-scale cultivation of jatropha has yet 

to be seen, and that jatropha has unpredictable yields, it seems unlikely that India could provide 

large volumes of biodiesel to the U.S.230 

Our analysis of the countries with the most potential to produce and consume biodiesel in 

the future suggests that there will be very limited supplies of biodiesel available to the US from 

other nations. Supplies to the U.S. will be limited by factors such as mandates and goals of other 

countries, preferential shipment of biodiesel to European and Asian nations, and how quickly 

non-traditional crops such as jatropha can be developed. Thus, we are estimating that there will 

be negligible amounts of biodiesel available to the U.S. in the future. 

61
 
 

1.1.3.7 Biodiesel Feedstock Summary 

Table 1.1-26. 

Estimated 2022 Potential Biodiesel & Renewable Diesel Volumes 

Based on Feedstock Availability (million gallons of fuel)
 Biomass-based diesel Other advanced biofuel Totals 

From FASOM Outside FASOM From FASOM Outside FASOM From FASOM Outside FASOM 

Soy oil 551 551 

Corn oil (food grade) 109 109 

Corn oil (fractionation) 150 150 

Etallow 14 14 28 

NonETallow 29 29 57 

Lard 26 26 52 

YGrease 94 94 188 

Poultry fat 25 25 50 

Subtotals 823 175 163 25 985 200 

Totals 998 188 1,185 

1.2 RFS2 Biofuel Volumes 

Our assessment of the renewable fuel volumes required to meet the Energy Independence 

and Security Act (EISA) necessitates establishing a primary set of fuel types and volumes on 

which to base our assessment of the impacts of the new standards. EISA contains four broad 

categories: cellulosic biofuel, biomass-based diesel, total advanced biofuel, and total renewable 

fuel. As these categories could be met with a wide variety of fuel choices, in order to assess the 

impacts of the rule, we projected a set of reasonable renewable fuel volumes based on our 

interpretation at the time we began our analysis of likely fuels that could come to market. 

The following subsections detail our rationale for projecting the amount and type of fuels 

needed to meet EISA. For cellulosic biofuel we have assumed that the entire volume will be 

domestically produced cellulosic ethanol. Biomass-based diesel is assumed for our analyses to 

be comprised of a majority of fatty-acid methyl ester (FAME) biodiesel and a smaller portion of 

non-co-processed renewable diesel. Subsequent to the analyses being conducted, our lifecycle 

analysis was completed showing that biomass-based diesel from soy oil failed to meet the 50% 

GHG threshold. The analyses contained in this DRIA are still based on the presumption that soy 

and other virgin plant oils used for biodiesel would qualify as biomass-based diesel. 

Adjustments in the analysis will be conducted for the FRM. The portion of the advanced biofuel 

category not met from cellulosic biofuel and biomass-based diesel is assumed to come mainly 

from imported (sugarcane) ethanol with a smaller amount from co-processed renewable diesel. 

The total renewable fuel volume not required to be comprised of advanced biofuels is assumed to 

be met with corn ethanol. 

In addition, the following subsections also describe other fuels that have the potential to 

contribute to meeting EISA, but because of their uncertainty of use, or because their use likely 

might be negligible we have chosen to not assume any use for our analysis. Examples of these 

types of renewable fuels or blendstocks include bio-butanol, biogas, cellulosic diesel, cellulosic 

gasoline, biofuel from algae, jatropha, or palm, imported cellulosic ethanol, other biomass-toliquids (BTL), and other alcohols or ethers. 

62
 
1.2.1 Cellulosic Biofuel 

As defined in EISA, cellulosic biofuel means renewable fuel produced from any 

cellulose, hemicellulose, or lignin that is derived from renewable biomass and that has lifecycle 

greenhouse gas emissions, as determined by the Administrator, that are at least 60% less than the 

baseline lifecycle greenhouse gas emissions. 

When many people think of cellulosic biofuel, they immediately think of cellulosic 

ethanol. However, cellulosic biofuel could be comprised of other alcohols synthetic gasoline, 

synthetic diesel fuel, and synthetic jet fuel, propane, and biogas. Whether cellulosic biofuel is 

ethanol will depend on a number of factors, including production costs, the form of tax subsidies, 

credit programs, and issues associated with blending the biofuel into the fuel pool. It will also 

depend on the relative demand for gasoline and diesel fuel. For instance, European refineries 

have been undersupplying the European market with diesel fuel supply and oversupplying it with 

gasoline, and based on the recent diesel fuel price margins over gasoline, it seems that the U.S. is 

falling in line with Europe. Therefore, if the U.S. trend is toward being relatively oversupplied 

with gasoline, there could be a price advantage towards producing renewable fuels that displace 

diesel fuel rather than a gasoline fuel replacement like ethanol. 

Current efforts in converting cellulosic feedstocks into fuels focus on biochemical and 

thermochemical conversion processes. In terms of production costs, at least for the main 

technologies of focus, neither biochemical nor thermochemical platforms (comparing enzymatic 

biochemical processing to ethanol and thermochemical processing to cellulosic diesel) appear to 

have clear advantages in capital costs or operating costs.231 We further discuss these 

technologies in Section 1.4 of the DRIA, while feedstock and production costs are discussed in 

Chapter 4 of the DRIA. The economic competitiveness of cellulosic biofuels will also depend on 

the extent of financial support from the government. Under the Farm Bill of 2008, both 

cellulosic ethanol and cellulosic diesel receive the same tax subsidies ($1.01 per gallon each). 

The tax subsidy, however, gives ethanol producers a considerable advantage over those 

producing cellulosic diesel due to the feedstock quantity needed per gallon produced (i.e. 

typically the higher the energy content of the product, the more feedstock that is required). On 

an energy basis, cellulosic ethanol would receive approximately $13/mmBtu while cellulosic 

diesel would receive approximately $8/mmBtu. In a similar manner, if we were to finalize our 

co-proposal for Equivalence Values such that they are generated based on volume rather than 

energy content, this would likewise provide an advantage for the production of cellulosic ethanol 

over cellulosic diesel. 

One large advantage that cellulosic diesel has over ethanol is the ability for the fuel to be 

blended easily into the current distribution infrastructure at sizeable volumes. There are 

currently factors tending to limit the amount of ethanol that can be blended into the fuel pool (see 

Section 1.7. of the DRIA for more discussion). Thus, the production of cellulosic diesel instead 

of cellulosic ethanol could help increase consumption of renewable fuels. 

Thus, there is uncertainty as to which mix of cellulosic biofuels will be produced to fulfill 

the 16 Bgal mandate by 2022. The latest release of AEO 2009, for example, estimates a mixture 

of cellulosic diesel and ethanol produced for cellulosic biofuel. For assessing the impacts of the 

63
 
 

 

RFS2 standards, we made the simplifying assumption that cellulosic biofuel would only consist 

of ethanol, though market realities may also result in cellulosic diesel and other products. 

Cellulosic biofuel could also be produced internationally. One example of internationally 

produced cellulosic biofuel is ethanol produced from bagasse or straw from sugarcane processing 

in Brazil. Currently, Brazil burns bagasse to produce steam and generate bioelectricity. 

However, improving efficiencies over the coming decade may allow an increasing portion of 

bagasse to be allocated to other uses, including cellulosic biofuel, as the demand for bagasse for 

steam and bioelectricity could remain relatively constant. 

One recent study assessed the biomass feedstock potential for selected countries outside 

the United States and projected supply available for export or for biofuel production.L,232 For the 

study’s baseline projection in 2017, it was estimated that approximately 21 billion ethanolequivalent gallons could be produced from cellulosic feedstocks at $36/dry tonne or less. The 

majority (~80%) projected is from bagasse, with the rest from forest products. Brazil was 

projected to have the most potential for cellulosic feedstock production from both bagasse and 

forest products. Other countries including India, China, and those belonging to the Caribbean 

Basin Initiative (CBI) also have some potential although much smaller feedstock supplies are 

projected as compared to Brazil. Although international production of cellulosic biofuel is 

possible, it is uncertain whether this supply would be available primarily to the U.S. or whether 

other nations would consume the fuel domestically. Therefore, for our analyses we have chosen 

to assume that all the cellulosic biofuel used to comply with RFS2 would be produced 

domestically. 

1.2.2 Biomass-Based Diesel 

Biomass-based diesel as defined in EISA means renewable fuel that is biodiesel as 

defined in section 312(f) of the Energy Policy Act of 1992 with lifecycle greenhouse gas 

emissions, as determined by the Administrator, that are at least 50% less than the baseline 

lifecycle greenhouse gas emissions.M Biomass-based diesel can include fatty acid methyl ester 

(FAME) biodiesel, renewable diesel (RD) that has not been co-processed with a petroleum 

feedstock, as well as cellulosic diesel. Although cellulosic diesel produced through the FischerTropsch (F-T) process or other processes could potentially contribute to the biomass-based diesel 

category, we have assumed for our analyses that the fuel and its corresponding feedstocks 

(cellulosic biomass) are already accounted for in the cellulosic biofuel category as discussed in 

the previous Section 1.2.1. 

FAME and RD processes can make acceptable quality fuel from vegetable oils, fats, and 

greases, and thus will generally compete for the same feedstock pool. For our analyses, we have 

assumed that the volume contribution from FAME biodiesel and RD will be a function of the 

available feedstock types. For our analysis we assumed that virgin plant oils would be 

L Countries evaluated include Argentina, Brazil, Canada, China, Colombia, India, Mexico, and CBI

M Subsequent to the analyses being conducted, our lifecycle analysis was completed showing that biomass-based 

diesel from soy oil failed to meet the 50% GHG threshold. The analyses contained in this DRIA are still based on 

the presumption that soy and other virgin plant oils used for biodiesel would qualify as biomass-based diesel. 

Adjustments in the analysis will be conducted for the FRM. 

64
 
 

 

 

preferentially processed by biodiesel plants, while the majority of fats and greases would be 

routed to RD production.N,O This is because the RD process involves hydrotreating (or thermal 

depolymerization), which is more severe and uses multiple chemical mechanisms to reform the 

fat molecules into diesel range material. The FAME process, by contrast, relies on more specific 

chemical mechanisms and requires pre-treatment if the feedstocks contain more than trace 

amounts of free fatty acids or other contaminates which are typical of recycled fats and greases. 

In terms of volume availability of feedstocks, supplies of fats and greases are more limited than 

virgin vegetable oils. As a result, our control case assumes the majority of biomass-based diesel 

volume is met using biodiesel facilities processing vegetable oils, with RD making up a smaller 

portion and using solely fats and greases. 

The RD production volume must be further classified as co-processed or non-coprocessed, depending on whether the renewable material was mixed with petroleum during the 

hydrotreating operations (more details on this definition are in Section III.B.1 of the preamble). 

EISA specifically forbids co-processed RD from being counted as biomass-based diesel, but it 

can still count toward the total advanced biofuel requirement. What fraction of RD will 

ultimately be co-processed is uncertain at this time, since little or no commercial production of 

RD is currently underway, and little public information is available about the comparative 

economics and feasibility of the two methods. We assumed in our control case that half the 

material will be non-co-processed and thus qualify as biomass-based diesel. 

We assumed that all biomass-based diesel would be produced from soy oil, corn oil, 

tallow, lard, yellow grease, and poultry fats. In the future, however, other feedstocks such as 

algae and jatropha may develop as discussed previously in Section 1.1 of the DRIA. 

1.2.3 Other Advanced Biofuel 

As defined in EISA, advanced biofuel means renewable fuel, other than ethanol derived 

from corn starch, that has lifecycle greenhouse gas emissions, as determined by the 

Administrator, that are at least 50% less than baseline lifecycle greenhouse gas emissions. As 

defined in EISA, advanced biofuel includes the cellulosic biofuel, biomass-based diesel, and coprocessed renewable diesel categories that were mentioned in Section 1.2.1 and Section 1.2.2 

above. However, EISA requires greater volumes of advanced biofuel than just the volumes 

required of these fuels. It is entirely possible that greater volumes of cellulosic biofuel, biomassbased diesel, and co-processed renewable diesel than required by the Act could be produced in 

the future. Our control case, however, does not assume that cellulosic biofuel and biomass-based 

diesel volumes will exceed those required under EISA.P

 As a result, to meet the total advanced 

biofuel volume required under EISA, advanced biofuel types are needed other than cellulosic 

biofuel, biomass-based diesel, and co-processed renewable diesel through 2022. 

N Recent changes to federal tax subsidies and market shifts may warrant changes to this assumption. We will 

reevaluate the relative production volumes of biodiesel and renewable diesel for the FRM. 

O This analysis was conducted prior to the completion of our lifecycle analysis and assumes the fuels will meet the 

required GHG threshold 

P While cellulosic biofuel will not be limited by feedstock availability, it likely will be limited by the very 

aggressive ramp up in production volume for an industry which is still being demonstrated on the pilot scale and 

therefore is not yet commercially viable. On the other hand, biomass-based diesel derived from agricultural oils and 

animal fats are faced with relatively high feedstock costs which limit feedstock supply. 

65
 
 

 

We have assumed for the analyses conducted that for our control case the most likely 

source of advanced fuel other than cellulosic biofuel, biomass-based diesel, and co-processed 

renewable diesel would be from imported sugarcane ethanol. Our assessment of international 

fuel ethanol production and demand indicate that anywhere from 3.8-4.2 Bgal of sugarcane 

ethanol from Brazil could be available for export by 2020/2022. If this volume were to be made 

available to the U.S., then there would be sufficient volume to meet the advanced biofuel 

standard. To calculate the amount of imported ethanol needed to meet the EISA standards, we 

took the difference between the total advanced biofuel category and cellulosic biofuel, biomassbased diesel, and co-processed renewable diesel categories. The amount of imported ethanol 

required by 2022 is approximately 3.2 Bgal. Refer to Section 1.5.2 for a more detailed 

discussion on imported ethanol. 

Recent news indicates that there are also plans for sugarcane ethanol to be produced in 

the U.S in places where the sugar subsidy does not apply. For instance, sugarcane has been 

grown in California’s Imperial Valley specifically for the purpose of making ethanol and using 

the cane’s biomass to generate electricity to power the ethanol distillery as well as export excess 

electricity to the electric grid.Q There are at least two projects being developed at this time that 

could result in several hundred million gallons of ethanol produced. The sugarcane is being 

grown on marginal and existing cropland that is unsuitable for food crops and will replace forage 

crops like alfalfa, Bermuda grass, Klein grass, etc. Harvesting is expected to be fully 

mechanized. Thus, there is potential for these projects and perhaps others to help contribute to 

the EISA biofuels mandate. This could lower the volume needed to be imported from Brazil. 

Butanol is another potential motor vehicle fuel which could be produced from biomass 

and used in lieu of ethanol to comply with the RFS2 standard. Production of butanol is being 

pursued by a number of companies including a partnership between BP and Dupont. Other 

companies which have expressed the intent to produce biobutanol are Baer Biofuels and Gevo. 

The near term technology being pursued for producing butanol involves fermentation of starch 

compounds, although it can also be produced from cellulose. Butanol has several inherent 

advantages compared to ethanol. First, it has higher energy density than ethanol which would 

improve fuel economy (mpg). Second, butanol is much less water soluble which may allow the 

butanol to be blended in at the refinery and the resulting butanol-gasoline blend then more easily 

shipped through pipelines. This would reduce distribution costs associated with ethanol’s need 

to be shipped separately from its gasoline blendstock and also save on the blending costs 

incurred at the terminal. Third, butanol can be blended in higher concentrations than 10% which 

would likely allow butanol to be blended with gasoline at high enough concentrations to avoid 

the need for most or all of high concentration ethanol-gasoline blends, such as E85, that require 

the use of fuel flexible vehicles. For example, because of butanol’s lower oxygen content, it can 

be blended at 16% (by volume) to match the oxygen concentration of ethanol blended at 10% (by 

volume). Because of butanol’s higher energy density, when blending butanol at 16% by volume, 

it is the renewable fuels equivalent to blending ethanol at about 20%. Thus, butanol would 

enable achieving most of the RFS2 standard by blending a lower concentration of renewable fuel 

than having to resort to a sizable volume of E85 as in the case of ethanol. The need to blend 

Q Personal communication with Nathalie Hoffman, Managing Member of California Renewable Energies, LLC, 

August 27, 2008 

66
 
ethanol as E85 provides some difficult challenges. The use of butanol may be one means of 

avoiding these blending difficulties. 

At the same time, butanol has a couple of less desirable aspects relative to ethanol. First, 

butanol is lower in octane compared to ethanol – ethanol has a very high blending octane of 

around 115, while butanol’s octane ranges from 87 octane numbers for normal butanol and 94 

octane numbers for isobutanol. Potential butanol producers are likely to pursue producing 

isobutanol over normal butanol because of isobutanol’s higher octane content. Higher octane is 

a valuable attribute of any gasoline blendstock because it helps to reduce refining costs. A 

second negative property of butanol is that it has a much higher viscosity compared to either 

gasoline or ethanol. High viscosity makes a fuel harder to pump, and more difficult to atomize 

in the combustion chamber in an internal combustion engine. The third downside to butanol is 

that it is more expensive to produce than ethanol, although the higher production cost is partially 

offset by its higher energy density. 

Another potential source of renewable transportation fuel is biomethane refined from 

biogas. Biogas is a term meaning a combustible mixture of methane and other light gases 

derived from biogenic sources. It can be combusted directly in some applications, but for use in 

highway vehicles it is typically purified to closely resemble fossil natural gas for which the 

vehicles are typically designed. The definition of biogas as given in EISA is sufficiently broad 

to cover combustible gases produced by biological decomposition of organic matter, as in a 

landfill or wastewater treatment facility, as well as those produced via thermochemical 

decomposition of biomass. 

Currently, the largest source of biogas is landfill gas collection, where the majority of 

fuel is combusted to generate electricity, with a small portion being upgraded to methane suitable 

for use in heavy duty vehicle fleets. Current literature suggests approximately 16 billion 

gasoline gallons equivalent of biogas (referring to energy content) could potentially be produced 

in the long term, with about two thirds coming from biomass gasification and about one third 

coming from waste streams such as landfills and human and animal sewage digestion. 233, 234 

Because the majority of the biogas volume estimates assume biomass as a feedstock, we 

have chosen not to include this fuel in our analyses since we are projecting most available 

biomass will be used for cellulosic liquid biofuel production in the long term. The remaining 

biogas potentially available from waste-related sources would come from a large number of 

small streams requiring purification and connection to storage and/or distribution facilities, 

which would involve significant economic hurdles. An additional and important source of 

uncertainty is whether there would be a sufficient number of vehicles configured to consume 

these volumes of biogas. Thus, we expect future biogas fuel streams to continue to find nontransportation uses such as electrical power generation or facility heating. 

1.2.4 Other Renewable Fuel 

The remaining portion of total renewable fuel not met with advanced biofuel is assumed 

to come from corn-based ethanol. The Act essentially sets a limit for participation in the RFS 

program of 15 Bgal of corn ethanol by 2022. It should be noted, however, that there is no 

67
 
specific “corn-ethanol” mandated volume, and that any advanced biofuel produced above and 

beyond what is required for the advanced biofuel requirements could reduce the amount of corn 

ethanol needed to meet the total renewable fuel standard. This occurs in our projections during 

the earlier years (2009-2014) in which we project that some fuels could compete favorably with 

corn ethanol (e.g. biodiesel and imported ethanol). Beginning around 2015, fuels qualifying as 

advanced biofuels likely will be devoted to meeting the increasingly stringent volume mandates 

for advanced biofuel. It is also worth noting that more than 15 Bgal of corn ethanol could be 

produced and RINs generated for that volume under our proposed RFS2 regulations. However, 

obligated parties would not be required to purchase more than 15 Bgal worth of corn ethanol 

RINs. 

We are assuming for our analysis that sufficient corn ethanol will be produced to meet 

the 15 Bgal limit. However, this assumes that in the future corn ethanol production is not limited 

due to environmental constraints, such as water quantity issues (see Section 6.10 of this DRIA). 

This also assumes that in the future either corn ethanol plants are constructed or modified to meet 

the 20% GHG threshold, or that sufficient corn ethanol production exists that is grandfathered 

and not required to meet the 20% threshold. Our current projection is that up to 15 Bgal could be 

grandfathered, but actual volumes will be determined at the time of facility registration. Refer to 

Section 1.5.1.4 for more information. Since our current lifecycle analysis estimates that much of 

the current corn ethanol would not meet the 20% GHG reduction threshold required of nongrandfathered facilities without facility upgrades, then if actual grandfathered corn volumes are 

less than 15 Bgal it may be necessary to meet the volume mandate with other renewable fuels or 

through the use of advanced technologies that could improve the corn ethanol lifecycle GHG 

estimates. 

1.2.5 Control Case for Analyses 

Table 1.2-1 summarizes the fuel types used for the control case and their corresponding 

volumes for the years 2009-2022. 

68
 
69 

Table 1.2-1. 

Control Case Projected Renewable Fuel Volumes (billion gallons) 

Year 

Advanced Biofuel 

Non-Advanced 

Biofuel 

Cellulosic 

Biofuel Biomass-Based Diesela Other Advanced Biofuel 

Cellulosic 

Ethanol 

FAMEb 

Biodiesel 

Non-Co-processed 

Renewable Diesel 

Co-processed 

Renewable Diesel 

Imported 

Ethanol Corn Ethanol 

2009 0.00 0.50 0.00 0.00 0.50 9.85 

2010 0.10 0.64 0.01 0.01 0.29 11.55 

2011 0.25 0.77 0.03 0.03 0.16 12.29 

2012 0.50 0.96 0.04 0.04 0.18 12.94 

2013 1.00 0.94 0.06 0.06 0.19 13.75 

2014 1.75 0.93 0.07 0.07 0.36 14.40 

2015 3.00 0.91 0.09 0.09 0.83 15.00 

2016 4.25 0.90 0.10 0.10 1.31 15.00 

2017 5.50 0.88 0.12 0.12 1.78 15.00 

2018 7.00 0.87 0.13 0.13 2.25 15.00 

2019 8.50 0.85 0.15 0.15 2.72 15.00 

2020 10.50 0.84 0.16 0.16 2.70 15.00 

2021 13.50 0.83 0.17 0.17 2.67 15.00 

2022 16.00 0.81 0.19 0.19 3.14 15.00 

aBiomass-Based Diesel includes FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel. bFatty acid methyl ester (FAME) biodiesel 
70 

We needed to make this projection soon after EISA was signed to allow sufficient time to 

conduct our long lead-time analyses. As a result, we used the same ethanol-equivalence basis for 

these projections as was used in the RFS1 rulemaking. However, as described in Section III.D.1 

of the preamble, we are also co-proposing that volumes of renewable fuel be counted on a 

straight gallon-for-gallon basis under RFS2, such that all Equivalence Values would be 1.0. 

While the control case volumes used as the basis for our analyses do not reflect this approach to 

Equivalence Values, the net effect on projected volumes is very small; instead of 36 billion 

gallons of renewable fuel in 2022, our control case includes 35.3 billion gallons. We do not 

believe that this difference will substantively affect the analyses that are based on our projected 

control case volumes. 

1.2.6 Construction Feasibility for Cellulosic Ethanol Industry 

Start-up of cellulosic ethanol plants is expected to begin in earnest with a few small 

plants in 2010-11, followed by addition of industry capacity continuing at an increasing pace due 

to more plant starts per year as well as increasing plant size. This is typical as an industry 

progresses up the learning curve, and investors become more confident and are willing to fund 

larger, more efficient plants. During the period from 2010-12, we also expect a slowing of starch 

ethanol plant construction, such that engineering and construction personnel and equipment 

fabricators would potentially be able to transition to work on cellulosic ethanol facilities. 

Here we examine the build rate required to construct cellulosic plants in time to meet the 

standards in Table 1.2-1, and we compare this to the historic build rate of capacity in the starch 

ethanol industry. Figure 1.2-1 depicts these construction trends. 
Figure 1.2-1. 

Historic and projected U.S. ethanol production trends 2001-2022. 

0 

5 

10 

15 

20 

25 

30 

35 

2002 

2004 

2006 

2008 

2010 

2012 

2014 

2016 

2018 

2020 

2022 

Plants/yr 

0 

5 

10 

15 

20 

25 

30 

35 

Bgal/yr 

Starch Plants Cellulosic Plants Total Ethanol Capacity 

2008 and later data are projected 

Historical plant build rates for starch ethanol were derived from figures in Chapter 1.5 of 

this DRIA (see Figure 1.5-1). Average plant capacity figures were estimated from existing 

capacity and plant counts, and we project that the recent trend toward larger plant sizes continues 

going forward. Approximately 200 starch ethanol plants are expected to be operating by 2022. 

For cellulosic ethanol plant construction, we assumed new plant size would begin 

relatively small at 40 million gal/yr for 2010-13, increasing to 80 million gal/yr for 2014-17, and 

100 million gal/yr afterwards. Given the volume standards laid out in the EISA, as well as the 

number of cellulosic ethanol plants projected in Chapter 1.5 to be roughly 180 by 2022 (see 

Table 1.5-36), we arrive at a maximum required build rate of approximately 2 billion gal/yr from 

2018-2022. This is similar to the rate of starch ethanol construction in recent years. Table 1.2-2 

shows a summary of the figures used in the analysis. 

71
 
 

Table 1.2-2. 

Summary of figures used in the ethanol plant construction rate analysis 2001-2022. 

Starch Ethanol Cellulosic Ethanol 

Build Avg Plant Capacity Industry Build Avg Plant Capacity Industry 

Rate Capacity Change Capacity Rate Capacity Change Capacity 

Year Plants/yr Mgal/yr Bgal/yr Bgal/yr Plants/yr Mgal/yr Bgal/yr Bgal/yr 

2001 1.8 

2002 6 50 0.3 2.1 

2003 14 50 0.7 2.8 

2004 12 50 0.6 3.4 

2005 10 50 0.5 3.9 

2006 20 50 1.0 4.9 

2007 16 100 1.6 6.5 

2008 27 100 2.7 9.2 

2009 20 100 2.0 11.2 

2010 15 100 1.5 12.7 2 40 0.1 0.1 

2011 10 100 1.0 13.7 5 40 0.2 0.3 

2012 8 100 0.8 14.5 7 40 0.3 0.6 

2013 5 100 0.5 15.0 10 40 0.4 1.0 

2014 15.0 12 80 1.0 1.9 

2015 15.0 15 80 1.2 3.1 

2016 15.0 17 80 1.4 4.5 

2017 15.0 18 80 1.4 5.9 

2018 15.0 20 100 2.0 7.9 

2019 15.0 20 100 2.0 9.9 

2020 15.0 20 100 2.0 11.9 

2021 15.0 20 100 2.0 13.9 

2022 15.0 20 100 2.0 15.9 

This work suggests that it may be feasible to construct plants quickly enough to meet the 

standard if plant starts can reach a rate as high as for starch ethanol in recent years. While 

cellulosic plant technology is still developing, it is expected that the plants will be considerably 

more complex and expensive to construct than the starch ethanol plants being built today. 

Therefore, we believe the market will need to react even more quickly with capital funding, as 

well as design and construction resources. 

1.3 Agricultural Residue Harvesting, Storage & Transport 

The amount of agricultural residue that can be removed is limited by how much residue 

must be left on the field to maintain soil health and by the mechanical efficiency (inefficiency) of 

the harvesting operation. We have already discussed sustainable removal rates in Section 1.1 

and will discuss the technical challenges related to the harvesting, storage, and transport of 

agricultural residues in the following sections. 

1.3.1 Harvesting Technologies 

The amount of residue that can be harvested from any one field is dependent on the 

combined mechanical inefficiencies of the harvesting operation and on the health of the soil. 

72
 
Even if 100% of the residue could be removed, from a soil health perspective, the mechanical 

inefficiencies of the harvest operation make it impossible to remove that much residue. A 

controlling principle is that increasing amounts of dry matter are lost as the stover is handled by 

increasing numbers of different machines. 

Corn stover harvest, at present, requires multiple machines: combines, shredders, rakes, 

balers, bale wagons, and stackers just to get the stover bales to the side of the field; dry matter is 

lost during each operation. Currently, there are no harvesting machines designed specifically for 

residue harvest, other than perhaps, for small grain straws that use common hay equipment. One 

proposal for corn stover harvest is to shut the spreader off on the grain combine in order to form 

a windrow, of sorts, following which the windrow is baled.235 However, modern combines leave 

most of the stalk standing. In order to harvest as much of the stover as possible, it is necessary to 

shred the standing stalks and then rake all of it together prior to baling.236 The baler pickup must 

be set high enough to avoid picking up dirt and dirt clods, the dirt-particles from which are very 

hard on harvesting equipment and that would demand a cleanup stage in downstream processing, 

which of itself would translate into overall dry matter losses. As such, it is likely that the baler 

will leave some amount of stover. 

Small grain straws, such as those from wheat, oats, barley, and rice have been harvested 

for many years. A significant difference between the harvesting equipment used for corn stover 

and these grains, is that the small grain plant is cut off near the ground and passes through the 

combine at the time of harvest. It falls to the ground from the harvester into somewhat of a 

windrow; in some cases, the windrow many need to be raked together before baling to gain 

maximum removal efficiency. Since the whole grain plant had dried prior to harvest, it’s not 

necessary to wait for the straw to dry before it’s baled. Small grain straws can be baled, hauled, 

and stacked in standard small bales or in larger 3’ x 4’ x 8’ square bales with current hay 

equipment. 

Sugarcane bagasse is not harvested, in the sense we’ve discussed ‘a harvest.’ It is a 

byproduct of sugar production from sugarcane, delivered by truck and trailer from the sugar 

processing facility to the ethanol plant. 

We anticipate that by 2022, the corn stover harvest will actually be reduced to a singlepass operation during which the amount of residue left on the field will be less a function of 

harvest efficiency and more a function of the farmer/grower and the harvesting company being 

able to determine how much residue must be left to maintain soil health. A combine designed 

specifically for the job must still be constructed, but we expect that it will cut the whole stalk a 

few inches above the soil, leaving some stalk anchored to the ground. A single-pass harvester 

could cut the entire plant a few inches above the ground and pull all of it, e.g., stalks, leaves, 

cobs, and grain into the combine, where they become a single, mixed grain and stover stream. 

The harvester blows the entire stream into tractor-pulled grain-carts that run along-side the 

harvester. When a cart is filled, it is replaced by an empty cart, and the full cart is hauled to the 

field side, where it’s unloaded into bulk ‘walking-floor’ semi trailers, and hauled to a co-op or 

depot type elevator/facility for further processing and storage. At the elevator, the stover/grain 

mix is unloaded into equipment for further processing before it’s sent to storage. Although a 

facility (equipment, buildings, etc.) at an elevator for separating the corn grain from the stover 

73
 
 

 

has not been constructed, we anticipate that it could operate very much like a modern grain 

harvester/combine, except it will obviously be stationary. The entire stream could be fed, by 

chain or belt, where it drops between a cylinder covered with rough steel bars and a piece of 

equipment called a concave. As the cobs are rubbed between the steel bars and concave, the 

corn grain rubs off and drops onto a perforated belt; most of the stover remains are larger than 

corn grain pieces, and is moved rearward toward the spreader. The corn grain and small stover 

particle fall through and are carried to a chaffer. 

One of the issues yet to be solved is how the proper quantity of residue required for soil 

maintenance is either left on or returned to the field and how it will be evenly spread. This of 

course could add another operation or two and would likely require heavy equipment to travel on 

fields, which would undoubtedly exacerbate compaction problems. We don’t anticipate any 

major future changes in the way the small grain straws will be harvested. 

1.3.2 Feedstock Storage 

We expect corn stover bales and small grain straw bales will be stored in similar ways. 

There has been some discussion about storing bales (of any of the feedstocks) out in the open, on 

gravel; few suggest storing them on dirt. Large, round stover bales store better in the open than 

large square bales, in that rain and particularly snow collect on flat surfaces more readily than on 

round. Another important issue that impacts whether round or square bales are used is that round 

bales can usually be stacked only three-bales high, in a kind of pyramid-shaped stack. One result 

of stacking round bales higher is that because of the low bale density, they tend to deform and 

the stack becomes unstable and there is an increased chance of dry matter loss. Square bales can 

be stacked as many as five-high and remain stable. 

As discussed in Section 1.3.1, we anticipate that the stover harvest could become a 

single-pass operation. Equipment at the elevator/depot separates the stover from the grain, 

following which the stover is chopped and dried. This distributed preprocessing facility can 

provide significant cost benefits by producing a higher value feedstock with improved handling, 

transporting, and merchandising potential. In addition, data supporting the preferential 

deconstruction of feedstock materials due to their bio-composite structure identifies the potential 

for significant improvements in equipment efficiencies and compositional quality upgrades.237 

The stover, now with flowability characteristics similar to small cereal grains, is moved by 

standard grain loading and unloading systems into large corrugated steel bins for intermediate 

storage. In this harvest format, the stover is handled by only two machines before it reaches the 

roadside and never hits the ground. Dry matter losses should be significantly reduced. 

Harvesting wet stover as chopped material, similar to animal forage, and ensiling it in a 

silo bag can be done successfully, with dry-matter (DM) matter loss at about 11% after seven 

months storage. Harvesting wet stover by baling and tube wrapping was also successful with 

DM losses of 3.6%. Dry stover bales stored indoors or outdoors had average DM losses of 5% 

and 15%, respectively. Wrapping dry bales in net wrap and storing on a well drained surface 

significantly reduced DM loss compared to storing twine wrapped dry bales on the ground.238 

74
 
 

 

 

Indoor storage is, in most cases, a concrete slab with a roof, supported by poles, with 

open sides (pole-barn). Depending on the number of bales to be stored, the slab must be sized to 

include aprons around all four edges with aisles between stacks to accommodate stacking and 

hauling equipment and for fire safety. Corn stover is usually harvested only once per year during 

an approximately 50- to 70-day period; this period is bounded by the time the corn grain harvest 

begins and the onset of winter weather, which is usually wet, and could include snow cover. As 

a result, the quantity of stover an ethanol plants expects to use until the next harvest (~one-year) 

must be harvested and stored during the same period. We don’t expect that a full-year’s worth of 

feedstock for most ethanol plants will be stored at the plant site; for larger plants the storage site 

would cover several hundred acres and the logistics of hauling and stacking the required number 

of bales would be impossible. If the bales are to be stored as large, square baled, in satellite 

storage, we anticipate that pole-barn type storage will be used. A similar slab and pole-barn 

would be constructed at the ethanol plant to store three- or four-days of feedstock.R 

Sugarcane bagasse is high in moisture, typically 60 to 75 percent, that is packed in 

storage and sealed as much as possible to reduce the amount of oxygen that would otherwise 

promote rotting. On the other hand, the anaerobic fermentation in the ensilage creates lactic acid 

that acts as a preservative. 

In the future, as we described in Section 1.3.1, we expect stover will be ground into 

particles that are small and stable enough that they can be handled and stored using methods and 

equipment currently used for grains of all kinds, e.g., silos or tanks. 

1.3.3. Feedstock Transport 

Baled Format: Following the baling operation, we expect stover bales will be picked up 

from the field in 10-bale loads, by vehicles designed for that purpose (such vehicles are currently 

used to gather hay bales); the bales are subsequently unloaded or dropped at the field-edge. 

Later, the bales are loaded onto wagons pulled by high-speed tractors that haul as many as 20­

bales per load to satellite storage (the pole-barns described in Section 1.3.2). The bales are 

unloaded and stacked for storage until they are needed at the ethanol plant. Transport to the 

plant is by over-the-road trucks and trailers that can haul net-loads of up to about 45- to 50-tons. 

However, because the bale density is low (on average, about half the weight of a similarly sized 

hay bale), the maximum number of bales a truck can haul usually weighs much less than the 

maximum allowable weight. We expect small grain straws will be handled in much the same 

way. Sugarcane bagasse can contain as much as 60% to 75% moisture and is usually hauled in 

open-topped metal trailers from which the bagasse can be dumped onto belts or into auger 

hoppers that convey it to ensilage type storage. 

As we pointed out in the previous paragraph, low bale density usually means that trucks 

and trailers can’t haul the maximum allowable weight, which translates into increased 

transportation costs. We anticipate that drying and grinding the stover (and possibly the other 

residues) will increase its bulk density and allow the transports to haul maximum weight loads to 

the ethanol plant. 

R We discuss this information in greater detail in subsection 4.1.1.2 of this chapter. 

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Grain Elevator Format: According to process requirement, an ethanol plant could pick up 

its feedstock from the elevator/depot in trucks and trailers for transport to the facility. We 

believe stover feedstock in the ground format will have a significantly higher bulk-density than 

baled stover, which should translate into lower transportation costs. 

1.4 Biofuel Production Technologies

 Biofuel production technologies continue to evolve with research and development 

efforts focused on reducing costs and increasing efficiencies. Improvements include increasing 

conversion yields for various feedstocks, reducing energy and materials usage, eliminating or 

reducing wastes, finding alternative uses for by-products, etc. For those technologies not yet 

commercial, researchers are combining their innovative ideas to develop cost-effective processes 

to produce biofuel at low enough costs to compete with their petroleum counterparts. The 

following sections describe both proven and new technologies which may be used to produce 

renewable fuels to meet the EISA 36 billion gallon standard by 2022. 

1.4.1 Corn Ethanol 

There are two primary processes for converting corn (and other similarly processed 

grains) into ethanol: wet milling and dry milling. The main difference between the two is in the 

treatment of the grain. Dry mill plants grind the entire kernel (shown below in Figure 1.4-1) and 

generally produce only one primary co-product: distillers grains with solubles (DGS). The coproduct is sold wet (WDGS) or dried (DDGS) to the agricultural market as animal feed. Wet 

mill ethanol plants separate the grain kernel prior to processing into its component parts and 

produce other co-products (usually gluten feed, gluten meal, and food-grade corn oil) in addition 

to DGS. Each process is described in greater detail in the subsections that follow. 

Figure 1.4-1. Components of the Corn Kernel 

ENDOSPERM 

Contains nearly all the 

starch used to make 

ethanol and also 

contains protein used in 

animal feed. 

TIP CAP 

Attachment point of the 

kernel to the cob. 

PERICARP/BRAN 

The protective covering of 

the kernel. Contains fiber 

used in human and animal 

food products. 

GERM 

Contains corn oil used in food 

applications as well as 

biodiesel production. 

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1.4.1.1 Dry Milling Technology239 

In traditional dry mill plants, first the corn is screened to remove any unwanted debris. 

Then, it goes through a hammer mill where it is ground into course flour also know as “meal.” 

Next the meal is cooked to physically and chemically prepare the starch for fermentation. 

The first step of the cooking process is to form a hot slurry. The meal is mixed with 

water, the pH is adjusted, and an alpha-amylase enzyme is added. The slurry is heated to 180– 

190°F for about 30–45 minutes to reduce viscosity. 

The second step in the cooking process is liquefaction, which occurs in two steps. First 

the hot slurry is pumped through a pressurized jet cooker at approximately 220°F and held for 

about 5 minutes. The mixture is then cooled by an atmospheric or vacuum flash condenser. 

After cooling, the mixture is held for 1–2 hours at 180–190°F to give the alpha-amylase enzyme 

time to break down the starch into short-chain carbohydrates also know as “dextrins.” Once 

cooking is complete, a pH and temperature adjustment is made, a second enzyme (glucoamylase) 

is added, and the resulting mixture (also know as “mash”) is pumped into the fermentation tanks. 

During the fermentation process, the glucoamylase enzyme breaks down the dextrins to 

form simple sugars. Yeast is added to convert the sugar into ethanol and carbon dioxide. The 

mash is then allowed to ferment for 50–60 hours. The result is a mixture that contains 10-15% 

ethanol by volume (20 to 30-proof) as well as solids from the grain and added yeast. 

From here, the fermented mash is pumped into a multi-column distillation system where 

additional heat is added. The columns utilize the differences in the boiling points of ethanol and 

water to boil off and separate the ethanol. By the time the product stream leaves the distillation 

columns, it contains about 95% ethanol by volume (190-proof). The residue from this process, 

called stillage, contains non-fermentable solids and water and is pumped out from the bottom of 

the columns into the centrifuges. 

The final step in the ethanol production process is dehydration to remove the remaining 

5% water. The ethanol is passed through a molecular sieve to physically separate the water from 

the ethanol based on the different sizes of the molecules. This result is 200-proof anhydrous 

(waterless) ethanol. At this point, denaturant is added (making it unfit for human consumption) 

and the ethanol is placed into storage. 

During the ethanol production process, two primary co-products are created: carbon 

dioxide and distillers grains. As yeast ferment the sugar, they release large amounts of carbon 

dioxide gas. In some plants it’s released into the atmosphere, but where local markets exist, it’s 

captured and purified with a scrubber and sold to the food processing industry for use in 

carbonated beverages and flash-freezing applications. 

The stillage from the bottom of the distillation columns contains solids from the grain and 

added yeast as well as liquid from the water added during the process. It is separated via 

centrifuge into thin stillage (a liquid with 5–10% solids) and wet distillers grain. 

77
 
Some of the thin stillage is routed back to the cooking tanks as makeup or “backset” 

water, reducing the amount of fresh water required by the cooking process. The rest is sent 

through a multiple-effect evaporation system where it is concentrated into a condensed distillers 

solubles or “syrup” containing 25–50% solids. This syrup, which is high in protein and fat 

content, is then mixed back in with the distillers grain to make wet distillers grains with solubles. 

Wet distillers grains with solubles (WDGS) contain most of the nutritive value of the 

original feedstock (plus added yeast) and can be easily conveyed as a wet cake for transport. As 

such, WDGS makes an excellent cattle ration for local feedlots and dairies. However, WDGS 

must be used soon after it’s produced because the wet grains spoil easily. Since many ethanol 

plants are located in areas where there are not enough nearby cattle to utilize all the feed, a 

portion or all of the WDGS is sent through a drying system to remove moisture and extend the 

shelf life. The resulting dried distillers grains with solubles (DDGS) are commonly used as a 

high-protein ingredient in cattle, swine, poultry, and fish diets. Distillers grains are also being 

researched for human consumption. A schematic of a typical dry-mill ethanol plant is shown 

below in Figure 1.4-2. 

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Figure 1.4-2. Dry Milling Process 

1.4.1.2 Wet Milling Technology240 

In wet mill plants, first the corn is soaked or "steeped" in a dilute sulfurous acid solution 

for 24-48 hours. The steeping process facilitates the separation of the corn kernel into germ, 

fiber, gluten, and starch. 

After steeping, the corn slurry is processed through a series of grinders to separate out the 

germ. The germ is either extracted on-site or sold to crushers who extract the corn oil. The corn 

oil in its crude state can be sold to the biodiesel or renewable diesel industry. However, most 

wet mill plants refine the product into food-grade corn oil for use in cooking applications. The 

remaining fiber, gluten and starch components are further segregated using centrifugal, screen, 

and hydroclonic separators. 

The steeping liquor is concentrated in an evaporator. This concentrated product, heavy 

steep water, is co-dried with the fiber component and is then sold as corn gluten feed to the 

livestock industry. Heavy steep water is also sold by itself as a feed ingredient and is used as a 

component in Ice Ban, an environmentally-friendly alternative to salt for removing ice from 

79
 
 

roads. 

The gluten component (protein) is filtered and dried to produce the corn gluten meal coproduct. This product is highly sought after as a feed ingredient in poultry broiler operations. 

The starch and any remaining water from the mash is generally processed in one of three 

ways: fermented into ethanol, dried and sold as dried or modified corn starch, or processed into 

corn syrup. If made into ethanol, the fermentation process is very similar to the dry mill ethanol 

production process described above. A schematic of the wet milling process is shown below in 

Figure 1.4-3. 

Figure 1.4-3. Wet Milling Process 

1.4.1.3 Advanced Technologies 

A number of corn ethanol plants are pursuing technological advancements such as cold 

starch fermentation, dry fractionation, and corn oil extraction to improve plant yields and reduce 

energy requirements. Research is also being done that looks at adding membranes to reduce 

ethanol distillation requirements. Finally a growing number of companies are utilizing 

alternative boiler fuels and/or incorporating combined heat and power (CHP) technology into 

their facilities to reduce to plant energy requirements, and in some cases, produce excess power 

for the grid. The advanced technologies currently being pursed by the corn ethanol industry are 

described in more detail below. 

80
 
 

 

 

Cold Starch Fermentation241242 

POET Biorefining, the United States’ largest corn ethanol producerS, has developed a 

cold starch fermentation process that uses raw-starch hydrolysis to convert starch to sugar, which 

then ferments to ethanol without heat. The patent-pending POET technology eliminates the 

cooking process that has been part of ethanol production for years. According to POET, the 

BPXTM process not only reduces energy costs, but also releases additional starch for conversion 

to ethanol, increases protein content and quality of co-products, increases co-product flowability, 

potentially increases plant throughput, and significantly decreases plant emissions. The benefits 

of the process include reduced energy costs, increased ethanol yields, increased nutrient quality 

in the distillers grains and decreased plant emissions. At the time of our industry assessment, 

BPXTM was reportedly used in 20 of POET's 22 U.S. ethanol plants. According to POET, the 

BPXTM process, which yields 20% ethanol in fermentation, increases theoretical ethanol yields 

from the industry standard of 2.7 gallons of ethanol per bushel of corn up to 3 gallons per bushel. 

Earlier this year, POET also announced that it was funding a research collaboration with Iowa 

State University to help improve the efficiency of the BPXTM process. 

Dry Fractionation 

Dry fractionation is a mechanical separation of the corn kernel into its three component 

pieces, the germ, bran, and endosperm before fermentation. This separation decreases the 

amount of non-fermentable material sent through the process and allows each of the components 

to be processed separately to produce new, higher-value co-products. As shown in Figure 1.4-1, 

the germ is a small, non-fermentable part of the kernel consisting predominantly of protein and 

oil. Food grade corn oil can be extracted from the germ. After the oil has been extracted, the 

remainder of the germ can then be blended into the DGS to increase its protein content. The 

bran, or pericarp, is the protective outer covering of the kernel. The bran can be sold as cattle 

feed, human fiber additive, or corn fiber for oil extraction. It can also be burned to reduce the 

amount of coal or natural gas required for ethanol production. The endosperm, which contains 

approximately 98% of the starch and is the only fermentable portion of the kernel, is sent to the 

fermentation vessels. Decreasing the amount of non-fermentable materials (germ and bran) in 

the process has many beneficial effects, including increasing the production capacity of the plant, 

decreasing the energy required to dry the DGS, and potentially decreasing the enzyme 

requirement of the plant but up to 30%. Dry fractionation is currently only used by a few ethanol 

plants; however several companies, including ICM, Delta-T, and POET currently offer dry 

fractionation options for new or existing plants. 

Corn Oil Extraction243 

Several dry mill corn ethanol plants have implemented corn oil extraction to produce 

fuel-grade corn oil for the biodiesel industry. The crude corn oil can either be extracted from the 

thin stillage (the non-ethanol liquid left after fermentation) before it enters the evaporator, or 

from the DGS after it has been dried. While the corn oil is of a lower quality and value than that 

produced from corn fractionation, the equipment can be easily added to existing ethanol 

production facilities and is relatively inexpensive. In addition to generating an additional 

S

 At the time of our May 2008 plant assessment. For more information, refer to Figure 1.5-4 in Section 1.5.1.1. 

81
 
 

revenue stream from the fuel-grade corn oil, reducing the oil content of the DGS improves its 

flowability and concentrates its protein content. The de-fatted DGS is more marketable than 

DGS containing corn oil as higher quantities can be included in dairy and beef cattle feed. 

Membrane Replacement 

Several companies are currently working to produce commercially viable polymeric 

membranes that could potentially reduce the energy used in distillation and eliminate the need 

for molecular sieve units currently used in most ethanol plants. One such company, Vaperma, 

has partnered with GreenField Ethanol to prove the viability of its SiftekTM technology. SiftekTM 

membranes have been successfully installed in GreenField’s Tiverton, Ontario demonstration 

plant and are scheduled to be installed in their Chatham, Ontario plant, which produces 187 

million liters of ethanol per year, by the end of 2008. Vaperma claims its SiftekTM membranes 

are capable of producing a fuel grade ethanol product from an ethanol/water mixture that 

contains as much as 60% water. These membranes would replace the rectifier unit as well as the 

molecular sieves used in a conventional ethanol plant, potentially reducing the energy 

consumption of the ethanol dehydration process by up to 50%. Another way for these 

membranes to be used is to treat the ethanol/water vapor collected when the molecular sieve 

units are regenerated. This stream is usually recycled to the rectifier and makes up 

approximately one third of the feed to the rectifying column. Using SiftekTM technology to treat 

this stream reduces the feed to the rectifier, reducing energy consumption and increasing 

production rate by 20% or more. While membrane replacement technology has the potential to 

significantly reduce the energy demands of an ethanol plant, they are likely at least a couple of 

years from being commercially available. It is not expected that membrane replacement units 

would be retrofitted into existing plants due to the significant capital costs. These two factors 

will effectively limit the use of membrane separation units to new ethanol plants built in 2010 or 

later. 

An alternative method of membrane replacement is to use ethanol-permeating 

membranes to eliminate the need for the beer column, followed by a water-selective membrane 

for final dehydration. Eliminating the need for the beer column as well as the rectifier and 

molecular sieve units would significantly reduce the capital costs of an ethanol plant, as well as 

lowering the energy requirements of ethanol separation. While this technology has the potential 

to significantly lower the cost and energy demands of an ethanol plant, it is highly unlikely that it 

will be available for near term commercialization. It has therefore not been considered section 

1.5.1.3 on the forecasted growth of advanced ethanol technologies. If more information becomes 

available we will consider including this method in the energy usage forecast for the final rule. 

Combined Heat and Power244 

Ethanol production is a relatively resource-intensive process that requires the use of 

water, electricity, and steam. In most cases, water and electricity are purchased from the 

municipality and steam is produced on-site using boilers fired by natural gas, coal, or in some 

cases, alternative fuels (described in more detail below).T

 However a growing number of ethanol 

T

 There are a few ethanol producers that we have been made aware of from EPA Region 7 that pull their steam from 

a nearby utility. 

82
 
producers are pursuing combined heat and power (CHP) technology. CHP, also known as 

cogeneration, is a mechanism for improving overall plant efficiency by using a single fuel to 

generate both power and thermal energy. The most common configuration in ethanol plants 

involves using the boiler to power a turbine generator unit that produces electricity, and using 

waste heat to make process steam. In some cases, the generator produces excess electricity that 

can be sold to the grid. While the thermal energy demand for an ethanol plant using CHP 

technology is slightly higher than that of a conventional plant, the additional energy used is far 

less than what would be required to produce the same amount of electricity in a central power 

plant. The increased efficiency is due to the ability of the ethanol plant to effectively utilize the 

waste heat from the electricity generation process. 

The CHP system can be owned and operated solely by the ethanol plant, or jointly 

operated with the local utility company. In these cases it is common for the utility company to 

purchase the generator and to split the cost of the generator fuel with the ethanol plant. The 

utility company receives the electricity produced, while the ethanol plant uses the waste heat. 

These arrangements reduce the energy costs for both parties, as well as reducing the green house 

gas emissions that would be produced by operating the generator and boiler separately. An 

illustration of the more common CHP configuration typically seen in ethanol plants is shown 

below in Figure 1.4-4. 

Figure 1.4-4. Steam Boiler with Steam Turbine 

Alternative Boiler Fuels 

In addition to CHP (or sometimes in combination), a growing number of ethanol 

producers are turning to alternative fuel sources to replace traditional boiler fuels (i.e., natural 

gas and coal), improve their carbon footprint, and/or become more self-sustainable. Alternative 

boiler fuels currently used or being pursued by the ethanol industry include biomass (wood and 

other organic feedstocks), co-products from the ethanol production process (bran, thin stillage or 

83
 
 

 

 

syrup), manure biogas (methane from nearby animal feedlots), and landfill gas (generated from 

the digestion of municipal solid waste). 

For a breakdown of current and near-termU utilization of CHP technology and alternative 

boiler fuels, refer to Sections 1.5.1.1 and 1.5.1.2. For our 2022 projections of the potential 

utilization of these and other advanced technologies, refer to Section 1.5.1.3. 

1.4.2 Ethanol from Sugarcane Juice and Molasses 

The production of ethanol from sugarcane juice or molasses is the least complicated 

method to use biomass to produce ethanol since sugarcane contains six-carbon sugars that can be 

directly fermented. This is currently the method used to produce ethanol in Brazil. In contrast, 

starch or cellulosic feedstocks require additional steps before sugars are released for use in the 

fermentation step. In addition to ethanol, sugarcane also yields trash, bagasse, filter cake mud, 

and vinasse. These by-products are described below: 

Trash (Leaves and Tops) 

The tops, brown and green leaves of sugarcane are commonly referred to as trash. 

Sugarcane trash is not currently harvested for production of ethanol. Much of the U.S. sugarcane 

trash is currently mechanically harvested and delivered to the factory with stalks, where it 

detrimentally affects industrial processing. However, there has been growing interest to use 

hydrolysis (cellulosic) technologies to convert trash to ethanol because it is easier to hydrolyze 

than bagasse, as the trash contains less lignin. Sugarcane trash can also be converted into 

bioelectricity. 

Bagasse 

Bagasse is the fibrous material left over after juice is extracted from the crushed stalk of 

the sugarcane plant. It mainly consists of hemicellulose, cellulose and lignin valued mainly for 

being a fossil fuel and wood substitute in steam energy generation. U.S. factories and other 

industrial units have used bagasse mainly for steam production, but a few are producing 

electricity (co-generation) as well. In Brazil, some facilities are able to produce more energy 

than needed and have exported excess electricity to the grid. 

Filter Cake Mud 

Filter cake is the dried, leftover solid material from precipitated mud after the sugarcane 

juice clarification (via lime addition) at the facility. It is sometimes reapplied to sugarcane fields 

as a fertilizer. 

Vinasse 

Vinasse is the liquid waste product from the ethanol distillation process. It is rich in 

minerals, organic material, and water. It is produced and used throughout the harvest in Brazil. 

U Based on current company plants. 

84
 
 

Some countries are allowed to spray vinasse on sugarcane crop as fertilizer (not allowed in the 

U.S.). There is environmental legislation which prohibits inappropriate disposal of vinasse into 

rivers, lakes, the ocean, and soils. 

In the production of sugarcane ethanol and sugar from sugarcane juice or molasses, the 

cane stalks are shredded and the juice is extracted across tandem mills or a diffuser. The juice 

contains most of the soluble sugars and the leftover sugarcane fiber is bagasse. Next, the cane 

juice is filtered then heated and limed to precipitate impurities during the clarification process. 

The resultant clarified juice is then concentrated across an evaporation station (14-16°Brix up to 

65°Brix). The syrup produced is then further evaporated in vacuum pans and seed crystallized, 

leading to a mixture of sucrose crystals surrounded by molasses with a concentration of 91­

93°Brix. The sugar crystals and molasses are subsequently separated by centrifugation. In 

ethanol production in Brazil, the sugars in juice or diluted are fermented into ethanol by the 

addition of yeast. Fermentation varies from 4-12 hours, with ethanol yields ranging from 80­

90%. The fermented mixture is then distilled to produce hydrous (96 % ethanol) or anhydrous 

ethanol (99.7 % ethanol). The production of anhydrous ethanol is normally done by addition of 

cyclohexane. See Figure 1.4.5 for a diagram of the sugarcane ethanol and sugar production 

process.245 The production of sugar (for food and export) or ethanol depends on the supply and 

demand changes for both products. 

Figure 1.4-5. Simplified Overview of Sugarcane Ethanol and Sugar Production Process 

1.4.3 Cellulosic Biofuel 

The following sections contain descriptions of cellulosic ethanol and cellulosic diesel 

production technologies. Section 1.4.3.1 introduces the two primary pathways for the production 

of cellulosic ethanol, through biochemical and thermochemical processes while Section 1.4.3.2 

discusses cellulosic diesel which is produced through thermochemical processes. We end the 

section with specific company descriptions of cellulosic biofuel technologies and briefly describe 

how they differ from generic process discussions. 

85
 
1.4.3.1 Cellulosic Ethanol 

Cellulosic biomass has long been recognized as a potential source of mixed sugars for 

fermentation to fuel ethanol. The Germans may have been one of the earliest to try 

commercializing a process to produce ethanol from a cellulosic feedstock, probably from wood 

in the late 1890s. They used dilute acid to hydrolyze the cellulose to glucose and xylose, but 

were able to only produce a little less than 20 gallons per ton of feedstock; they soon improved 

the process enough to generate yields of around 50 gallons per ton. Eventually, two commercialsized plants that used dilute sulfuric acid hydrolysis were constructed in the U.S. Yields from 

the U.S. facilities were roughly half that of the German plants, however, the production rate from 

U.S. facilities was significantly higher. Lumber production decreased following World War I, 

which resulted in the close down of cellulosic plants.246, 247 Although corn-grain ethanol was used 

in the early 20th Century, especially by high-performance race cars and as an additive to raise 

gasoline octane, petroleum-derived gasoline eventually replaced it as the primary fuel for 

automobiles and light-duty trucks. From the early 1970’s and up through the present, ethanol 

from corn, has been increasingly used as a fuel; however, recently, ethanol from cellulose is 

being viewed with increasing interest. 

Several processing options are currently available to convert cellulosic biomass into 

ethanol. These conversion technologies generally fall into two main categories: biochemical and 

thermochemical. Biochemical conversion refers to the fermentation of sugars liberated from the 

breakdown of biomass feedstock. Thermochemical conversion includes the gasification and 

pyrolysis of biomass material into a synthesis gas for subsequent fermentation or catalysis. The 

main benefit of gasification/pyrolysis over the biochemical route is that thermochemical 

processes can more easily convert low-carbohydrate or “non-fermentable” biomass materials 

such as forest and wood residues to alcohol fuels and can more readily accept a wider variety of 

feedstocks.248 However, the thermochemical process does have some drawbacks, such as tar 

production and clean-up gas procedures that require additional capital investment. 

Since commercial production of cellulosic ethanol has not yet begun, it is unclear which 

process options will prove most viable or whether additional variations will emerge. At least in 

the near future, there have been plans to build both stand-alone biochemical and thermochemical 

ethanol processing plants. In addition, some investors are currently supporting research and 

development in both cellulosic processing procedures, neither choosing one conversion over the 

other.249 The following subsections describe the process steps, current challenges, and targeted 

areas for improvement for each conversion method. 

1.4.3.1.1 Biochemical Conversion 

Unlike grain feedstocks where the major carbohydrate is starch, lignocellulosic biomass 

is composed mainly of cellulose (40-60 %) and hemicellulose (20-40 %). The remainder 

consists of lignin, a complex polymer which serves as a stiffening and hydrophobic (waterhating) agent in cell walls.250 Cellulose and hemicellulose are made up of sugars residues linked 

together in long chains called polysaccharides. Once hydrolyzed, they can be fermented into 

ethanol. Currently, lignin cannot be fermented into ethanol, but could be burned as a by-product 

to generate electricity. 

86
 
Both starch (corn grain) and cellulosic feedstocks must be hydrolyzed prior to 

fermentation. Structural differences at the molecular level make it far more difficult, and 

therefore more costly, to hydrolyze cellulosic biomass than it is to hydrolyze starch. Glucose, 

C6H12O6, the repeating monomer in both starch and cellulose, is a six-sided ring, similar in 

conformation to the classic ‘chair’ conformation of cyclohexane or benzene, except one carbon 

atom in the ring is replaced by an oxygen atom. For uniformity (and ease) of discussion, it is 

generally assumed that the first carbon atom next to the oxygen, is carbon #1; the numbering, 2­

5, continues around the ring with oxygen in the 6th position; one of the four bonds of the fifth 

carbon atom is attached to the oxygen atom to complete the ring, one is attached to hydrogen 

atom and the fourth to a -CH2OH group. Thus, a glucose molecule/monomer is a six-sided 

molecule, but not a six-carbon ring (although there are six-carbon molecules present, one of 

which is in the –methylhydroxy group). 

The main difference between starch and cellulosic plant matter is that starch 

polysaccharides are made up of α-glucose monomers, uniformly strung together by α-linked 1,4­

glucosidic bonds whereas cellulosic polysaccharides are made up of β-glucose monomers, strung 

together through β-linked 1,4-glucosidic bonds. In starch with the α-conformation, the hydroxyl 

group on carbon #1 is in the axial or α-position, which causes the -OH’s on each successive 

glucose monomer to end up on the same side of the polymer. There are also 1,6-linked glucose 

branches that occur irregularly on approximately one in twenty-five glucose units.251 The -OH 

groups on the same side of the polymer, along with the randomly attached 1,6-glucose branches, 

leaves starch polymers relatively weak, flexible, and able to easily wrap and twist together to 

form tiny granules, e.g., common, everyday corn starch. 

Cellulosic polysaccharides are in the β-conformation with the hydroxyl group on carbon 

#1 is positioned away from the ring, in the equatorial or β-position, which causes the -OH’s on 

each successive glucose monomer, added to the chain, to end up on opposite sides of the 

polymer. The hydroxyl groups lined up evenly and uniformly along opposite sides of each 

polymer strand allow intra-molecular hydrogen bonds to develop within each monomer. They 

also allow inter-molecular hydrogen bonds to develop between adjacent polymers to form tight, 

rigid, strong, mostly straight polymer bundles called microfibrils that act as the core constituent 

in the formation of plant cell walls that are also insoluble in water and resistant to chemical 

attack. The β-conformation and the resulting hydrogen bonds stabilize the glucose chair 

structure to help minimize the polymer’s flexibility (which hinders hydrolysis) and to add to its 

strength. 

The second cellulosic component is called hemicellulose. It consists mainly of a random 

mixture of highly branched and heavily substituted five- and six-carbon rings. The five-carbon 

residues are usually D-xylose and L-arabinose; the six-carbon residues are usually D-galactose, 

D-glucose, and D-mannose, and uronic and acetic acid. Hemicellulose is not as rigid or strong as 

cellulose, but does contribute additional strength and helps protect the plant cell wall against 

attack by microbes or water. Hemicellulose is relatively easy to hydrolyze, due to its highly 

branched, somewhat random or non-uniform structure. 

Lignin, the third principle component, is a complex, cross-linked polymeric, high 

molecular weight substance derived principally from coniferyl alcohol by extensive condensation 

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polymerization. Covalently bonded to the hemicellulose, it is essentially a glue-like polymer that 

covers the cellulose and hemicellulose polymer cell walls and helps hold them together, provides 

additional strength, helps resist microbial decay, and perhaps most importantly, for this 

discussion, inhibits hydrolysis. Its molecular weight is around 10,000.252 While both cellulose 

and hemicellulose contribute to the amount of fermentable sugars for ethanol production, lignin 

does not, but can be combusted to provide process energy in a biochemical plant or used as 

feedstock to a thermochemical process.253 

To review, a significant part of the reason it is more difficult and more costly to produce 

ethanol from cellulosic feedstocks, such as corn stover, has to do with the differences in the 

molecular structures of simple starch and those of cellulosic plant matter. That is, as a plant 

grows, glucose monomers are added to the polysaccharide chains of the plant cell walls through 

condensation reactions. In general, condensation is a chemical process by which two molecules 

are joined together to make a larger, more complex molecule, and a molecule of water is a 

byproduct of the reaction. In the formation of polysaccharides, and enzyme catalyzes the 

reaction wherein the -OH group on carbon #1 of one monomer, or glucose residue, reacts with 

the -OH on carbon #4 or #6 of another residue. An H-OH (H2O or water) molecule is removed 

leaving an -O- that links the monomers together to form the polysaccharide chain. Again, 

depending on the direction of the –OH group at carbon 1, it may be called an alpha (as in starch) 

or a beta (as in cellulose) linkage.254 

Hydrolysis is the reverse reaction. The -H from an H-OH (water) molecule is added to 

one monomer and the remaining -OH is added to its pair, e.g., to the next monomer on the chain, 

to regenerate separate glucose monomers. During starch hydrolysis, water and water borne 

hydrolyzing enzymes can easily penetrate the randomly formed polymers (the tiny granular 

particles or bundles) in order to break the bonds to release glucose monomers. However, the 

cellulosic or glucan polymers formed in tightly packed, dense, rigid microfibrils are especially 

resistant to water and hydrolyzing enzymes. Xylan, the main constituent of hemicellulose, is 

more easily hydrolyzed than cellulose, but not easily fermented. Cellulose is not easily 

hydrolyzed, but readily ferments. These are two of the major problems that must be 

satisfactorily resolved before cellulosic ethanol can become a competitive fuel. 

Biochemical conversion processes typically use dilute acid with enzymes or concentrated 

acid to convert cellulosic biomass to sugar for fermentation to ethanol. Concentrated acid 

hydrolysis is fairly well developed and is being pursued to commercialization in certain niche 

situations. For example, concentrated acid hydrolysis is suitable for feedstocks such as 

municipal solid wastes which have largely heterogeneous mixtures.255 Concentrated acid 

hydrolysis is typically much faster than enzymatic approaches, albeit at the cost of reduced sugar 

yields due to undesirable side reactions.256 Enzymatic hydrolysis is mostly suitable for 

homogeneous mixtures because specific enzymes are needed to convert a given type of 

feedstock. During the period covered by this proposed rule, the cost to enzymatically hydrolyze 

cellulose is expected to decline significantly as these technologies continue to improve.257 

In general, steps of the biochemical process include: feedstock pretreatment, hydrolysis, 

saccharification and fermentation, ethanol dehydration, and lignin recovery. Refer to Figure 1.4­

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6 for an illustration of the enzymatic biochemical production process. We used NREL’s study as 

a guide to describe, somewhat generically, how such a process might work.258 

Figure 1.4-6. 

Cellulosic Ethanol Biochemical Production Process (Enzymatic) 

Feedstock 

(e.g. corn stover) 

Feedstock 

Pretreatment 

Hydrolysis 

Saccharification 

Cellulase & 

enzymes Fermentation 

Ethanol 

Dehydration 

Lignin 

Recovery 

Fuel Ethanol Lignin 

Stage 1 – Feedstock Pretreatment 

Lignocellulosic biomass, such as the corn stover we’re currently discussing, must 

undergo at least some pretreatment prior to hydrolysis. During the early years of cellulosic 

ethanol production (e.g., 2010 to 2015), we anticipate that this stage will likely occur within the 

facility. In the out years covered by this rule (2022) we believe that this stage will likely be 

moved outside the plant gate (e.g., upstream of the ethanol plant) to reduce transportation costs 

that are typically high due to the low density of this type of biomass. The biomass is pretreated 

with either a physical or chemical pretreatment method to help the polysacharides become more 

accessible to hydrolysis. Studies have shown a direct correlation between the removal of lignin 

and hemicellulose and the digestibility of cellulose.259 

Physical pretreatment nearly always includes size reduction by some type of grinding, 

shredding, or chopping. For example, in order to biochemically process wood chips, e.g., poplar 

trees or willows, the chips must be reduced in size to 1-mm or less in order to increase the 

surface area for contact with acid, enzymes, etc. Breaking up a 5-in tree stem into 1-mm pieces 

89
 
 

would consume a large amount of energy. On the other hand, corn stover chips for a 

biochemical process can range up to a maximum size of 1.5 inches.260 

Chemicals are also used for pretreatment. The most common chemical pretreatment 

methods for cellulosic feedstocks are dilute acid, hot water, alkaline, organic solvent, ammonia, 

sulfur dioxide, carbon dioxide, or other chemicals to make the biomass more digestible by the 

261,262 enzymes. These chemicals cause the biomass to react quite differently.263 For example, 

instead of hydrolyzing the hemicellulose (as in acidic pretreatments), an alkaline approach tends 

to leave the hemicellulose and cellulose intact. Enzymes are therefore required to digest both 

hemicellulose and cellulose at the same time when a basic pretreatment is used. 

Different pretreatment approaches also affect the amounts of degradation products (e.g. 

furfurals, acetates) that occur from the decomposition of hemicellulose and lignin. This is 

important since these degradation products can inhibit microorganisms in the fermentation step. 

A well known pretreatment method that does not degrade biomass sugars or produce 

fermentation inhibitors is ammonia fiber expansion (AFEX). During AFEX, liquid ammonia is 

added to the cellulosic material followed by a rapid pressure release. 

Each type of feedstock, whether softwoods, corn stover or bagasse, requires a particular 

combination of pretreatment methods to optimize the yields of that feedstock, minimize the 

degradation of the substrate, and maximize the sugar yield. Pretreatment of cellulosic biomass in 

a cost-effective manner is a major challenge of cellulose-ethanol technology research and 

development.264 

Stage 2 – Pretreatment and Hydrolyzate Conditioning 

NREL refers to this stage as a combination of pretreatment and hydrolysis. In their 

process flow diagram, the washed and sized-reduced feed is directly heated with steam and 

mixed with dilute sulfuric acid. The process converts, primarily, the hemicellulose 

polysaccharides xylan, mannam, arabinan and galactan, to produce the mixed sugars and futher 

helps prepare the cellulose for hydrolysis. A small amount of glucan in the hemicellulose and in 

the cellulose is converted into glocose. The rundown from the acid hydrolysis reactor is fed to a 

blowdown tank that subsequently feeds a filter press. The filter press produces two main 

streams, a filter cake and a liquid filtrate, also called hydrolyzate. The filter cake carries the 

unhydrolyzed portions of the feed (e.g., glucans) among other insollubles, while the liquid 

carries that part of the feed that was hydrolyzed, mainly the xyloses. 

The liquid portion is neutralized to remove gypsum and other contaminants that would be 

toxic to downstream enzymes. The cake is washed, mixed back with the detoxified liquid 

hydrolyzate, and fed to the saccharification reactors to hydrolyze the glucan polysaccharides. 

Stage 3 – Saccharification and Co-Fermentation 

We should point out that this is not ‘Simultaneous Saccharification and Fermentation’ 

(SSF). Saccharification, in the process we’re discussing, takes place primarily in several reactors 

along with other intermediate treatments such as filtering and detoxifying. Using a cellulase 

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enzyme cocktail, saccharification of the cellulose to glucose occurs first at an elevated 

temperature to take advantage of increased enzyme activity, which reduces the quantity of 

required enzyme as well as the reaction time. 

The cellulase enzymes used to convert cellulose to sugars can be obtained in two ways. 

The first option is for a plant to produce it on-site. The second option requires the plant to 

purchase the enzymes from off-site enzyme manufacturers. Due to a joint research effort by 

DOE, Genencor International, and Novozymes Biotech, the cost for production of cellulase 

enzymes has been drastically reduced. Such research and development in areas of enzyme 

production have reduced the cost of cellulolytic enzymes by a factor of 10 to 30, down to 20 to 

30 cents per gallon of ethanol produced.265,266,267 It is estimated, however, that enzyme costs 

will have to be further reduced to a level comparable to those used to produce ethanol from corn 

grain at a cost of 3 to 4 cents per gallon of ethanol. The current challenge is to develop the 

correct enzyme “cocktails” to reflect differences in the physical and chemical characteristics of 

all the various types of cellulosic materials. It may be easier, therefore, to process single 

feedstocks (more homogeneous) rather than multiple feedstocks, in which variations are more 

likely. 

Following cellulose saccharification, both the glucose and xylose sugars are cofermented. Although xylan, the hemicellulose polysaccharide, is more easily hydrolyzed than 

glucan (cellulose polysaccharides), the xylose sugar is more difficult to ferment than is the 

glucose sugar. Different microbes as well as different residence times and process conditions 

may be required for each. 

Because xylan can make up as much as 25% of plant matter it is imperative that as much 

of it as possible be fermented; the economic viability of biochemically produced ethanol depends 

heavily it. This continues to be high on the list of problems researchers are working on, but good 

progress has been made toward fermenting a higher percentage of xylose during the past few 

268 years.

Stage 3A – Consolidated Bioprocessing e.g., Simultaneous Saccharification and Fermentation 

(SSF) 

During the past few years, researchers have been looking for ways to combine 

saccharification and fermentation into a single step through the use of enzyme/microbe cocktails. 

If successful, we expect there could be significant capital cost savings in that fewer reactors and 

other support equipment and piping would be necessary. Also, it may be possible to reduce 

processing times if hydrolysis reactions can take place simultaneously, rather than sequentially. 

Such strategies are known as consolidated bioprocessing (CBP). CBP, however, is currently 

hampered by the relative inability of yeast to process recombinant cellulases (enzymes that help 

convert cellulose to sugars), and the relative lag in the development of molecular biological 

methods to manipulate organisms that secrete cellulases naturally.269 

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Stage 4 – Ethanol Dehydration 

NREL’s process model indicates that the fermentation reactor rundown stream, now 

called ‘beer,’ runs down the beer column feed surge tank. The beer column feed consists of 

about 83% water and only 5.5% ethanol; the balance of the mixture is very complex, but consists 

mostly of lignin. The beer column removes the dissolved CO2 overhead and produces a 

water/ethanol bottom stream that is fed to a rectification column. According to NREL’s model, 

the rectification column bottoms would be mostly water with about 0.05% ethanol that’s 

recycled back to the process. The rectification column overhead that consists of about 92.5% 

ethanol and 7.5% water, is fed to a molecular sieve that produces a 99.5 wt.% ethanol product 

stream with about 0.5 wt.% water. Gasoline, a denaturant, is added to produce a 95 % to 98 % 

ethanol fuel. 

Stage 5 – Lignin Recovery 

Following the saccharification and fermentation of the xylan and glucan to ethanol, the 

lignin is gradually concentrated with other solids into a moist cake-like product that is about 48% 

insoluble solids. About 80% of the 48% insoluble solids is essentially lignin microbial cells, and 

other unconverted biomass remnants, (e.g., cellulose, xylose, glucan, xylan, other oligomers, 

etc.,) from the process. This material can be either combusted to provide process heat for the 

biochemical operation, for a co-located starch ethanol plant, or as we discuss in the following 

section, could be used as feedstock for a thermochemical unit. 

1.4.3.1.2 Thermochemical Conversion 

Thermochemical conversion involves biomass being broken down into intermediates 

using heat and upgraded to fuels using a combination of heat and pressure in the presence of 

catalysts.270 Thermochemical processes include pyrolysis (absence of oxygen), gasification 

(partial oxidation in the presence of a gasifying agent, usually air, oxygen, and/or steam), and 

combustion (complete oxidation). The former two conversion processes, pyrolysis and 

gasification, can be used to convert biomass into energy carriers for transportation use. It is 

important to note that these processing steps are also applicable to other feedstocks (e.g., coal or 

natural gas); the only difference is that a renewable feedstock is used (i.e. biomass) to produce 

cellulosic biofuel. A thermochemical unit can also complement a biochemical processing plant 

to enhance the economics of an integrated biorefinery by converting lignin-rich, non-fermentable 

material left over from high-starch or cellulosic feedstocks conversion.271 We discuss the 

gasification and pyrolysis processes below. 

Gasification 

Compared to corn ethanol or biochemical cellulosic ethanol plants, the use of biomass 

gasification may allow for greater flexibility to utilize different biomass feedstocks at a specific 

plant. Mixed biomass feedstocks may be used, based on availability of long-term suppliers, 

seasonal availability, harvest cycle, and costs. Agricultural residue, energy crops, forest residue, 

and municipal solid waste have been discussed as potential feedstocks. Geographic location, 

availability of biomass, the existence of biomass suppliers, and costs would all likely influence 

92
 
 

the mix of biomass feedstocks utilized. The general steps of the gasification thermochemical 

process include: feedstock handling, gasification, gas cleanup and conditioning, fuel synthesis, 

and separation. Refer to Figure 1.4-7 for a schematic of the thermochemical cellulosic ethanol 

production process through gasification. 

Figure 1.4-7. Cellulosic Ethanol Thermochemical Gasification Process 

Feedstock 

(e.g. forest residue) 

Feedstock 

Handling 

Gasification 

Gas Cleanup & 

Conditioning 

Fuel 

Synthesis 

Separation 

Fuel Ethanol 

(Other mixed alcohols if using catalyst) 

Stage 1 – Feedstock Handling 

The particle size requirement for a thermochemical process is around 10-mm to 100-mm 

in diameter.272 Once the feed is ground to the proper size, flue gases from the char combustor 

and tar reformer catalyst regenerator dry the feed from around 30% to 40% moisture to the level 

required by the gasifier. 

Stage 2 – Gasification 

There are two general classes of gasifiers. First, partial oxidation (POx) gasifiers 

(directly-heated gasifiers) use the exothermic reaction between oxygen and organics to provide 

the heat necessary to devolatilize biomass and to convert residual carbon-rich chars. In POx 

gasifiers, the heat to drive the process is generated internally within the gasifier. A disadvantage 

93
 
 

 

of POx gasifiers is that oxygen production is expensive and typically requires large plant sizes to 

improve economics. 

The second general class, called indirect gasification, uses steam gasifiers to accomplish 

gasification through heat transfer from a hot solid or through a heat transfer surface. Either the 

byproduct char and/or a portion of the product gas can be combusted with air (external to the 

gasifier itself) to provide the energy required for gasification. Although steam gasifiers have the 

advantage of not requiring oxygen, most operate at low pressure and therefore require product 

gas compression for downstream purification and synthesis unit operations. 273,274 

There are different subcategories of gasifiers which are either directly or indirectly 

heated. One subcategory is termed a bubbling fluidized bed gasifier and it employes a bubbling 

fluidized bed of inert material and the reactant (biomass) is also bubbled through the fluidized 

bed. A second variant is the circulating fluidized bed gasifier which is similar to the bubbling 

fluidized bed reactor except that a high feedstock and air flow rate circulates the fluidized bed 

out of and back into the reactor. For the fluidized bed, the bed material may either be inert 

alumina or sand which helps the heat transfer. There are also fixed bed reactors which either 

feed the reacting gas (oxygen or air) upward or downward through a fixed bed of the reactant 

(biomass). Because of the tar formed when using biomass as a feedstock, a second reactor is 

sometimes added which solely targets converting the tar to syn-gas. If the biomas feedstock is 

ground to a sufficiently small particle size, or liquefied, the biomass is considered to be 

“entrained” in the reactor, and the reactor is defined as an entrained flow reactor. 

Indirect gasification using an entrained flow gasifier is described for this example. The 

gasification process begins as the biomass is fed to the reactor containing a heat transfer media, 

such as sand, and is partially reacted with air (or oxygen) which is introduced to the bottom of 

the reactor. The air serves as the carrier-gas and as the oxidant for partially oxidizing the 

biomass to syn-gas, carbon monoxide and hydrogen. In addition to the syngas produced, char 

and coke are also formed. The heat for the endothermic gasification reactions is supplied by 

circulating heat transfer media (e.g. sythetic sand) between the gasifier and the char combustor. 

The heat generated by the combustion of the char and coke heats the heat transfer media to over 

1800°F. The syngas is separated from the sand and ash and sent to gas cleanup. 

Stage 3 – Gas Cleanup & Conditioning 

Once the biomass is gasified and converted to syngas, the syngas must be cleaned and 

conditioned. This raw syngas has a low to medium energy content depending on the gasifying 

agent and consists mainly of CO, H2, CO2, H2O, N2, and hydrocarbons. The minor components, 

tars, sulfur, nitrogen oxides, alkali metals, and particulates have the potential to negatively affect 

the syngas conversion steps. Therefore, unwanted impurities are removed in a gas cleanup step 

and the gas composition is further modified during gas conditioning. Gas conditioning steps 

include sulfur polishing to remove trace levels of H2S and water-gas shift to adjust the final 

H2/CO ratio for optimized fuel synthesis. 

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Stage 4 – Fuel Synthesis 

After cleanup and conditioning, the “clean” syngas is comprised of essentially CO and 

H2. The syngas is then converted into a liquid fuel by either a catalytic process or through the 

use of a microorganism. The fuel producer has the choice of producing diesel fuel or alcohols 

from syngas by optimizing the type of catalyst used and the H2/CO ratio. Diesel fuel has 

historically been the primary focus of such processes, as it produces a high quality distillate 

product, however, with the 45 cent tax subsidy currently available for ethanol production, it may 

be economically advantageous for fuel producers to convert syngas to ethanol instead of to diesel 

fuel. Production of cellulosic diesel is discussed in further detail in the following Section 

1.4.3.2. 

Conceptual designs and techno-economic models have been developed for ethanol 

production via mixed alcohol synthesis using catalytic processes. The proposed mixed alcohol 

process produces a mixture of ethanol along with higher normal alcohols (e.g., n-propanol, nbutanol, and n-pentanol). The by-product higher normal alcohols have value as commodity 

chemicals and fuel additives. Typically the mixed alcohol products described in literature are 

often high in methanol, but contain a wide distribution of several different alcohols. A concept 

proposed in literature is to completely recycle this methanol in order to increase the production 

of ethanol and higher alcohols which are generally more valuable. This concept was modeled by 

NREL for the thermochemical production of ethanol for the year 2012. Total mixed alcohol 

yield was 94.1 gallons per dry ton, in which 85% of the total alcohol product was ethanol. This 

was made possible through the addition of an almost complete recycle of methanol within the 

275 process.

In contrast to the catalytic processing of syngas to produce fuels, the fermentation process 

requires a special microorganism (Clostridium ljungdahlii) that will convert the syngas to 

ethanol.276 This combined syngas and fermentation process has the benefit of having a 

significantly faster processing time, on the order of minutes, as compared to the typical 

biochemical process on the order of days.277 

Stage 5 – Alcohol Separation 

The liquid rundown from the low-pressure separator is dehydrated in vapor-phase 

molecular sieves, producing the dehydrated mixed alcohol feed into a methanol/ethanol overhead 

stream and a mixed, higher molecular weight alcohol bottom stream. The overhead stream is 

further separated into a methanol stream and an ethanol stream. 

Heat & Power 

A carefully integrated conventional steam cycle produces process heat and electricity 

(excess electricity is exported). Pre-heaters, steam generators, and super-heaters generate steam 

that drives turbines on compressors and electrical generators. The heat balance around a 

thermochemical unit or thermochemical/biochemical combined unit must be carefully designed 

and tuned in order to avoid unnecessary heat losses.278 

95
 
 

Pyrolysis 

Pyrolysis oils, or bio-oils, are produced by condensing the decomposed biomass instead 

of introducing a gasifying agent.279 The decomposition occurs at lower temperatures than 

gasification processes, and produces liquid oil instead of a synthesis gas. The reaction can occur 

both with or without the use of catalysts. The oil produced varies in oxygen content or viscosity 

according to the feedstock used. The oil must have particulates and ash removed in filtration to 

create a homogenous product and is further upgraded to hydrocarbon fuels via hydrotreating and 

hydrocracking processing, which reduces its total oxygen content. Some believe that pyrolysis 

could have a significant economic advantage over other cellulosic ethanol approaches since very 

little has been done in terms of optimizing the process, and as such, there are still many 

possibilities yet to be explored.280 

1.4.3.2 Cellulosic Diesel 

Technology 

Another example of a thermochemical process is a cellulosic diesel fuel technology 

which is also termed biomass-to-liquids (BTL). The BTL process produces a syngas from 

biomass and then the syngas is fed to a Fischer-Tropsch (FT) reactor to primarily produce diesel 

fuel. 

The BTL method removes contaminants from the gasification stream prior to the 

reactions that form the liquid compounds. The resulting liquid fuel is essentially contaminantfree and is very similar to petroleum-based diesel fuel – in fact, its cetane number is higher than 

petroleum-based diesel fuel making it somewhat better in quality. Thus it can be easily blended 

with or used interchangeably with petroleum-based diesel fuel. 

BTL plants, like thermochemical ethanol plants, are capital intensive plants with many 

subunits associated with them. The first couple of steps of BTL plants, including biomass 

processing and gasification, are similar to the thermochemical cellulosic ethanol plants described 

above. However, once the syngas is produced, it is then cooled producing high pressure steam, 

and is scrubbed to remove particulate matter. Impurities such as mercury, arsenic and trace 

metals are removed by a sulfur impregnated carbon reactor. The syngas is further treated in 

either a Selexol or Rectisol unit to remove hydrogen sulfide and concentrated carbon dioxide 

(CO2). The CO2 can be captured and sold to a bottling company, used for enhanced the oil 

recovery from oil wells, or even sequestered in the ground for additional life cycle benefits. The 

syngas is sent to a water shift reactor to which causes a shift to more hydrogen and less carbon 

monoxide, which is necessary to establish an optimal mix of hydrogen and carbon for the 

downstream Fischer-Tropsch (FT) reactor. 

The cleaned and water-shifted syngas is sent to the FT reactor where the carbon 

monoxide and hydrogen are reacted over a FT catalyst. The FT catalyst is either iron-based or 

cobalt-based. The cobalt catalyst is more expensive, although it does not require a recycle, while 

the less expensive iron catalyst does require a recycle. The FT reactor creates a syncrude, which 

is variety of hydrocarbons that boil over a wide distillation range (a mix of heavy and light 

96
 
 

 

 

hydrocarbons). The syncrude from the FT reactor is sent to a distillation column where it is 

separated into various components based on their vapor pressure, mainly liquid petroleum gas 

(LPG), naphtha, distillate and wax fractions. The heavier compounds are hydrocracked to 

maximize the production of diesel fuel. The distillate boiling compounds have high cetane and 

thus are of high quality for blending into diesel fuel. Conversely, the naphtha material is very 

low in octane thus, it would either have to be upgraded, or blended down with high octane 

blendstocks (i.e., ethanol), or be upgraded to a higher octane blendstock to have much value for 

use in gasoline. The naphtha could also be sold as feedstock for the petrochemical market for 

manufacturing chemical products such as ethylene and benzene. 

The unreacted carbon monoxide and hydrogen and any gaseous hydrocarbon material are 

burned to produce electricity in a turbine. The waste heat from the gas turbine along with the 

steam created to cool the syn-gas, may be sent to steam turbines to produce additional electricity. 

Most of the electricity would be used within the BTL plant, however, some could be sold to raise 

additional revenues, particularly in the summer when electricity demand and prices are high. 

Industry Characterization 

No commercial BTL plants currently exist in the U.S., however, there are several BTL 

pilot plants. Choren is currently building a 1 million ton per year commercial Plant in Freiberg/ 

Saxony Germany that is expected to start up in 2011 or 2012. Initially, the plant will use 

biomass from nearby forests, the wood-processing industry and straw from farmland. 

Although coal-to-liquids (CTL) plants use coal as a feedstock, the process is essentially 

the same, therefore, CTL pilot and full scale plants help to demonstrate the BTL plant 

technology. Examples of CTL pilot projects include a 10-15 barrel per day (BPD) operation in 

Colorado (Rentech) and a 30 BPD plant in New Jersey (Headwaters Inc.). Internationally, 

commercial sized CTL plants are currently in operation in South Africa (Sasol) and have been in 

operation for a number of decades. These plants produce approximately 2.4 billion gallons per 

year (or 160,000 barrels per day) of fuel products. These liquid fuel products can include 

finished Fischer-Tropsch diesel, Fischer-Tropsch naphtha (a gasoline blendstock), methanol, and 

dimethyl ether, among others. Worldwide, additional CTL plants are being considered or 

constructed in China, Indonesia, India, Australia, and Malaysia. 

An inventory of current domestic CTL plants under consideration (including those 

without CCS, with CCS, and/or biomass co-feed) involves fifteen projects ranging in size from 

smaller projects (1,800 BPD) to large commercial plants up to 80,000 BPD. Most plants being 

considered are in the conceptual stage or are in the project feasibility stage.V Two plants are 

currently in the design phase (a 13,000 BPD and a 5,000 BPD plant) while one plant is in the 

construction phase (a 1,800 BPD plant).W Based on discussions with plant developers, three of 

the plant sites under consideration are currently assessing the use of both biomass co-firing and 

V DOE (2007), “Clean Coal Today: A Newsletter about Innovative Technologies for Coal Utilization,” Office of 

Fossil Energy, U.S. Department of Energy, DOE/FE-0509, Issue No. 72, Summer 2007, Table 1, p. 6. 

W The plants currently listed under design status are located near Medicine Bow, WY (DKRW Advanced Fuels, 

13,000 BPD) and near Gilberton, PA (WMPI, 5,000 BPD). The current plant under construction is in East Dubuque, 

IL (Rentech, 1,800 BPD). 

97
 
 

 

carbon capture to reduce GHG emissions. The plant furthest in developing coal and biomass to 

liquids (CBTL) with carbon capture (with CO2 intended for reuse in enhanced oil recovery 

applications) would be located in Wellsville, OH (a 50,000 BPD plant, Baard Energy). 

1.4.3.3 Developing Technologies 

The following sections describe specific companies and their cellulosic biofuel 

technologies which the companies have developed or are developing. This summary is not 

meant to be an unabridged list of cellulosic biofuel technologies, but rather a description of some 

of the more prominent or interesting cellulosic biofuel technologies. These technologies are 

variants of the biochemical or thermochemical platforms described above in Section 1.4.3.1.1 

and 1.4.3.1.2. The process technology summaries provided below are those stated by the 

respective companies. EPA has not confirmed the statements made concerning these 

technologies, nor have we confirmed the process conditions and the process flow steps necessary 

for any of these companies. As some of these technologies have slightly different process 

designs from the general descriptions found in Section 1.4.3.1 and Section 1.4.3.2 and may 

warrant additional consideration in the final rule, we found it important to discuss their 

differences below. 

Amyris Biotechnologies 

A new second generation process from Amyris Biotechnologies has a fermentation 

process that uses custom designed yeast cells to make renewable fuels that are substitutes for 

petroleum gasoline and petroleum diesel fuel. The technology is modular in design and can be 

collocated with existing ethanol plants. 

Amyris’s yeast cells are the key drivers of their conversion process. The process uses the 

same feedstocks that are currently used to make corn ethanol, which could be sugar cane or corn. 

At this time, no public information is available to derive production cost estimates for the 

Amyris process. Amyris has a 100 gallon per week pilot plant operating in Emeryville, CA, and 

is constructing a commercial demonstration plant in Brazil in 2010 to showcase their technology. 

The produced diesel fuel and is compatible with the existing petroleum distribution 

system and provides better storage and cold flow properties than biodiesel. 

Bell Bio-Energy 

A biochemical biofuel technology has been developed which uses genetically engineered 

bacteria to convert cellulosic feedstocks to synthetic hydrocarbon fuels. Depending on the types 

of bacteria used, this process can produce specific hydrocarbon types which can either be 

methane or other light hydrocarbons, gasoline, diesel or jet fuel type hydrocarbon compounds. 

For example, if a bacterium is chosen to produce gasoline, the bacteria may only produce octane, 

the eight carbon hydrocarbon molecule that boils within the distillation temperature range of 

gasoline. 

98
 
After the inventors of this process completed their development work, they discussed 

their technology with the Department of Defense which became interested in this technology for 

providing fuels to their land and air based vehicles. The military agreed to partially fund the 

establishment of pilot plants at different military bases. The bases are: Fort Benning and Fort 

Stewart in Georgia, For Bragg in North Carolina, Fort AP Hill in Virginia, Fort Drum in New 

York and Fort Lewis in Washington, and at a facility in San Pedro, California. The first of these 

pilot plants began operating at Fort Stewart, GA in late 2008 and the total expected production 

capacity for these pilot plants is 0.04 million gallons per year. The intent is to next build a large 

commercial demonstration plant of at least 150 million gallons per year with a startup date in 

2011. 

The technology works by first grinding the cellulosic feedstock into a smaller size and 

then immersing the ground cellulose with bacteria into water. The bacteria begin to digest the 

cellulose after only several hours, but require 30 days to fully digest the cellulose. The produced 

fuel is constantly removed from the reaction vessel, and some organic material is also produced 

which can be marketed as potting soil. The process produces over 84 gallons of renewable 

product per ton of feedstock and the simplicity of the process results in low capital costs per 

volume produced. The process is believed to be cost competitive with petroleum fuels when 

crude oil is priced at or above $30 per barrel assuming that the cellulosic feedstocks cost $40 per 

dry ton. 

BlueFire Ethanol 

BlueFire Ethanol has a commercial acid hydrolysis technology process that converts 

cellulosic materials into ethanol. The technology can make ethanol from urban trash, rice and 

wheat straws, wood waste and other agricultural residues. Acid hydrolysis is the main reaction 

mechanism to convert cellulosic and hemicellulosic material into simple sugars such as hexose 

and pentose or "C6 and C5" sugars. Fermentation of these sugars with microbes converts these 

sugars into ethanol. This process for converting cellulosic and hemicellulosic material into 

ethanol via acid hydrolysis and fermentation has been around for many decades; though it has 

not been economically competitive as the cost was not competitive with transport fuel made from 

petroleum. BlueFire’s process is claimed to offer several improvements to existing acid 

hydrolysis technology, giving higher ethanol yields and lower production costs. 

Bluefire uses a proprietary concentrated acid hydrolysis system and several other process 

improvements to make ethanol production more economically attractive than older acid 

hydrolysis methods. Some of Bluefire’s stated improvements include a more efficient acid 

recovery system; higher sugar purities and concentrations; use of more efficient microbes to 

ferment C6 and C5 sugars into ethanol; the processes ability to use biomass feedstock’s 

containing silica. The Bluefire process consists of the following main components; feedstock 

preparation; decrystallization/hydrolysis reaction; filtration of solids and liquids; separation of 

the acid and sugars; fermentation of the sugars and product separation. For product separation, 

ethanol effluent is separated using distillation and then dehydrated with molecular sieve 

technology. 

99
 
Bluefire has successfully operated a pilot plant for five years near their headquarters in 

Southern California. BlueFire is in the process of building its first commercial facility which 

will be located in Lancaster California. The plant could start up as early as 2010 and will 

produce up to 3.2 million gallons of cellulosic ethanol per year, using feedstock derived from 

cellulosic feedstocks from municipal solid waste (MSW) Blue Fire is planning to start up 

another cellulosic ethanol plant which they call their Mecca plant also using MSW as feedstock, 

and which will produce about 17 million gallons per year. No start up date has been announced 

for their Mecca plant. 

Cello-Energy 

The Cello-Energy process is a catalytic depolymerization technology. At moderate 

pressure and temperature, the Cello-Energy process catalytically removes the oxygen and 

minerals from the hydrocarbons that comprise cellulose. This results in a mixture of short chain 

(3, 6 and 9 carbon) hydrocarbon compounds. These short chain hydrocarbon compounds are 

polymerized to form compounds that boil in the diesel boiling range, though the process can also 

be adjusted to produce gasoline or jet fuel. The resulting diesel fuel meets the ASTM standards, 

is in the range of 50 to 55 cetane and typically contains 3 ppm of sulfur. The resulting diesel fuel 

has been tested in Caterpiller engines to demonstrate the viability of the fuel. 

The Cello-Energy process is reported to convert 94% of the hydrocarbon material to 

diesel fuel, although a very small amount of heavier hydrocarbons is also produced. The Cello 

Energy Process could be totally self-sufficient by routing 12% of the product to run generators to 

produce the electricity that it needs. The only energy input is electricity - no natural gas nor 

water is used in the process.. The Cello process is on the order of 82 % efficient at converting 

the feedstock energy content into the energy content of the product, which is very high compared 

to most of today's biochemical and thermochemical processes which are on the order of 50 % 

efficient, or less. 

Because of the simplicity of the process, the capital costs are very low. A 50 million 

gallon per year plant only incurs a total cost of $45 million. This is typical of the capital costs 

incurred when refiners expand their refineries, a very low cost for a grassroots plant. Because of 

its high efficiency in converting feedstocks into liquid fuel, the production and operating costs 

are estimated to be very low. By using some waste feedstocks today, production costs are 

reported to be less than $0.50 per gallon. However, even with feedstock costs in the $70 to $80 

per ton range, which is the cost we used in our cost analysis, total costs would remain less than 

$1.00 per gallon of diesel fuel. 

Cello-Energy was founded 16 years ago and after the chemistry was worked out, they 

built their first pilot plant in 1998. They next converted their pilot plant in 2004 to a larger 

continuously-operating pilot plant that produced 4 million gallons per year of diesel fuel. In 

December 2008, Cello started up a 20 million gallon per year commercial demonstration plant. 

Cello energy already has chosen locations to construct and start up three 50 million gallons per 

year plants by the end of 2010. This includes a facility in conjunction with the State of Georgia 

Energy Innovation Center, and two additional plants in Alabama. Cello is already making plans 

to construct and start-up ten more plants the year after. Cello explained that they will use 

100
 
 

prefabrication techniques so that these plants can readily be constructed, shipped and installed 

anywhere in the U.S. 

Choren 

Choren has a technology called Carbo-V, which is a Fischer-Tropsch process that can be 

used to make diesel fuel. The process can process a wide variety biomass and recycled material 

materials as feedstocks. The process converts agriculture biomass, forestry biomass, biogenic 

waste and recycling substances into a synthesis gas which can be further converted to a diesel 

fuel using a Fischer-Tropsch reactor. The Carbo-V process can also be configured without the 

Fischer-Tropsch hydrocracking technology, so as to produce electricity, heat and power, 

methanol, and other chemical feedstocks. 

The principal aspect of the Carbo-V Process is a three-stage gasification process 

consisting of low temperature gasification, high temperature gasification and endothermic 

entrained bed gasification. In the first stage, biomass is partially oxidized with air or oxygen at 

temperatures between 400 and 500 °C. This breaks down the feedstock into a gas containing tar 

and solid carbon. In the second stage, the tar is oxidized at temperature higher than the ash’s 

melting point, converting the tar into a synthesis gas. In the third stage, solid carbon is 

mechanically pulverized and blown into the hot gasification stream. The fluidized carbon 

endothermicly reacts with the gasification stream and is converted into a synthesis gas. In the 

next Fischer-Tropsch stage of the process, the synthesis gas (CO and H2) reacts with the aid of a 

catalyst to form hydrocarbons. The resulting hydrocarbons produced from the three stages can 

then be sent to a hydrocracking process to primarily produce diesel fuel. 

Choren will be building building a commercial Plant in Freiberg/ Saxony Germany that is 

expected to be operational in 2011 or 2012. Initially, the plant will use biomass from nearby 

forests, the wood-processing industry and straw from farmland. 

Coskata 

The Coskata process is a gasification-based technology which produces ethanol from 

biomass and other forms of carbon through a biofermentation route. A wide variety of 

feedstocks can be used, municipal waste, agriculture waste and other carbonaceous containing 

material. Since this process uses combustion and biofermentation, it is not easily classifiable as 

either a biochemical or thermochemical production method. This process requires that the 

biomass or carboneous material be processed to a small particle size and then it is injected into a 

gasifier. 

The gasifier combusts any dry carboneous feed stocks into syngas, comprised primarily 

of carbon monoxide and hydrogen. The syngas produced is fermented in a reactor by microorganisms, which convert the carbon monoxide and hydrogen directly into ethanol. The microorganisms are low cost and can process a wide range of carbon monoxide and hydrogen molar 

ratios in the syngas, providing feedstock processing flexibility. No other enzymes are required 

by this process for producing ethanol, providing significant cost savings over current cellulosic 

and corn based fermentation production methods. The Coskata process is conducted at low 

101
 
 

pressures, which offers savings on capital and energy costs. Additional energy savings can be 

realized by employing membrane technology to separate ethanol from the reactor decant liquid. 

This technology uses gravity and filtration to recover ethanol, resulting in significant savings on 

distillation capital and energy costs used in cellulosic and corn based production methods. 

Initial ethanol production cost estimates are lower than the biochemical and thermochemical 

cellulosic technologies described in Section 1.4.3.1.1 and 1.4.3.1.2. 

For woody biomass, Coskata estimates that each ton of this feedstock would generate 

about 100 gallons of ethanol and small amounts of ash which would be burned to supply energy 

needs for the process. Corn stover is expected to yield similar ethanol yields as woody biomass 

feed stocks, though details about yields from the various feed supply stocks are not yet public. 

Coskata has a bench scale pilot plant in Warrenville, IL, and projects that its larger 

40,000 gallon per year pilot plant will be operational later on in 2009. Coskata is targeting to 

design and build a 50 million gallons per year commercial demonstration plant will be 

operational in 2011 

Dynamotive Energy Systems 

Dynamotive Energy Systems Corporation has announced a pyrolysis technology that uses 

medium temperatures and oxygen free reactions to convert dry waste biomass and energy crops 

into fuels that can be used in power/heat generation and transportation vehicles. Additionally, 

the process can make feedstock’s that can be used to produce chemicals. The process is flexible 

on the types of biomass feedstock’s that can be processed. The fuel produced from the 

Dynamotive process is called “BioOil” and contains up to 25% water, though the water is 

intimately mixed and does not easily separate into another phase with time. Since the bio oil 

contains significant amounts of water, it is not directly useable as fuel in conventional vehicles 

and would have to be converted via another catalytic conversion processing step. The additional 

catalytic step envisioned for this would combust the material into a synthesis gas which would 

then be converted into diesel fuel or bio-methanol via a catalytic reaction (the BTL process). 

The diesel fuel produced is expected to be compatible with existing petroleum diesel fuels. 

Three products are produced by the Dynamotive process, bio oil (60-75% by weight), 

char (15-20% wt.) and non-condensable gases (10-20% wt.). The char produced is similar to 

coke and can be used as fuel by other industries while the gases yielded from the process can be 

used to supply about 75% of the energy requirements of the pyrolysis process. The pyrolysis 

process operates at a reactor temperatures of about 400-500 degrees Celsius. 

The process has two small demonstration plants, one operating and another at the end of 

its construction phase. These plants are being run to produce bio oil for use in the power sector, 

though Dynamotive has not announced plans for building a facility to make transportation fuels. 

The operating demonstration plant is located in West Lorne Ontario, Canada. This plant started 

operation in early 2005 and operates with a capacity of 130 tons per day of waste sawdust. The 

other demonstration plant is being built with a stated capacity of 200 tons per day. This plant 

will be located in Guelph, Ontario, Canada and will process 66,000 dry tons of biomass a year. 

102
 
This process uses waste construction and demolition wood from the private sector and will use 

about 3,000 tons of recycled wood. 

POET 

POET has over twenty years of producing conventional ethanol in 23 plants in seven 

states with production capability of one billion gallons of ethanol annually. POET has expanded 

their production capability to include cellulosic ethanol technology. POET’s cellulosic 

technology will make ethanol from plant materials like corn stalks, switch grass, wood chips and 

refuse. In February 2007, POET was selected by DOE for an award totaling $80 million for 

federal funding for a commercial cellulosic ethanol plant, which will be located in Emmetsburg, 

Iowa. As such, POET will be one of the first to build a cellulosic plant on a commercial scale. 

POET’s commercial demonstration plant is projected to produce 25 million gallons per year and 

start up in 2011. It will make cellulosic ethanol from plant materials such as corn cobs and 

perhaps other cellulosic feedstocks. 

Range Fuels 

Range Fuels produces cellulosic ethanol via a two step thermochemical process, similar 

to that discussed above for the cellulosic ethanol process via the thermochemical pathway. Their 

technology converts biomass to syngas followed by catalytic conversion of the syngas to 

alcohols. Range claims that their technology produces more ethanol than other cellulosic 

technologies based on yields per energy input. This is a two step process which can use many 

forms of non food biomass, such as agriculture waste, wood, and corn stocks. Additionally, the 

technology can process feed stocks with variable water content. 

In the Range process, biomass feedstock are converted by heat, pressure and steam into 

syngas, which is then scrubbed and cleaned before entering into the second stage. The second 

stage uses catalyst to convert the syngas into mixed alcohols, which are then separated and 

purified into alcohol fuels using distillation equipment. Overall, the Range process is simple as 

no enzymes or living organisms are used for the main conversion reactions. 

Range has operated a pilot plant for over 7 years using over 20 different nonfood 

feedstocks. Range broke ground building its first commercial plant late in late 2008 and is 

expected to be operational in 2010. This plant will be located in Soperton, Georgia and is 

partially funded from proceeds of a DOE grant. The plant will use wood, grasses, and corn 

stover as feedstocks. Although the initial plant is designed to produce 10 million gallons of 

ethanol per year, the plant is expected to be expanded to produce up to 60 million gallons per 

year of ethanol. 

Virent Bioreforming 

Another new process unveiled by Virent called “Bioforming Process” functions similarly 

as the gasoline reforming process used in the refining industry. While refinery-based reforming 

raises natural gasoline’s octane value and produces organic chemicals, benzene, xylene and 

toluene as a byproduct, Bioforming reforms biomass-derived sugars into hydrocarbons for 

103
 
 

blending into gasoline and diesel fuel. The process however, operates at much lower 

temperatures and pressures than reforming used by the refining industry. The Bioforming 

process is being developed through a partnership with Shell, Cargill, Honda and the University 

of Wisconsin. Virent currently has 16 pilot plants in operation. At this stage, though, the data is 

limited. It appears that Bioforming is a promising technology, as production costs estimates are 

low in comparison to most other renewable and biomass production processes while the products 

are compatible with traditional petroleum stocks. 

Biomass feedstocks for the Bioforming process are sugar feeds, such a corn syrup, 

sucrose, glycerol, sorbitol, xylose, glucose, cellulose and hemi cellulose. These are primarily 

converted into gasoline and diesel fuel, though other hydrocarbons such as jet fuel, LPG, 

benzene, toluene, xylene, hydrogen, natural gas can also be produced. Water is also produced, as 

the reforming process removes oxygen from the sugar feeds. The resulting properties and energy 

content of gasoline and diesel produced though are physically comparable to those yielded from 

refining industry, probably allowing movement in existing petroleum distribution systems, 

saving on shipping costs. Additionally, variable operating costs are low because no distillation 

equipment is needed to separate the produced gasoline, diesel and other hydrocarbons, as these 

separate naturally from the aqueous solutions generated in the reforming process. The net 

energy costs are also low due to low operating pressures and temperatures. 

1.4.4 Biodiesel & Renewable Diesel Production

 Biodiesel 

Plant oils and animal fats consist primarily of triglycerides, a type of a molecule 

consisting of a group of three hydrocarbon chains (saturated or olefinic) linked to a three-carbon 

backbone via carboxylic acid esters (see Figure 1.4-8). Biodiesel is made by removing the 

chains from the triglyceride molecules and adding methanol to their ends to form methyl esters. 

Glycerin is formed as a by-product from the three-carbon backbones that remain. For relatively 

pure triglycerides, such as virgin plant oils, the primary reaction is catalyzed by an alkaline pH 

and takes place in a stirred vessel at mild temperature and pressure conditions. 

104
 
Figure 1.4-8. Overview of biodiesel conversion process 

+

transesterification

methyl esters

(biodiesel)

glycerin

triglyceride

+ 

transesterification 

methyl esters 

(biodiesel) 

glycerin 

triglyceride 

In the case of feedstocks containing more than a few percent free fatty acids (FFAs), such 

as rendered fats and waste greases, addition of base will result in the formation of soap, an 

undesirable process contaminate when present above trace levels. To avoid this, these 

feedstocks first undergo an acid pre-treatment step to esterify the FFAs before proceeding to the 

base-catalyzed triglyceride transesterification reaction. Feedstocks with small amounts of FFAs 

may be converted in a basic environment if the soaps can be removed from the fuel product. 

Once the chemical conversions are complete, the mixture is neutralized, washed, and coproducts and unreacted alcohol are recovered. At that point the biodiesel is subjected to quality 

control testing and then released for sale. Figure 1.4-9 shows a process flow diagram for a 

typical biodiesel production process that uses virgin plant oil as feedstock; processes using waste 

fats or greases would include a an acid esterification step upstream of the transesterification 

reactor shown here. Plants that also produce other oleochemicals often have distillation 

equipment at the end of the process capable of purifying the methyl esters to a high degree or 

separating them by molecular weight. These plants may use this equipment to produce a very 

high purity biodiesel product. We estimate that less than 10% of current biodiesel production is 

distilled. 281 

105
 
 

Trans

esterification

Reactor

Acid Acidulation

Separator

Acidulation

Biodiesel

Wash Tank

Separator

Figure 1.4-9. Schematic of typical biodiesel production from virgin plant oil 

-

Vegetable

Oils

Methanol

Catalyst (Base)

Glycerin Stripper

Column

Methanol Rectification

Column

Glycerin

Product

Methanol /

Water

Crude

Biodiesel

To Methanol

Storage

Glycerin

Methanol

Water

Water

Gray

Water

Biodiesel /

Methanol

Stripper

Biodiesel

Methanol / Water

Filter

Biodiesel

Filter Product

Transesterification 

Reactor 

Acid 

Vegetable

Oils 

Methanol 

Catalyst (Base) 

Acidulation 

Separator 

Acidulation 

Glycerin Stripper

Column 

Methanol Rectification 

Column 

Glycerin 

Product 

Methanol /

Water 

Biodiesel 

Wash Tank 

Crude 

Biodiesel 

To Methanol 

Storage 

Glycerin

Methanol 

Water 

Water 

Separator 

Gray

Water 

Biodiesel / 

Methanol 

Stripper 

Biodiesel 

Methanol / Water 

Filter 

Biodiesel 

Filter Product

Some differences exist between large and small plants that are worth mentioning given 

the very wide range of plant capacities existing in this industry. Larger plants (greater than 10 

million gallons per year) are more likely to employ continuous flow processes, which afford 

certain efficiencies of scale and steady-state operation. On the other hand, small plants (less than 

one million gallons per year) are most likely to produce fuel batch-by-batch, which may give 

them more flexibility to change feedstock types or slow output on short notice. Smaller plants 

are less likely to be able to afford an on-site laboratory or quality control specialist, which may 

cause them hardship as fuel quality standards tighten and/or are more stringently enforced. 

Third-party labs exist for this purpose, but they pose challenges such as significant per-test costs 

and multi-day turnaround times that require holding of product batches until results are received. 

The biodiesel production process is relatively simple and economical, and there is 

sufficient existing U.S. capacity to produce all the biodiesel required to comply with the 

biomass-based diesel standard in this rulemaking. With U.S. 2008 biodiesel production 

estimated to be 650 million gallons, most made as described above, the process is viewed as 

demonstrated and reliable. Thus, we do not expect large changes in the process technology used 

to make biodiesel going into the future. That said, it is worth noting some potential changes as 

existing plants strive to comply with changing fuel quality standards, or as new plants are 

occasionally built to take advantage of specific market niches. 

106
 
One such change may be an increase in distillation of biodiesel. EPA requires biodiesel 

to meet the ASTM D-6751 specification for B100 in order to be legally blended into diesel fuel 

for use in vehicles. Earlier this year, ASTM amended this specification to require a cold filter 

plugging test, which effectively mandates very low levels of FFAs, sterol glucosides, and 

partially-converted triglycerides in the finished biodiesel. There are a variety of process 

parameters a biodiesel producer can adjust to reduce the levels of these compounds in the 

finished fuel, but one very effective way to ensure a high purity product is through distillation. 

At this time it is unclear to what extent distillation will be relied upon for compliance with the 

amended biodiesel specification. An increase in distillation would increase per-gallon energy 

inputs to the process significantly, which will make the biodiesel more costly and result in higher 

GHG emissions. 

Another potential change is a shift to use of heterogeneous (i.e., solid phase) catalysts for 

transesterification rather than the sodium or potassium methylate liquids used in most plants 

now. This is expected to reduce the neutralizing/washing/separating steps required downstream 

of the reactor, potentially resulting in a higher purity product and decreasing process energy use 

to some extent. 

Some industry forecasts suggest animal fats and waste greases will make up an increasing 

share of biodiesel feedstocks due to their lower costs and lower upstream GHG impacts. 

Because most fats and greases contain significant levels of FFAs, this shift will cause more 

plants to use acid pre-treatment, increasing process complexity and per-gallon energy use. 

Renewable Diesel 

The renewable diesel production process converts vegetable oils and animal fats into 

diesel fuel using thermal depolymerization, which is similar to hydrotreating used in petroleum 

refining to remove sulfur. The process uses hydrogen and catalyst to remove oxygen from the 

triglyceride molecules in the feedstocks oils via a decarboxylation and hydro-oxygenation 

reaction, yielding some light petroleum products and water as byproducts. The reactions also 

saturate the olefin bonds in the feedstock oils, converting them to paraffins. All of these 

reactions consume significant amounts of hydrogen. The extent of these reactions depends on 

the process conditions, as some of the carbon backbone of the oils can be cracked to naphtha and 

lighter products with higher severity. For our analysis though, we assume no such cracking and 

predict high selectivity to diesel-range material with a small amount of propane and water as byproducts. Figure 1.4-10 shows a flow diagram of the primary steps of renewable diesel 

production. 

107
 
S, N, 

metal 

removal

Flash 

separator Hydrotreating 

reactor

S, N, 

metal 

removal

Figure 1.4-10. Process flow diagram of primary steps in renewable diesel production 

Water, light 

hydrocarbons 

Mixed grease 

feedstock

Hydrogen

Heat in

Heat out

Liquid fuel for 

blending or further 

S, N, separation

metal 

removal 

Mixed grease 

feedstock 

Hydrogen 

Heat in 

Flash 

separator 

Heat out 

Liquid fuel for 

blending or further 

separation 

Hydrotreating 

reactor 

Renewable diesel will be produced either at a stand-alone facility or within the 

boundaries of an existing petroleum refinery. For the stand-alone facility, feedstock is brought in 

and finished fuel is transported out to market. This type of facility may be co-located with a 

rendering facility to minimize feedstock transportation and storage costs. For production within 

the boundaries of a refinery, the feed material may either be processed in a segregated unit (new 

or revamped), or co-processed with petroleum in an existing unit. In any case, the feedstock will 

require pre-treatment in a unit that removes contaminates such as sulfur, nitrogen, and other 

compounds that may poison hydrotreating catalysts. 

Since December, 2007, ConocoPhilips has been producing a small amount (300-500 

bbl/day) of renewable diesel at their Borger, Texas, refinery from beef tallow generated by 

Tyson Foods, Inc. in Amarillo, Texas.282 In 2007, Dynamic Fuels, LLC., was formed by 

Syntroleum Corp. and Tyson Foods, Inc., to produce liquid renewable fuels. This fall Dynamic 

Fuels has announced ground-breaking for a 75 million gallon per year plant (5,000 bbl/day) in 

Geismar, Louisiana, that will use Tyson meat processing fats as feedstock to Syntroleum’s BioSynfining process. Start-up is scheduled for 2010, with the primary product being high-quality 

diesel fuel that will be fungible within the existing petroleum supply system. 283 This facility 

plans to utilize supplies of hydrogen available in the industrial park where it will be located, as 

well as rail and shipping infrastructure already in place nearby. 284 

Syntroleum Corp was founded in 1984 and holds a number of patents in gas-to-liquids 

and biomass-to-liquids conversion processes. One of these technologies they call Synfining, a 

process for upgrading Fischer-Tropsch paraffins to compounds with properties more favorable 

108
 
 

for diesel fuel. They have further adapted this process to use a variety of fats and oils as 

feedstocks, calling it Bio-Synfining. It is this process that will be used in the Geismar facility. 

Looking internationally, the Finnish company Neste Oil began operating a 3,200 bbl/day 

process in Finland in 2007 to convert vegetable oils into renewable diesel. This company has 

plans to construct similar facilities in Singapore and the Netherlands by 2010, and eventually 

plans to bring on-line plants that will convert biomass to liquid fuels using gasification.285 

Since thermochemical production of hydrocarbon fuels from fats and biomass is a 

relatively new endeavor to conduct on a commercial scale, we expect continued innovation and 

fine-tuning of the technology as these processes evolve from their roots in Fischer-Tropsch and 

petroleum hydrotreating processes. (This discussion ties in with cellulosic diesel in section 

1.4.3.2.) 

1.5 Biofuel Industry Characterization & Projected Growth 

In this section we will discuss the current state of the biofuel industry and how 

production might grow in the future under the proposed RFS2 program. The bulk of the 

discussion will focus on ethanol production, but we will also provide insight on biodiesel, 

renewable diesel, and the evolving cellulosic diesel industry. We will start by discussing current 

corn ethanol production and how the industry might continue to expand under the RFS2 program 

as well as employ more advanced processing technologies. From there we will discuss the 

availability of imported ethanol from Brazil and Caribbean Basin Initiative (CBI) countries to 

help meet the Advanced Biofuel Standard. Following this discussion, we will characterize the 

present state of the cellulosic biofuel industry and talk about the likelihood of near-term 

commercialization based on industry plans and technological breakthroughs aided by state and 

federal grants, tax incentives, and loan guarantee programs. And furthermore, why we believe 

the industry is on track for meeting the 2010 Cellulosic Biofuel Standard set by EISA. We will 

end the discussion by forecasting where potential cellulosic biofuel plants could be located in the 

U.S. based on feedstock availability. This information, along with projected corn ethanol plant 

locations and imported ethanol locations, will be used as an input into the distribution analysis 

(discussed later in Section 1.6) and the emissions and air quality modeling (discussed in Chapter 

3). Finally, we will conclude our industry characterization by discussing the present state of the 

biomass-based diesel industry and how we expect biodiesel production to grow in the future and 

renewable diesel production to emerge. For a more in-depth discussion of corn ethanol, 

imported ethanol, cellulosic ethanol/diesel, biodiesel, and renewable diesel processing 

technologies, refer to Section 1.4. 

1.5.1 Corn Ethanol 

The majority of domestic biofuel production currently comes from plants processing corn 

and other similarly-processed grains in the Midwest. However, there are a handful of plants 

located outside the Corn Belt and a few plants processing simple sugars from food or beverage 

waste. In this subsection, we will talk about the present state of the corn ethanol industry and 

how we expect things might change in the future under the proposed RFS2 program. At the end 

109
 
 

 

 

 

of this section (Section 1.5.1.5) we will summarize an earlier May 2008 corn ethanol industry 

assessment that was used to project future corn/starch ethanol plant locations for various impact 

analyses associated with this proposed rule. 

1.5.1.1 Historic/Current Production 

The United States is currently the largest ethanol producer in the world. In 2008, the U.S. 

produced almost 9 billion gallons of fuel ethanol for domestic consumption, the majority of 

which came from domestically-grown corn.286 Although the U.S. ethanol industry has been in 

existence since the 1970s, it has rapidly expanded over the past few years due to the phase-out of 

methyl tertiary butyl ether (MTBE)X, elevated crude oil prices, state mandates and tax 

incentives, the introduction of the Federal Volume Ethanol Excise Tax Credit (VEETC)Y, and 

the implementation of the existing RFS1 programZ. As shown in Figure 1.5-1, U.S. ethanol 

production has grown exponentially over the past decade. 

X For more information on how the phase-out of MTBE helped spur ethanol production/consumption, refer to 

Section 1.7.1.1. 

Y On October 22, 2004, President Bush signed into law H.R. 4520, the American Jobs Creation Act of 2004 (JOBS 

Bill), which created the Volumetric Ethanol Excise Tax Credit (VEETC). The $0.51/gal VEETC for ethanol blender 

replaced the former fuel excise tax exemption, blender’s credit, and pure ethanol fuel credit. However, the recentlyenacted Farm Bill has modified the alcohol credit so that corn ethanol gets a reduced credit of $0.45/gal. The 2008 

Farm Bill also gives cellulosic biofuel a credit of $1.01/gal. Both credits appear to be valid through the end of 2012. 

Z

 On May 1, 2007, EPA published a final rule (72 FR 23900) implementing the Renewable Fuel Standard (RFS) 

required by the Energy Policy Act of 2005. The RFS requires that 4.0 billion gallons of renewable fuel be blended 

into gasoline/diesel by 2006, growing to 7.5 billion gallons by 2012. 

110
 
 

 

 

 

1999 2000 2001 2002 2003 

2004 2005 2006 

2007 2008 

Figure 1.5-1. 

Historical Growth in U.S. Corn/Starch Ethanol Production287
 

1.4 

1.6 1.7 

2.0 

2.7 

3.3 

3.8 

4.6 

6.3 

8.9 

0 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

Corn/Starch Ethanol Production (Bgal) 

Year 

As of April 2009, there were 169 fuel ethanol plants operating in the U.S. with a 

combined estimated production capacity of 10.5 billion gallons per year.AA288289 This does not 

include a number of ethanol plants that are currently idled.BB The majority of today’s ethanol 

(over 91% by volume) is produced exclusively from corn. Another 11% comes from a blend of 

corn and/or similarly processed grains (milo, wheat, or barley) and less than half a percent is 

produced from cheese whey, waste beverages, and sugars/starches combined. A summary of 

U.S. ethanol production by feedstock is presented in Table 1.5-1. 

AA Our April 2009 corn/starch ethanol industry characterization was based on a variety of data sources including: 

Renewable Fuels Association (RFA) Ethanol Biorefinery Locations (updated March 31, 2009); Ethanol Producer 

Magazine (EPM) Current plant list (last modified on April 7, 2009), and ethanol producer websites. The baseline 

does not include ethanol plants whose primary business is industrial or food-grade ethanol production nor does it 

include plants that might be located in the Virgin Islands or U.S. territories. Where applicable, current ethanol plant 

production levels have been used in lieu of nameplate capacities to estimate plant production. The April 2009 

information presented in this section reflects our most recent knowledge of the corn/starch ethanol industry. 

However, for various NPRM impact analyses, an earlier May 2008 industry assessment was used. For more on this 

assessment, refer to Section 1.5.1.5.

BB In addition to idled plants, the assessment does not include idled production capacity at facilities that are currently 

operating at 50% or less than their nameplate capacity. 

111
 
 

 

 

 

 

Table 1.5-1. 

Current Corn/Starch Ethanol Production Capacity by Feedstock 

Plant Feedstock 

(Primary Listed First) 

Capacity 

MGY 

% of 

Capacity 

No. of 

Plants 

% of 

Plants 

Corna 9,605 91.2% 144 85.2% 

Corn, Milob 717 6.8% 14 8.3% 

Corn, Wheat 130 1.2% 1 0.6% 

Milo 3 0.0% 1 0.6% 

Wheat, Milo 50 0.5% 1 0.6% 

Cheese Whey 5 0.0% 1 0.6% 

Waste Beveragesc 19 0.2% 5 3.0% 

Waste Sugars & Starchesd 7 0.1% 2 1.2% 

Total 10,535 100% 169 100% 

a

Includes one facility processing seed corn, two facilities also operating pilot-level cellulosic 

ethanol plants, and four facilities with plans to build pilot-level cellulosic ethanol plants or 

incorporate biomass feedstocks in the future. 

b

Includes one facility processing a small amount of molasses in addition to corn and milo. 

c

Includes two facilities processing brewery waste. 

d

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

As shown in Table 1.5-1, of the 169 operating plants, 161 plants processing corn and/or 

other similarly processed grains. Of these facilities, 150 utilize dry-milling technologies and the 

remaining 11 plants rely on wet-milling processes. Dry mill ethanol plants grind the entire 

kernel and generally produce only one primary co-product: distillers grains with solubles (DGS). 

The co-product is sold wet (WDGS) or dried (DDGS) to the agricultural market as animal feed. 

However, there are a growing number of dry mill ethanol plants pursuing front-end corn 

fractionation or back-end corn oil extraction to produce fuel-grade corn oil for the biodiesel 

industry. There are also additional plants pursuing cold starch fermentation and other energysaving processing technologies. For more on the dry-milling and wet-milling processes as well 

as emerging advanced technologies, refer to Section 1.4.1. 

In contrast to traditional dry mill plants, wet mill facilities separate the kernel prior to 

processing into its component parts (germ, fiber, protein, and starch) and produce other coproducts (usually gluten feed, gluten meal, and food-grade corn oil) in addition to DGS. Wet 

mill plants are generally more costly to build but are larger in size on average. As such, 11.5% 

of the current grain ethanol production comes from the 11 previously-mentioned wet mill 

facilities listed in Table 1.5-2. 

112
 
 

 

 

Table 1.5-2. 

Existing Wet Mill Corn Ethanol Plants 

Ethanol Plant/Company Location 

Capacity 

MGY 

% of Tot 

Capacity 

Archer Daniels Midlanda 

Archer Daniels Midlanda 

Archer Daniels Midlanda 

Archer Daniels Midlanda 

Archer Daniels Midlanda 

Aventine Renewable Energy 

Cargill, Inc. 

Cargill, Inc. 

Grain Processing Corp 

Penford Products 

Tate & Lyle 

Cedar Rapids, IA 

Clinton, IA 

Columbus, NE 

Decatur, IL 

Marshall, MN 

Pekin, IL 

Eddyville, IA 

Blair, NE 

Muscatine, IA 

Cedar Rapids, IA 

Loudon, TN 

250 

190 

95 

290 

40 

100 

35 

85 

20 

45 

66 

2.4% 

1.8% 

0.9% 

2.8% 

0.4% 

0.9% 

0.3% 

0.8% 

0.2% 

0.4% 

0.6% 

Total 1,216 11.5% a

Estimated plant capacities. 

The remaining eight ethanol plants process cheese whey, waste beverages or 

sugars/starches and operate differently than their grain-based counterparts. These small 

production facilities do not require milling and operate a simpler enzymatic fermentation 

process. A summary of today’s average ethanol plant sizes is found in Table 1.5-3 below. 

Table 1.5-3. 

Average Corn/Starch Plant Sizes 

Processing 

Technology 

Capacity 

MGY 

% of 

Capacity 

No. of 

Plants 

% of 

Plants 

Avg. Size 

MGY 

Dry Millinga 

Wet Milling 

Othera 

9,289 

1,216 

30 

88.2% 

11.5% 

0.3% 

150 

11 

8 

88.8% 

6.5% 

4.7% 

61.9 

110.5 

3.8 

Total 10,535 100.0% 169 100.0% 62.3 a

Includes four facilities that plan on incorporating cellulosic feedstocks at their existing corn 

ethanol plants in the future. If plans come to fruition, these plants will need additional front end 

technology to supplement their existing dry mill processes. 

b

Facilities that do not process traditional grain-based crops and thus do not require milling. 

This category includes plants processing cheese whey, waste beverages or sugars & starches. 

Ethanol production is a relatively resource-intensive process that requires the use of 

water, electricity, and steam.CC Steam needed to heat the process is generally produced on-site 

or by other dedicated boilers. The ethanol industry relies primarily on natural gas. Of today’s 

CC For more on plant energy requirements, refer to Section 1.5.1.3. 

113
 
 

 

 

 

 

 

 

169 ethanol production facilities, 142 burn natural gasDD (exclusively), three burn a combination 

of natural gas and biomass, one recently started burning a combination of natural gas, landfill 

syngas and wood, and two burn a combination of natural gas and syrup from the process. In 

addition, 20 plants burn coal as their primary fuel and one burns a combination of coal and 

biomass. Our research suggests that 25 plants currently utilize cogeneration or combined heat 

and power (CHP) technology, although others may exist. CHP is a mechanism for improving 

plant energy efficiency by using a single fuel to generate both power and thermal energy. For 

more on this technology, refer to Section 1.4.1.3. A summary of the energy sources and CHP 

technology utilized by today’s ethanol plants is found in Table 1.5-4. 

Table 1.5-4. 

Current Corn/Starch Ethanol Production Capacity by Energy Source 

Plant Energy Source 

(Primary Listed First) 

Capacity 

MGY 

% of 

Capacity 

No. of 

Plants 

% of 

Plants 

CHP 

Tech. 

Coala 

Coal, Biomass 

Natural Gasb 

Natural Gas, Biomassc 

Natural Gas, Landfill Biogas, Wood 

Natural Gas, Syrup 

1,868 

50 

8,294 

113 

110 

101 

17.7% 

0.5% 

78.7% 

1.1% 

1.0% 

1.0% 

20 

1 

142 

3 

1 

2 

11.8% 

0.6% 

84.0% 

1.8% 

0.6% 

1.2% 

9 

0 

15 

1 

0 

0 

Total 10,535 100.0% 169 100.0% 25 a

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

and one facility that intends to transition to biomass in the future. 

b

Includes one facility that intends to switch to biomass, one facility that intends to burn thin stillage biogas, and two 

facilities that might switch to coal in the future. 

c

Includes one facility processing bran in addition to natural gas. 

Since the majority of ethanol is made from corn, it is no surprise that most of the plants 

are located in the Midwest near the Corn Belt. Of today’s 169 ethanol production facilities, 151 

are located in the 15 states comprising PADD 2. For a map of the Petroleum Administration for 

Defense Districts or PADDs, refer to Figure 1.5-2. 

DD Facilities were assumed to burn natural gas if the plant boiler fuel was unspecified or unavailable on the public 

domain. 

114
 
Figure 1.5-2. 

Petroleum Administration for Defense Districts 

As a region, PADD 2 accounts for 94% (or almost 10 billion gallons) of today’s 

estimated ethanol production capacity, as shown in Table 1.5-5. 

Table 1.5-5. 

Current Corn/Starch Ethanol Production Capacity by PADD 

PADD 

Capacity 

MGY 

% of 

Capacity 

No. of 

Plants 

% of 

Plants 

PADD 1 

PADD 2 

PADD 3 

PADD 4 

PADD 5 

150 

9,900 

194 

160 

131 

1.4% 

94.0% 

1.8% 

1.5% 

1.2% 

3 

151 

3 

7 

5 

1.8% 

89.3% 

1.8% 

4.1% 

3.0% 

Total 10,535 100.0% 169 100.0% 

Leading the Midwest in ethanol production are Iowa, Nebraska, Illinois, Nebraska, 

Minnesota, and South Dakota. Together, these five states’ 98 ethanol plants account for twothirds (or just over 7 billion gallons) of the nation’s ethanol production capacity. However, 

although the majority of ethanol production comes from PADD 2, there are a growing number of 

plants situated outside the traditional Corn Belt. Our April 2009 industry assessment indicates 

that Arizona, California, Colorado, Georgia, Idaho, Kentucky, Mississippi, New York, 

Oklahoma, Oregon, Texas and Wyoming all have one or more operational ethanol plants. Some 

of these facilities ship in feedstocks (namely corn) from the Midwest, others rely on locally 

grown/produced feedstocks, while others rely on a combination of the two. A summary of 

ethanol production capacity by state is presented in Table 1.5-6. 

115
 
Table 1.5-6. 

Current Corn/Starch Ethanol Production Capacity by State 

State 

Capacity 

MGY 

% of 

Capacity 

No. of 

Plants 

% of 

Plants 

Iowa 3,011 28.6% 37 21.9% 

Illinois 1,142 10.8% 11 6.5% 

Nebraska 1,091 10.4% 19 11.2% 

Minnesota 951 9.0% 18 10.7% 

South Dakota 836 7.9% 13 7.7% 

Indiana 714 6.8% 9 5.3% 

Wisconsin 529 5.0% 9 5.3% 

Kansas 439 4.2% 11 6.5% 

Ohio 320 3.0% 5 3.0% 

Missouri 261 2.5% 6 3.6% 

Michigan 215 2.0% 4 2.4% 

Tennessee 176 1.7% 2 1.2% 

North Dakota 175 1.7% 4 2.4% 

Colorado 146 1.4% 5 3.0% 

Texas 140 1.3% 2 1.2% 

Georgia 100 1.0% 2 1.2% 

Mississippi 54 0.5% 1 0.6% 

New York 50 0.5% 1 0.6% 

Arizona 50 0.5% 1 0.6% 

California 41 0.4% 3 1.8% 

Kentucky 40 0.4% 2 1.2% 

Oregon 40 0.4% 1 0.6% 

Wyoming 9 0.1% 1 0.6% 

Idaho 5 0.0% 1 0.6% 

Oklahoma 2 0.0% 1 0.6% 

Total 10,535 100.0% 169 100.0% 

The U.S. ethanol industry is currently comprised of a mixture of company-owned plants 

and locally-owned farmer cooperatives (co-ops). The majority of today’s ethanol production 

facilities are company-owned and, on average, these plants are larger in size than farmer-owned 

co-ops. Accordingly, company-owned plants account for almost 80% of today’s ethanol 

production capacity.290 Furthermore, 30% of the total domestic product comes from 38 plants 

owned by just three different companies – POET Biorefining, Archer Daniels Midland (ADM), 

and Valero Renewables (refer to Figure 1.5-3 below). Valero recently entered into the renewable 

fuels business by acquiring five corn ethanol plants and one construction site from bankrupted 

VeraSun Energy Corporation. Valero has since purchased two more VeraSun plants, but at the 

time of our April 2009 assessment these plants had not been brought back online yet. 

116
 
 

Figure 1.5-3. 

Current Corn/Starch Ethanol Production Capacity by Company 

Other, 5,549 

POET Biorefining, 1,535 

, 

Aventine Renewable 

Energy, 207
 Archer Daniels Midland, 

1,100 

BioFuel Energy Corp., 230
 Valero Renewables, 560
 

Glacial Lakes Energy, 

LLC, 250 Hawkeye Renewables, 

LLC, 460
 

Green Plains Renewable
 

The Andersons, 315 Energy, Inc., 330
 

1.5.1.2 Forecasted Production Under RFS2 

As highlighted above, 10.5 billion gallons of corn/starch ethanol plant capacity was 

online as of April 2009. So even if no additional capacity was added, U.S. ethanol production 

would grow from 2008 to 2009, provided facilities continue to operate at or above today’s 

production levels. And despite today’s temporary unfavorable market conditions (i.e., low 

ethanol market values), we expect the ethanol industry will continue to expand in the future 

under RFS2. Although there is not a set corn ethanol standard, EISA allows for 15 billion 

gallons of the 36-billion gallon renewable fuel standard to be met by conventional biofuels. And 

we expect that corn and other sugar or starch-based ethanol will fulfill this requirement. 

Furthermore, we project that all new corn/starch ethanol plant capacity brought online under 

RFS2 would either meet the conventional biofuel GHG threshold requirementEE or meet the 

grandfathering requirement (for more information, refer to Section 1.5.1.4). 

In addition to the 169 corn/starch ethanol plants that are currently online today, 36 plants 

are presently idled. Some of these constructed facilities (namely smaller ethanol plants) have 

been idled for quite some time, whereas other plants have just recently been put into “hot idle” 

mode. A number of ethanol producers (e.g., VeraSun) are idling operations, putting projects on 

hold, selling off plants, and even filing for Chapter 11 bankruptcy. In addition, we are aware of 

EE The lifecycle assessment values which assume a 2% discount rate over a 100-year timeframe. 

117
 
 

 

 

 

 

 

 

 

 

two facilities that are currently operating at 50% or less than their nameplate capacity. As crude 

oil and gasoline prices rise again in the future, corn ethanol production will become more viable 

again and we expect that these plants will resume operations. At the time of our April 2009 

ethanol industry assessment, there were also 19 new ethanol plants under construction in the U.S, 

and two plant expansion projects underway.FF While many of these projects are also on hold due 

to current economic conditions, we expect these facilities will eventually come online under the 

RFS2 program. A summary of the projected industry growth is found in Table 1.5-7. 

Table 1.5-7. 

Potential Corn/Starch Ethanol Industry Expansion Under RFS2 

Growth in Ethanol Production 

Plants 

Currently 

Online 

Idled 

Plants / 

Capacitya 

New 

Construction 

Projects 

Expansion 

Projects Total 

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

Total No. of Plants 169 36 19 2 226 a

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

capacity. 

While theoretically it only takes 12-18 months to build an ethanol plantGG, the rate at 

which new plant capacity comes online will be dictated by market conditions, which will in part 

be influenced by the RFS2 requirements. As mentioned above, today’s proposed program will 

create a growing demand for corn ethanol reaching 15 billion gallons by 2015. However, it is 

possible that market conditions could drive demand even higher. Whether the nation will 

overcomply with the corn ethanol standard is uncertain and will be determined by feedstock 

availability/pricing, crude oil pricing, and the relative ethanol/gasoline price relationship. To 

measure the impacts of the proposed RFS2 program, we assumed that corn ethanol production 

would not exceed 15 billion gallons. We also assumed that all growth would come from new 

plants or plant expansion projects (in addition to idled plants being brought back online).HH 

However, it is possible that some of the required growth could come from minor process 

improvements (e.g., debottlenecking) at existing facilities. 

Once all the aforementioned projects are complete, we project that there will be 226 

corn/starch ethanol plants operating in the U.S. with a combined production capacity of around 

15 billion gallons per year. Much like today’s ethanol industry, the overwhelming majority of 

new plant capacity (93% by volume) is expected to come from corn-fed plants. Another 7% is 

FF Based on Renewable Fuels Association (RFA), Ethanol Biorefinery Locations – Under Construction/Expansions 

(updated April 4, 2008); Ethanol Producer Magazine (EPM), Under Construction plant list (last modified on April 

14, 2008), ethanol producer websites, and follow-up correspondence with ethanol producers. It is worth noting that 

for our industry assessment, “under construction” implies that more than just a ground breaking ceremony has taken 

place. To determine whether a facility “commenced construction” by December 19, 2007 and thus will be 

grandfathered under the proposed RFS2, we will rely on the Expanded registration Process (refer to Section III.C of 

the Preamble). 

GG For more information on our estimated plant build rates, refer to Section 1.2.5. HH For our NPRM impact analysis, we relied on an earlier May 2008 industry assessment. For more information, 

refer to Section 1.5.1.5. 

118
 
 

 

 

 

 

 

forecasted to come from plants processing a blend of corn and/or other grains, and a very small 

increase is projected to come from idled cheese whey and waste beverage plants coming back 

online. A summary of the forecasted ethanol production by feedstock under the RFS2 program 

is found in Table 1.5-8. 

Table 1.5-8. 

Projected RFS2 Ethanol Production Capacity by Feedstock 

Plant Feedstock 

(Primary Listed First) 

Additional Production Total RFS2 Estimate 

Capacity 

MGY 

No. of 

Plants 

Capacity 

MGY 

No. of 

Plants 

Corna 4,197 49 13,802 193 

Corn, Milob 185 3 902 17 

Corn, Wheat 8 1 138 2 

Corn, Wheat, Milo 110 2 110 2 

Milo 0 0 3 1 

Wheat, Milo 0 0 50 1 

Cheese Whey 3 1 8 2 

Waste Beveragesc 4 1 23 6 

Waste Sugars & Starchesd 0 0 7 2 

Total 4,507 57 15,042 226 a

Includes one facility processing seed corn, another facility processing small amounts of whey, 

two facilities also operating pilot-level cellulosic ethanol plants, and four facilities with plans to 

build pilot-level cellulosic ethanol plants or incorporate biomass feedstocks in the future. 

bIncludes one facility processing a small amount of molasses in addition to corn and milo. 

c

Includes two facilities processing brewery waste. 

d

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

Based on current industry plans, the majority of additional corn/grain ethanol production 

capacity (almost 84% by volume) is predicted to come from new or expanded plants burning 

natural gas.II Additionally, we are forecasting one new plant and a reopening of another plant 

relying on manure biogas. We are also predicting expansions at three coal-fired plants.JJ Of the 

55 new ethanol plants, our research indicates that five would utilize cogeneration, bringing the 

total number of CHP facilities to 30. A summary of the forecasted near-term ethanol plant 

energy sources is found in Table 1.5-9. 

II Facilities were assumed to burn natural gas if the plant boiler fuel was unspecified or unavailable on the public 

domain. 

JJ Two of the three coal-fired plant expansions appear as new plants in Table 1.5-8. This is because two of the 

expansion projects consist of adding dry milling plant capacity to an existing wet mill plant. However, our 

interpretation is that these facilities will rely on the same (potentially expanded) coal-fired boilers for process steam. 

Since all the aforementioned coal-fired ethanol production facilities appear to have commenced construction prior to 

December 19, 2007, we project that the ethanol produced at these facilities will be grandfathered under the proposed 

RFS2 rule. For more on our grandfathered volume estimate, refer to Section 1.5.1.4. 

119
 
 

 

 

 

 

Table 1.5-9. 

Projected Near-Term Corn/Starch Ethanol Production Capacity by Energy Source 

Plant Energy Source 

(Primary Listed First) 

Additional Production Total RFS2 Estimate 

Capacity 

MGY 

No. of 

Plants 

Capacity 

MGY 

No. of 

Plants 

CHP 

Tech. 

Coala 610 2 2,478 22 11 

Coal, Biomass 0 0 50 1 0 

Manure Biogas 134 2 134 2 0 

Natural Gasb 3,763 53 12,056 195 18 

Natural Gas, Biomassc 0 0 113 3 1 

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

Natural Gas, Syrup 0 0 101 2 0 

Total 4,507 57 15,042 226 30 a

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

one facility that intends to transition to biomass in the future. 

b

Includes one facility that intends to switch to biomass , one facility that intends to burn thin stillage biogas, and six 

facilities that might switch to coal in the future. 

c

Includes one facility processing bran in addition to natural gas. 

The information in Table 1.5-9 is based on short-term industry production plans at the 

time of our April 2009 plant assessment. However, we anticipate even more growth in advanced 

ethanol production technologies in the future under the proposed RFS2 program. We project that 

fuel prices will drive a large number of corn ethanol plants to transition from conventional boiler 

fuels to advanced biomass-based feedstocks. We also believe that fossil fuel/electricity prices 

will drive a number of ethanol producers to pursue CHP technology. For more on our projected 

2022 utilization of these technologies under the RFS2 program, refer to Section 1.5.1.3. 

Under the proposed RFS2 program, the majority of new ethanol production is expected to 

originate from PADD 2, close to where the corn is grown. However, there are a growing number 

of “destination” ethanol plants being built outside the Midwest in response to state production 

subsidies, E10/E85 retail pump incentives, and state mandates. A summary of the forecasted 

ethanol production by PADD under the RFS2 program can be found in Table 1.5-10. 

120
 
Table 1.5-10. 

Projected RFS2 Corn/Starch Ethanol Production Capacity by PADD 

PADD 

New Plants/Exp. Total 2022 Est. 

Capacity 

MGY 

No. of 

Plants 

Capacity 

MGY 

No. of 

Plants 

PADD 1 

PADD 2 

PADD 3 

PADD 4 

PADD 5 

214 

5,002 

215 

70 

328 

2 

47 

2 

2 

5 

264 

13,620 

385 

230 

499 

4 

187 

5 

9 

11 

Total 5,829 58 14,998 216 

Based on current production plans, we project that Iowa, Nebraska, and Illinois will 

continue to dominate ethanol production with a collective production capacity of about 7.4 

billion gallons. Indiana and Minnesota are projected to be the fourth and fifth largest producers 

displacing South Dakota (today’s fifth largest producer according to Table 1.5-6). Ethanol 

production is expected to grow in other Midwest states and there are also a growing number of 

plants that are being built outside the Corn Belt. After the proposed RFS2 program is fully 

implemented, we estimate that more than half of the United States will have corn/starch ethanol 

production as shown below in Table 1.5-11. 

121
 
Table 1.5-11. 

Projected RFS2 Corn/Starch Ethanol Production Capacity by State 

State 

Additional Production Total RFS2 Estimate 

Capacity 

MGY 

No. of 

Plants 

Capacity 

MGY 

No. of 

Plants 

Iowa 833 8 3,844 45 

Nebraska 827 9 1,918 28 

Illinois 538 7 1,680 18 

Indiana 506 5 1,220 14 

Minnesota 188 4 1,139 22 

South Dakota 172 2 1,008 15 

Wisconsin 27 1 556 10 

Ohio 224 3 544 8 

Kansas 80 2 519 13 

Texas 210 2 350 4 

North Dakota 171 2 346 6 

Michigan 50 1 265 5 

Missouri 0 0 261 6 

Tennessee 60 0 236 2 

California 195 4 236 7 

New York 114 1 164 2 

Oregon 113 1 153 2 

Colorado 0 0 146 5 

Georgia 0 0 100 2 

North Carolina 60 1 60 1 

Idaho 50 1 55 2 

Washington 55 1 55 1 

Mississippi 0 0 54 1 

Arizona 0 0 50 1 

Kentucky 0 0 40 2 

New Mexico 30 1 30 1 

Wyoming 0 0 9 1 

Florida 4 1 4 1 

Oklahoma 0 0 2 1 

Total 4,507 57 15,042 226 

The majority of future ethanol plants are expected to be company-owned. Of the 57 

plants we are expecting to be built or brought back online under the proposed RFS2 program, 51 

are expected to be owned by corporations. The leading ethanol producers will likely continue to 

be Archer Daniels Midland and POET Biorefining, each with over 1.5 billion gallons of annual 

corn ethanol production capacity. Valero Renewables, who recently purchased eight ethanol 

plants (including a development site) from VeraSun Energy is expected to be the third largest 

122
 
 

Other, 7,816 

White Energy, 250 

Glacial Lakes Energy, 

LLC, 250 

Green Plains Renewable 

Energy, Inc., 330 

The Andersons, 315 

Abengoa Bioenergy Corp., 

369 

Aventine Renewable 

Energy, 427 

Hawkeye Renewables, 

LLC, 460 

Archer Daniels Midland, 

1650 

POET Biorefining, 1535 

Valero Renewables, 890 

TBD Ownership (former 

VeraSun plants), 750 

ethanol producer with almost 900 million gallons of production capacity. How the rest of the 

company rankings fall out will be largely dependent on who purchases the remaining eight 

VeraSun ethanol plants (currently owned by banks and holding companies) totaling 750 million 

gallons of annual capacity. A summary of the projected ethanol plant ownership under the RFS2 

program is found in Figure1.5-4. 

Figure 1.5-4. 

Forecasted Corn/Starch Ethanol Production Capacity by Company 

1.5.1.3 Forecasted Growth in Advanced Processing Technologies 

While we can get a good idea of what the ethanol industry will look like in the near term 

by looking at currently existing ethanol plants and those under construction, further analysis is 

needed to forecast what the ethanol industry will look like in 2022. Significant changes in the 

primary fuel source and overall energy efficiency of ethanol production plants are likely to 

occur. The high price of natural gas has many ethanol plants considering alternative fuel 

sources. Greater biofuel availability and potential low life cycle green house gas emissions 

incentives may further encourage ethanol producers to transition from fossil fuels to biomass 

based fuels. As ethanol plants become more efficient and require less energy, their ability to use 

biofuels increases. Two of the biggest drawbacks to using biofuels currently are handling and 

storage costs. Due to the lower density of biofuels, as compared to coal, a larger area is required 

to store biomass with an equivalent heating value of coal. Handling costs are also increased as a 

larger volume of fuel must be moved. These negative impacts would be less significant in an 

ethanol plant using less energy. Lower overall energy use would also allow waste products and 

123
 
 

 

locally produced biofuels to make up a larger portion of the total fuel supply, reducing the 

purchase and transportation costs of the biofuels. It is likely that plants currently using natural 

gas would transition to using biogas and those using coal would transition to using solid biomass 

due to their ability to make these transitions without investing in new boiler equipment. The 

same factors, cost and lower life cycle green house gas emissions, are expected to increase the 

number of ethanol producers using combined heat and power (CHP) technology. Projections for 

the primary feedstock and use of CHP technology from 2020 to 2030 are summarized in Table 

1.5-12 below. 

Table 1.5-12.KK
 

Projected Primary Fuel Sources and CHP Usage 

2020 2022 2025 2030 

Natural Gas Boiler 54% 49% 42% 31% 

Natural Gas CHP 11% 12% 13% 15% 

Coal Boiler 0% 0% 0% 0% 

Coal CHP 4% 4% 4% 4% 

Biomass Boiler 10% 11% 12% 15% 

Biomass CHP 9% 10% 12% 15% 

Biogas Boiler 12% 14% 16% 20% 

The energy efficiency of ethanol plants are also expected to change significantly. New 

technologies are expected to both increase the efficiency of units currently used in ethanol 

production, as well as provide energy saving alternatives to conventional production practices. 

Increasing energy efficiency is a priority in many ethanol plants as is can dramatically increase 

profitability by reducing energy costs, the second highest cost of ethanol production behind raw 

materials. Several groups are currently working on technologies that could impact the ethanol 

industry. The Department of Energy’s (DOE) Super Boiler program is expected to produce 

boilers with an efficiency of 94% by 2020. The National Electrical Manufacturers Association’s 

(NEMA) premium efficiency motors are expected to be adopted more widely in the coming 

years. Electricity generation efficiency is also expected to increase, both on site at plants with 

CHP technology, and at central power plants supplying electricity to ethanol plants through the 

national grid. The projected energy savings from the energy efficiency improvements to units 

used in conventional ethanol plants in 2022 relative to 2007 is 32.1%. The projected energy 

savings from 2015 to 2030 are summarized in Table 1.5-13 below. 

KK Data based on “An Analysis of the Projected Energy Use of Future Dry Mill Corn Ethanol Plants (2010-2030)”; 

Steffen Mueller, University of Illinois at Chicago Energy Resource Center, October 10, 2007, Available online at: 

http://www.chpcentermw.org/pdfs/2007CornEethanolEnergySys.pdf 

124
 
 

 

Table 1.5-13.LL
 

Projected Energy Savings from Conventional Production Equipment 

2007 2015 2020 2022 2025 2030 

Boiler, Efficiency 82.0% 86.0% 90.0% 91.6% 94.0% 94.0%

 Energy Savings Relative to 2007 - 1.2% 8.9% 10.5% 12.8% 12.8% 

Motor, Efficiency 90.0% 92.0% 93.0% 93.8% 95.0% 95.0%

 Energy Savings Relative to 2007 - 2.2% 3.2% 4.0% 5.3% 5.3% 

10 MW Industrial Turbine, Efficiency 31.0% 33.0% 34.0% 34.0% 34.0% 34.0%

 Energy Savings Relative to 2007 - 6.1% 8.8% 8.8% 8.8% 8.8% 

Central Power Plant, Efficiency 30.5% 32.5% 33.5% 33.5% 33.5% 33.5%

 Energy Savings Relative to 2007 - 6.1% 8.8% 8.8% 8.8% 8.8% 

Total Energy Savings Relative to 2007 - 15.6% 29.7% 32.1% 35.7% 35.7% 

The same factors that drive ethanol producers to increase the energy efficiency of their 

equipment may also move them to consider energy saving changes to the ethanol production 

process. Several process changes, including raw starch hydrolysis, corn fractionation, corn oil 

extraction, and membrane separation, are likely to be adopted to varying degrees. The degree to 

which they are adopted will depend on many factors, including technology availability, capital 

cost of implementation, energy cost savings, and co-product revenue generation. A description 

of each of these technologies, including the challenges and benefits of their implementation, can 

be found in Section 1.4.1.3. The projected impact of the implementation of these technologies 

on ethanol production energy usage is to decrease the thermal energy usage by 12% and to 

increase the electrical energy usage by 3.8%. These numbers are based on a plant that is drying 

100% of its distillers grains and solubles (DGS). Plants that dry less than 100% of their DGS 

would be likely to realize smaller benefits from these technologies. The projected penetration of 

these technologies, and the associated energy use impact, is summarized in Table 1.5-14 below. 

LL Data based on “An Analysis of the Projected Energy Use of Future Dry Mill Corn Ethanol Plants (2010-2030)”; 

Steffen Mueller, University of Illinois at Chicago Energy Resource Center, October 10, 2007, 

125
 
 

Table 1.5-14.MM
 

Projected Energy Savings from Process Changes 

Percent of all Plants Adopting Process 

Process Improvement 2020 2022 2025 2030 

Raw Starch Hydrolysis 20% 22% 25% 30% 

Corn Fractionation 18% 20% 24% 30% 

Corn Oil Extraction 20% 22% 25% 30% 

Membrane Separation 3% 5% 5% 5% 

Energy Reduction from Base Process (Thermal) 

Raw Starch Hydrolysis 16% 16% 17% 17% 

Corn Fractionation 31% 31% 31% 32% 

Corn Oil Extraction 4% 4% 5% 5% 

Membrane Separation 29% 29% 29% 29% 

Weighted Average Savings (Thermal) 10.45% 12.05% 14.39% 17.65% 

Energy Reduction from Base Process (Electrical) 

Raw Starch Hydrolysis 0% 0% 0% 0% 

Corn Fractionation -9% -9% -8% -8% 

Corn Oil Extraction -9% -9% -8% -8% 

Membrane Separation 0% 0% 0% 0% 

Weighted Average Savings (Electrical) -3.42% -3.78% -3.92% -4.80% 

The combined effect of the energy efficiency improvements and the production process 

changes are expected to reduce the energy required to produce a gallon of ethanol significantly. 

We project a thermal energy use reduction of 42.1% and an electrical energy use reduction of 

25.8% by 2022. Based on the USDA’s 2007 estimated energy requirements of 38,717 BTU 

thermal energy/gallon ethanol and 3,242 BTU electrical energy/gallon ethanol for a dry mill 

ethanol plant fueled by natural gas drying 100% of its DDGS, we project that a similar plant in 

2022 would have energy requirements of 22,435 BTU thermal energy/gallon ethanol and 2,406 

BTU electrical energy/gallon ethanol. 

As these technologies are incorporated into more ethanol plants, or make progress 

towards commercial viability we are able to make better estimates as to their impacts on energy 

usage and expected penetration in the ethanol industry. Additionally, recent energy price 

fluctuations and decreasing ethanol profit margins have likely impacted ethanol producers’ 

ability and willingness to invest in new technology. For the final rule our projections of the 

technology penetration and its impact on energy use will be reevaluated and revised as 

necessary. The cost impacts of these technologies will also be analyzed. 

1.5.1.4 Projected Grandfathered Corn Ethanol Volume 

As explained in the Section III.B.3 of the Preamble, renewable fuel produced from new 

facilities which commenced construction after December 19, 2007 must achieve at least a 20% 

reduction in lifecycle greenhouse gas emissions compared to baseline lifecycle greenhouse gas 

MM Data based on “An Analysis of the Projected Energy Use of Future Dry Mill Corn Ethanol Plants (2010-2030)”; 

Steffen Mueller, University of Illinois at Chicago Energy Resource Center, October 10, 2007, with the exception of 

Membrane Separation data based on conversation with Leland Vane, EPA 

126
 
 

emissions in order to generate RINs under the proposed RFS2 program.NN However, facilities 

that commenced construction before December 19, 2007 are exempt or “grandfathered” from the 

20% GHG reduction requirement. In addition, facilities that commenced construction in 2008 or 

2009 are grandfathered if they burn natural gas, biomass, or any combination thereof. 

The ethanol plants (and corresponding production volumes) that are grandfathered under 

the RFS2 rule will be determined based on information received during the expanded registration 

process (refer to Section III.C of the Preamble). However, for the NPRM we thought it would be 

a useful exercise to estimate the volume of corn ethanol that might be grandfathered under this 

rule. 

To do so, we stated with our assessment of ethanol plants that were operational, idled, 

under construction, or expanding at the time of our April 2009 assessment (refer to Table 1.5-7). 

This amounts to around 15 billion gallons or the entire conventional biofuel standard. As such, 

for this exercise we assumed that these corn ethanol plants would be representative of those in 

production in the future under the RFS2 program. As shown in Table 1.5-9, 12.5 billion gallons 

are expected to come from 203 plants burning natural gas, biomass, or a combination thereof 

and the remaining 2.5 billion gallons are expected to come from 23 plants burning coal as their 

primary fuel. 

As illustrated in Figure 1.5-5 below, the 203 natural gas and/or biomass-fired plants 

would be grandfathered or “deemed complaint” under the proposed grandfathering provisions 

due to the fact that they commenced construction by 2008/2009 (refer to proposed regulation 

§80.1403). In addition, the 23 coal-fired plants would be grandfathered because it appears they 

were all either online or commenced construction prior to December 19, 2007 as summarized in 

Table 1.5-15. 

NN In accordance with Section 211(o)(2)(A)(i) of the Clean Air Act as amended by EISA. 

127
 
 

Figure 1.5-5. 

Estimate of Grandfathered Volume of Corn Ethanol Under RFS2 

128
 
 

 

 

 

 

 

 

 

 

 

Table 1.5-15. 

Projected Coal-Fired Ethanol Plants
 

Plant/Company Name City 

Operational Under Construction 

Capacity 

MGY 

Est. 

Prod 

Capacity 

MGY 

Est. 

Prod 

Ag Processing Inc. (AGP) Hastings, NE 52 1992 

Archer Daniels Midland (ADM) Cedar Rapids, IA 250 N/Aa 

Archer Daniels Midland (ADM) Cedar Rapids, IA 275 TBDb 

Archer Daniels Midland (ADM) Clinton, IA 190 N/Aa 

Archer Daniels Midland (ADM) Columbus, NE 95 1994 

Archer Daniels Midland (ADM) Columbus, NE 275 TBDb 

Archer Daniels Midland (ADM) Decatur, IL 290 N/Aa 

Archer Daniels Midland (ADM) Marshall, MN 40 1988 

Archer Daniels Midland (ADM) Peoria, IL 210 N/Aa 

Archer Daniels Midland (ADM) Walhalla, ND 25 N/Aa 

Aventine Renewable Energy, Inc. Pekin, IL 100 1981 

Blue Flint Ethanol LLC Underwood, ND 50 Feb-07 

Cargill Inc. Eddyville, IA 35 Sep-92 

Cargill, Inc. Blair, NE 85 Apr-94 

Chief Ethanol Fuels Inc. Hastings, NE 62 1985 

Corn LPc Goldfield, IA 50 Dec-05 

Grain Processing Corp Muscatine, IA 20 May-00 

Heron Lake BioEnergy, LLC Heron Lake, MN 50 Oct-07 

Lincolnway Energy LLC Nevada, IA 50 May-06 

Red Trail Energy, LLC Richardton, ND 50 Jan-07 

Riverland Biofuels Canton, IL 38 Oct-08d 

Southwest Iowa Renewable Energy (SIRE) Council Bluffs, IA 110 Feb-08e 

Tate & Lylef Loudon, TN 66 N/A 60 TBD a

It is unclear exactly when these five ADM ethanol plants came online. However, based on permitting information, it appears they 

commenced construction prior to December 17, 2007. 

b

It appears these dry-mill ADM expansion projects are currently on hold at the moment. However, based on permitting information 

and an August 28, 2007 e-mail construction update, it appears these expansion projects began prior to December 17, 2007. 

c

This Corn LP plant burns biomass in addition to coal. 

d

This plant was was originally proposed in 2001 as Central Illinois Energy. Local farmers provided start-up capital but due to lack of 

additional financing, ground wasn’t broken on the plant until October 2006. The project went over budget and Central Illinois 

Energy was forced to file for bankruptcy in December 2007. Riverland Biofuels took over the project, completed construction of 

the plant, and started producing ethanol in October 2008. Based on the information provided, it appears this plant commenced 

construction prior to December 17, 2007. 

e

A "groundbreaking" ceremony was held on November 11, 2006, a final permit was issued on April 19, 2007, construction was well u 

f

It is unclear exactly when this Tate & Lyle ethanol plant came online and when the expansion project began. However, since both pr 

1.5.1.5 May 2008 Assessment of the Corn Ethanol Industry 

The information presented above in Sections 1.5.1.1 and 1.5.1.2 (as well as 1.5.1.4) 

represents our most current assessment of the corn/starch ethanol industry. However, we relied 

on an earlier May 2008 industry assessment to reflect existing corn ethanol production and 

project future growth under the proposed RFS2 program. This was the best information 

available at the time our distribution, cost, emission and air quality analyses were conducted. 

This was before the economic recession forced many companies to idle plants, file for Chapter 

11 bankruptcy and/or to sell off ethanol plants/projects. As a result, the starting ethanol 

129
 
 

 

 

 

production is slightly different from the information presented in Section 1.5.1.1. However, 

since we assume that many of the idled plants/projects would come back online in the future; the 

final RFS2 projections are not that different from the information presented in Section 1.5.1.2. A 

summary of the relevant May 2008 industry information used to support various NPRM analyses 

is presented below. 

Previously Existing Corn/Starch Ethanol Production 

At the time of our May 2008 corn ethanol plant assessment, there were 158 fuel ethanol 

plants operating in the U.S. with a combined production capacity of 9.2 billion gallons per 

OO291292 year. The majority of ethanol (nearly 89% by volume) was produced exclusively from 

corn. Another 11% came from a blend of corn and/or similarly processed grains (milo, wheat, or 

barley) and less than half a percent was produced from cheese whey, waste beverages, and 

sugars/starches combined. A summary of the feedstocks utilized by the U.S. ethanol industry as 

of May 2008 is found in Table 1.5-16. 

OO Our May 2008 corn/starch ethanol industry characterization was based on a variety of data sources including: 

Renewable Fuels Association (RFA) Ethanol Biorefinery Locations (updated April 2, 2008); Ethanol Producer 

Magazine (EPM) Current plant list (last modified on April 14, 2008), and ethanol producer websites. The baseline 

does not include ethanol plants whose primary business is industrial or food-grade ethanol production. Where 

applicable, ethanol plant production levels were used in lieu of nameplate capacities to estimate plant production. 

The baseline does not include U.S. plants that were idled as of May 2008 or plants that might be located in the 

Virgin Islands or U.S. territories. 

130
 
 

 

 

 

 

 

 

Table 1.5-16. 

May 2008 Corn/Starch Ethanol Production Capacity by Feedstock 

Plant Feedstock 

(Primary Listed First) 

Capacity 

MGY 

% of 

Capacity 

No. of 

Plants 

% of 

Plants 

Corna 8,141 88.8% 131 82.9% 

Corn, Milob 704 7.7% 14 8.9% 

Corn, Wheat 130 1.4% 1 0.6% 

Corn, Wheat, Milo 115 1.3% 2 1.3% 

Milo 3 0.0% 1 0.6% 

Wheat, Milo 50 0.5% 1 0.6% 

Cheese Whey 8 0.1% 2 1.3% 

Waste Beveragesc 13 0.1% 4 2.5% 

Waste Sugars & Starchesd 7 0.1% 2 1.3% 

Total 9,169 100% 158 100% 

a

Includes one facility processing seed corn, one facility also operating a pilot-level cellulosic ethanol 

plant, and six facilities with plans to build pilot-level cellulosic ethanol plants or incorporate biomass 

feedstocks in the future. 

b

Includes one facility processing small amounts of molasses in addition to corn and milo. 

c

Includes two facilities processing brewery waste. 

d

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

The corn ethanol industry relies primarily on natural gas. At the time of our May 2008 

plant assessment, 134 of the 158 corn/starch ethanol plants burned natural gas (exclusively).PP In 

addition, three burned a combination of natural gas and biomass, one burned a combination of 

natural gas, landfill syngas and wood, while one burned a combination of natural gas and syrup 

from the process. In addition, 18 plants burned coal as their primary fuel and one burned a 

combination of coal and biomass. Our research suggested that 24 plants utilized cogeneration or 

combined heat and power (CHP) technology at the time of our assessment. A summary of the 

energy sources and CHP technology utilized by the U.S. ethanol industry as of May 2008 is 

found in Table 1.5-17. 

PP Facilities were assumed to burn natural gas if the plant boiler fuel was unspecified or unavailable on the public 

domain. 

131
 
Table 1.5-17. 

May 2008 Corn/Starch Ethanol Production Capacity by Energy Source 

Plant Energy Source 

(Primary Listed First) 

Capacity 

MGY 

% of 

Capacity 

No. of 

Plants 

% of 

Plants 

CHP 

Tech. 

Coala 

Coal, Biomass 

Natural Gasb 

Natural Gas, Biomassc 

Natural Gas, Landfill Syngas, Wood 

Natural Gas, Syrup 

1,720 

50 

7,141 

113 

100 

46 

18.8% 

0.5% 

77.9% 

1.2% 

1.1% 

0.5% 

18 

1 

134 

3 

1 

1 

11.4% 

0.6% 

84.8% 

1.9% 

0.6% 

0.6% 

8 

0 

15 

1 

0 

0 

Total 9,169 100.0% 158 100.0% 24 

a

Includes four plants that are permitted to burn biomass, tires, petroleum coke, and wood waste in addition to 

coal and one facility that intends to transition to biomass in the future. b

Includes one facility that intends to burn thin stillage biogas, five facilities that intend to transition to coal, and 

one facility that intends to switch to biomass in the future. 

c

Includes one facility processing bran in addition to natural gas. 

Besides a few plants located outside of the Corn Belt, the majority of ethanol is produced 

in PADD close to where the corn is grown. At the time of our May 2008 ethanol industry 

characterization, PADD 2 accounted for 94% (or 8.6 billion gallons) of the estimated ethanol 

production capacity as shown in Table 1.5-18 below. 

Table 1.5-18. 

May 2008 Corn/Starch Ethanol Production Capacity by PADD 

PADD 

Capacity 

MGY 

% of 

Capacity 

No. of 

Plants 

% of 

Plants 

PADD 1 

PADD 2 

PADD 3 

PADD 4 

PADD 5 

50 

8,619 

170 

160 

171 

0.5% 

94.0% 

1.9% 

1.7% 

1.9% 

2 

140 

3 

7 

6 

1.3% 

88.6% 

1.9% 

4.4% 

3.8% 

Total 9,169 100.0% 158 100.0% 

Leading the Midwest in ethanol production were Iowa, Nebraska, Illinois, South Dakota 

and Minnesota. Together, these five states’ 93 ethanol plants accounted for 67 percent of the 

nation’s ethanol production capacity in May 2008. For a map of the ethanol plant locations and a 

summary of ethanol production capacity by state, refer to Figure 1.5-6 and Table 1.5-19 below. 

132
 
Figure 1.5-6. 

May 2008 Corn/Starch Ethanol Plant Locations 

133
 
Table 1.5-19. 

May 2008 Corn/Starch Ethanol Production Capacity by State 

State 

Capacity 

MGY 

% of 

Capacity 

No. of 

Plants 

% of 

Plants 

Iowa 2,282 24.9% 30 19.0% 

Nebraska 1,278 13.9% 22 13.9% 

Illinois 941 10.3% 9 5.7% 

South Dakota 892 9.7% 14 8.9% 

Minnesota 749 8.2% 18 11.4% 

Indiana 540 5.9% 7 4.4% 

Wisconsin 479 5.2% 8 5.1% 

Kansas 464 5.1% 12 7.6% 

Ohio 345 3.8% 4 2.5% 

Michigan 214 2.3% 4 2.5% 

Missouri 202 2.2% 5 3.2% 

Colorado 146 1.6% 5 3.2% 

Texas 140 1.5% 2 1.3% 

North Dakota 125 1.4% 3 1.9% 

California 81 0.9% 4 2.5% 

Tennessee 66 0.7% 1 0.6% 

New York 50 0.5% 1 0.6% 

Arizona 50 0.5% 1 0.6% 

Kentucky 40 0.4% 2 1.3% 

Oregon 40 0.4% 1 0.6% 

New Mexico 30 0.3% 1 0.6% 

Wyoming 9 0.1% 1 0.6% 

Idaho 5 0.1% 1 0.6% 

Oklahoma 2 0.0% 1 0.6% 

Georgia 0 0.0% 1 0.6% 

Total 9,169 100.0% 158 100.0% 

134
 
 

 

 

 

Preliminary Forecasted Growth in Corn/Starch Ethanol Production Under RFS2 

According to our industry assessment, there were 59 ethanol plants under construction or 

expanding as of May 2008 with a combined production capacity of 5.2 billion gallons per 

year.QQ These projects were at various phases of construction from conducting land stabilization 

work, to constructing tanks and installing ancillary equipment, to completing start-up activities. 

Unfavorable market conditions have recently driven a number of producers to delay construction 

or scrap plans altogether. However, we believe that implementation of the RFS2 program will 

help revitalize ethanol production. As such, we assumed that all this capacity would eventually 

come online as well as a number of other projects that were at advanced stages of planning at the 

time of our May 2008 industry assessment. 

Once all the aforementioned projects are complete, we projected that there would be 216 

corn/starch ethanol plants operating in the U.S. with a combined production capacity of about 15 

billion gallons per year. Much like today’s ethanol production facilities, the overwhelming 

majority of new plant capacity (95% by volume) was expected to come from corn-fed plants. 

The remainder was forecasted to come from plants processing a blend of corn and milo. A 

summary of the forecasted ethanol production by feedstock under the RFS2 program based on 

our May 2008 plant assessment is found in Table 1.5-20. 

QQ Based on Renewable Fuels Association (RFA), Ethanol Biorefinery Locations – Under Construction/Expansions 

(updated April 4, 2008); Ethanol Producer Magazine (EPM), Under Construction plant list (last modified on April 

14, 2008), ethanol producer websites, and follow-up correspondence with ethanol producers. 

135
 
 

 

 

 

 

 

 

Table 1.5-20. 

May 2008 Projected RFS2 Ethanol Production Capacity by Feedstock 

Plant Feedstock 

(Primary Listed First) 

New Plants/Exp. Total RFS2 Est. 

Capacity 

MGY 

No. of 

Plants 

Capacity 

MGY 

No. of 

Plants 

Corna 5,526 54 13,666 185 

Corn, Milob 303 4 1,007 18 

Corn, Wheat 0 0 130 1 

Corn, Wheat, Milo 0 0 115 2 

Milo 0 0 3 1 

Wheat, Milo 0 0 50 1 

Cheese Whey 0 0 8 2 

Waste Beveragesc 0 0 13 4 

Waste Sugars & Starchesd 0 0 7 2 

Total 5,829 58 14,998 216 

a

Includes one facility processing seed corn, one facility also operating a pilot-level cellulosic 

ethanol plant, and six facilities with plans to build pilot-level cellulosic ethanol plants or 

incorporate biomass feedstocks in the future. 

b

Includes one facility processing small amounts of molasses in addition to corn and milo. 

c

Includes two facilities processing brewery waste. 

d

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

Based on May 2008 industry plans, the majority of new corn/grain ethanol production 

capacity (82% by volume) was predicted to come from new or expanded plants burning natural 

gas. Additionally, we forecasted one new plant burning a combination of natural gas and syrup 

(from the process) and an expansion at an existing facility burning natural gas and biomass. Our 

predictions also suggest two new coal-fired ethanol plants and three expansions at existing coalfired plants.RR Finally, we projected three new plants burning alternative fuels – one relying on 

manure biogas, one burning biomass, and one burning a combination of biomass and thin stillage 

from the process.SS Our research indicated that nine of the 58 new plants would utilize 

cogeneration, bringing the total number of CHP facilities to 33. A summary of the forecasted 

ethanol plant energy sources in 2022 under the RFS2 program is found in Table 1.5-21. 

RR Two of the three coal-fired plant expansions appear as new plants in Table 1.5-21. This is because two of the 

expansion projects consist of adding dry milling plant capacity to an existing wet mill plant. However, our 

interpretation is that these facilities will rely on the same (potentially expanded) coal-fired boilers for process steam. 

Since all the aforementioned coal-fired ethanol production facilities appear to have commenced construction prior to 

December 19, 2007, we project that the ethanol produced at these facilities will be grandfathered under the proposed 

RFS2 rule. For more on our grandfathered volume estimate, refer to Section 1.5.1.4. SS Thin stillage is a process liquid with 5–10 percent solids taken out of the distillers grains via centrifuge. 

However, construction on this alternatively fuel ethanol plant near Heyburn, ID was recently terminated. 

Accordingly, this plant was not included in our April 2009 RFS2 projections. 

136
 
 

 

 

 

 

Table 1.5-21. 

Projected Near-Term Corn/Starch Ethanol Production Capacity by Energy Source 

(Based on May 2008 Ethanol Industry Characterization) 

Plant Energy Source 

(Primary Listed First) 

New Plants/Exp. Total RFS2 Est. 

Capacity 

MGY 

No. of 

Plants 

Capacity 

MGY 

No. of 

Plants 

CHP 

Tech. 

Biomass 88 1 88 1 0 

Coala 740 4 2,460 22 12 

Coal, Biomass 0 0 50 1 0 

Manure Biogas 115 1 115 1 0 

Natural Gasb 4,776 50 11,917 184 19 

Natural Gas, Biomassc 40 0 153 3 1 

Natural Gas, Landfill Biogas, Wood 0 0 100 1 0 

Natural Gas, Syrup 50 1 96 2 0 

Thin Stillage Biogas, Biomass 20 1 20 1 1 

Total 5,829 58 14,998 216 33 

a

Includes four existing plants and two under construction facilities that are permitted to burn biomass, tires, 

petroleum coke, and wood waste in addition to coal. Also includes one facility that intends to transition to biomass 

in the future. 

b

Includes one facility that intends to burn thin stillage biogas, six facilities that intend to transition to coal, and one 

facility that intends to switch to biomass in the future. 

c

Includes one facility processing bran in addition to natural gas. 

The information presented in Table 1.5-21 is based on near-term production plans at the 

time of our May 2008 industry assessment. As mentioned in Section 1.5.1.2, we anticipate 

additional growth in advanced ethanol production technologies in the future under the proposed 

RFS2 program. For more on our projected 2022 utilization of these technologies under the RFS2 

program, refer to Section 1.5.1.3. 

Based on our May 2008 assessment, 85% of new ethanol production capacity under 

RFS2 is expected to originate from PADD 2. For a summary of this and other forecasted PADDlevel production projections, refer to Table 1.5-22. 

137
 
Table 1.5-22. 

May 2008 Projected RFS2 Corn/Starch Ethanol Production Capacity by PADD 

PADD 

New Plants/Exp. Total RFS2 Est. 

Capacity 

MGY 

No. of 

Plants 

Capacity 

MGY 

No. of 

Plants 

PADD 1 

PADD 2 

PADD 3 

PADD 4 

PADD 5 

214 

5,002 

215 

70 

328 

2 

47 

2 

2 

5 

264 

13,620 

385 

230 

499 

4 

187 

5 

9 

11 

Total 5,829 58 14,998 216 

Our May 2008 assessment suggested that Iowa, Nebraska, and Illinois would continue to 

dominate ethanol production under RFS2 with a collective annual production capacity of about 

7.5 billion gallons. Minnesota and Indiana were projected to be the fourth and fifth largest 

ethanol producers. A map of the forecasted corn ethanol plant locations based on our May 2008 

assessment is provided in Figure 1.5-7 and a summary of the ethanol production capacity by state 

is presented in Table 1.5-23. 

Figure 1.5-7. 

May 2008 Projected RFS2 Corn/Starch Ethanol Plant Locations 

138
 
 

Table 1.5-23. 

May 2008 Projected RFS2 Corn/Starch Ethanol Production Capacity by State 

State 

New Plants/Exp. Total RFS2 Est. 

Capacity 

MGY 

No. of 

Plants 

Capacity 

MGY 

No. of 

Plants 

Iowa 1,573 13 3,854 43 

Nebraska 959 7 2,237 29 

Illinois 465 4 1,406 13 

Minnesota 440 4 1,189 22 

Indiana 470 5 1,010 12 

South Dakota 100 1 992 15 

Kansas 203 4 667 16 

Wisconsin 70 1 549 9 

Ohio 185 3 530 7 

Texas 215 2 355 4 

North Dakota 210 2 335 5 

Michigan 107 1 321 5 

Missouri 60 1 262 6 

California 160 3 241 7 

Tennessee 160 1 226 2 

New York 114 1 164 2 

Oregon 113 1 153 2 

Colorado 0 0 146 5 

Georgia 100 1 100 2 

Idaho 70 2 75 3 

Washington 55 1 55 1 

Arizona 0 0 50 1 

Kentucky 0 0 40 2 

New Mexico 0 0 30 1 

Wyoming 0 0 9 1 

Oklahoma 0 0 2 1 

Total 5,829 58 14,998 216 

1.5.2 Imported Ethanol 

1.5.2.1 Historic/Current Imports and Exports 

In order to assess the potential for U.S. imported ethanol, we examined the chief 

countries that are currently producing or consuming relatively large volumes of ethanol. In 

particular, we chose to focus on Brazil, the European Union (EU), Japan, India, and China to 

determine whether each country will likely be an importer or exporter of ethanol in the future. 

The following sections first describe the ethanol demands of each of these countries due to 

enacted or proposed mandates and goals as well as their ability to supply those demands with 

139
 
 

domestically produced ethanol. We conclude the analysis by examining the most likely 

pathways for imported ethanol, namely through the Caribbean Basin Initiative (CBI) and directly 

from Brazil. 

1.5.2.1.1 Brazil 

Much of the potential of imported ethanol will depend on the ability for Brazil to supply 

ethanol to the United States and other countries. This is because Brazil has been a top producer 

and is the top exporter of ethanol in the world. In fact, many countries are interested in Brazilian 

produced sugarcane ethanol because it is currently the least costly method for producing ethanol. 

No other nation is seen as being able to supply any reasonably large amount of ethanol, and as 

such, it is important to devote much of the import potential discussion to Brazil. 

Brazil has been steadily increasing its exports of ethanol, with total exports escalating 

from under 700 million gallons in 2005 to over 1200 million gallons in 2008. As seen in Figure 

1.5-8, Brazil exports ethanol to many different countries around the globe. Prior to 2006, the 

majority of Brazilian ethanol exports flowed to the EU and Caribbean due to favorable 

economics. In 2006, the majority of Brazilian ethanol exports (52%) went to the U.S as a result 

of the withdrawal of MTBE from the U.S. fuel pool and an increased price of ethanol. As 

countries create their own biofuels mandates and goals, they will also be looking to other 

countries such as Brazil to supply large amounts of biofuels. Countries may essentially be 

“competing” against one another for Brazilian ethanol in the future to meet their mandates and 

goals. 

Figure 1.5-8. Brazil Ethanol Exports (Includes all types of ethanol).293,294,295 Million Gallons 

1400 

1200 

1000 

800 

600 

400 

200 

0 

2005 2006 2007 2008 

Others 

Venezuela 

Japan 

India 

Mexico 

Nigeria 

South Korea 

Caribbean 

EU 

U.S. 

140
 
 

Brazil currently produces both hydrous and anhydrous ethanol. Hydrous ethanol has 

96% ethanol and 4% water in its composition, whereas anhydrous ethanol is made up of 99.5% 

ethanol and 0.5% water.296 In 2006, total ethanol consumption made up 17.2% (9.9% hydrous 

and 7.3% anhydrous) of the vehicle fuel pool with the rest being: 27.2% Gasoline A (pure 

gasoline before blending with ethanol), 3.2% vehicular natural gas (VNG), 3.3% B2 (diesel 

blended with 2% biodiesel), and 48.9% Diesel.297 Of light duty vehicles only, ethanol accounts 

for 36.1% of the total fuel pool in Brazil. 

While hydrous ethanol is used directly in Otto-cycle motors (100%), anhydrous ethanol is 

mixed with pure gasoline at 20-25% by volume. Production of anhydrous ethanol to be mixed 

with gasoline has fallen since the 2005/2006 harvest, on account of the smaller share of cars 

running exclusively on gasoline. This was especially due to the success of flex vehicles with 

Brazilian customers.298 In fact, sales of flex-fuel vehicles (FFVs) in Brazil, those that can use 

any mixture of gasoline and ethanol from 0 to 100%, have grown dramatically, with domestic 

FFV sales representing 91% of vehicles sold in 2008.299 Hydrous ethanol production, on the 

other hand, has grown almost constantly in recent years. However, in the 2008/2009 crop year, 

growth in hydrous ethanol was much larger, with hydrous ethanol accounting for 65% of ethanol 

production in Brazil. Figure 1.5-9 shows the historical production of hydrous and anhydrous 

ethanol in Brazil. 

Figure 1.5-9. 

Historical Ethanol Production of Hydrous and Anhydrous Ethanol in Brazil.300 

5,000 Hydrous Ethanol
 

4,500
 Anhydrous Ethanol 

4,000 

Million Gallons 3,500 

3,000 

2,500 

2,000 

1,500 

1,000 

500 

0 

199719981999200020012002200320042005200620072008 

141
 
In contrast to Brazil, ethanol consumed in the U.S. must first be converted to anhydrous 

ethanol before its use in conventional or FFV vehicles. This differs from Brazil because 

Brazilian FFVs can use hydrous ethanol, or E100 (100% ethanol), whereas U.S. FFVs can only 

use up to E85 (85% ethanol and 15% gasoline by volume). As a result, if hydrous ethanol is 

exported from Brazil, it must be dehydrated somewhere else before it is used in the U.S. This is 

the case for the majority of ethanol exported from Brazil to the Caribbean, where it is dehydrated 

and often re-exported to the U.S. for consumption. 

In terms of future ethanol production, however, there has been much speculation about 

Brazil’s ability to increase production. Sugarcane analyst Datagro recently stated that Brazil’s 

ethanol fuel production would have to grow by approximately 800 million gallons a year through 

2025 to keep up with demand at home and abroad.301 Estimates of future ethanol production in 

Brazil range greatly. See Figure 1.5-10. Brazil’s government has adopted plans to meet global 

demand by tripling production by 2020.302 This would mean a total capacity of approximately 

12.7 billion gallons, to be achieved through a combination of efficiency gains, greenfield 

projects, and infrastructure expansions. Estimates for the investment required tend to range from 

$2 billion to $4 billion a year. Other estimates indicate that based on current projects the 

required investment in capacity expansion is $3-4 billion annually.303 If global demand were to 

increase much more than Brazil is planning, then capacity would need to expand even further 

and thus greater investment dollars would be required. 

Figure 1.5-10. Estimated Brazilian Ethanol Production Volumes304 

25,000

2000 2010 2020 2030 2040

FAPRI 2007

Agricultural Outlook 

OECD-FAO 

Agricultural Outlook 

Bioenergia (2007) 

Rothkopf (2006)

EPE (2007) 

Unica 

20,000 

15,000 

10,000 

5,000 

0 

Million Gallons 

142
 
 

 

To meet the growing demand, the Brazilian sugar and ethanol industry is already rapidly 

expanding and numerous mills have been planned. This includes over 90 new plants (354 

existing plants in 2007/2008) that will be set up in the next five years, allowing the expansion of 

processing from 383 to 560 million tonnes of sugarcane by 2010/2011.305,306 Brazil’s stateowned development bank BNDES said the country is set to invest $13.1 billion between 2007 

and 2011 in 89 of these new sugar and ethanol mills.307 Some estimate even more, where 

investments in sugarcane processing factories are expected to top $23 billion over the next four 

years.308 Recent investments also include a project by Odebrecht, a Brazilian engineering 

company that will invest $2.6 billion dollars over the next decade to build 12-15 plants with a 

combined capacity to crush at least 30-40 Mt/year of sugarcane and produce ~ 400 million 

gallons per year of ethanol.309 Even U.S. ethanol producer ADM is preparing to enter the sugarcane business in Brazil. A recent quote by ADM’s senior vice president of strategy, Steve Mills, 

said that sugar cane ethanol is now “a key component” of ADM’s short-term strategy and, 

“We’re devoting a lot of time and energy to this area. We’re not talking about something 10 

years down the road. It’s on the front burner.”310 To put these estimates of production capacity 

expansion into perspective, 383 million tonnes of sugar cane yielded 26.2 million tonnes of raw 

sugar and approximately 4.2 billion gallons of ethanol in 2005. If we assume the same split 

between sugar and ethanol then by 2010 we could expect an additional ~2 billion gallons of 

ethanol produced from Brazil each year from now until 2010/2011. 

In addition to expanding sugarcane production and ethanol production plant capacity, 

Brazil will need to improve its current ethanol distribution infrastructure. Brazil’s transport 

system is predominantly road-based.311 Railroad infrastructure and use of a waterway system is 

lacking, as well as very low availability of multi-mode terminals. Logistics currently represent 

22% of the export expenses and is one of the areas where costs need to be reduced in order for 

Brazilian ethanol to become more competitive abroad.312 

One way of dealing with this lack of infrastructure is to invest in enlarging the pipeline 

network. Petrobras, Brazil’s largest petroleum refiner is planning to build a pipeline to transport 

ethanol destined for export from the states of Sao Paulo, Minas Gerais, Mato Grosso, Mato 

Grosso do Sul, Goias, and Parana. The pipeline is anticipated to go online in October 2010, with 

$232 million invested in the project. By 2012 Petrobras will spend more than $1.6 billion to 

improve logistics infrastructure to transport Brazilian production. By 2011, Petrobras has the 

goal of exporting 920 million gallons per year.313 Recent updates indicate a perhaps more 

optimistic timeframe for completion, stating that Petrobras will complete the first of two ethanol 

pipelines in 2009.314 One of the pipelines will run from Goias state in Brazil’s center-west to 

Petrobras’s Paulinia refinery in Sao Paulo State. The project is called PMCC Projetos de 

Transporte de Alcool. The line is expected to have the capacity to ship 3.2 million gallons of 

ethanol annually.315 

Other competitors include the joint venture from Cosan, Copersucar, and Crystalsev 

which will make initial investments of $11.5 million apiece to install an ethanol-only pipeline 

between the oil refinery in Paulinia, to an ethanol offloading terminal on the state’s coast. In 

addition, at least three major private equity groups (Infinity, Clean Energy Brazil, and Brenco) 

plan to invest $1 billion in a 683 mile long ethanol pipeline expected to be completed by 2011 

with a capacity to deliver 1.1 million gallons of ethanol a year. In total, it is estimated that Brazil 

143
 
 

will need to invest $1 billion each year for the next 15 years in infrastructure to keep pace with 

capacity expansion and export demand.316 

Another area that requires investment is in R&D and education. Currently, Brazil 

produces only 0.08 engineers for every 1000 people, compared to 0.2 in the US, 0.33 in the EU, 

and 0.8 in Korea.317 In addition, there are deficiencies in basic education in Brazil’s north and 

northeast regions. Since certain types of education require a long lead time (e.g. scientific 

training) Brazil will need to continue to invest in training and professional development for the 

sector’s labor pool to meet the growing demand in the biofuels industry. 

Before ethanol can be exported to other countries, Brazil’s own domestic fuel 

consumption should be met. Brazil currently has an ethanol mandate of 25% (as of July 1, 

2007).318 The Brazilian ethanol to gasoline mix is set by the Brazilian government, which has 

the flexibility to adjust the ethanol mandate of 20-25% by volume ethanol to gas ratio. Ethanol 

currently represents nearly 30% of the light vehicle fuel market in Brazil.319 Approximately 

80% of new vehicles sold in Brazil in 2006 were flex fuel (1.6 million vehicles). The current 

increase in domestic consumption of ethanol in Brazil is partially due to the success of the flexfueled vehicle. 

At some point in the future, Brazil’s light vehicle fleet will likely become saturated with 

FFVs in preference to gasoline. As such, the rate in domestic demand for ethanol is expected to 

begin to slow.320 Thus, as domestic demand begins to level off, some experts believe that there is 

a significant possibility that exports will become more relevant in market share terms. Figure 

1.5-11 shows various estimates for future Brazilian ethanol domestic consumption. 

144
 
Figure 1.5-11. Estimated Brazilian Ethanol Consumption Volumes 321 

0 

5,000 

10,000 

15,000 

20,000 

25,000 

Million Gallons 

Canaplan, Director 

Carvalho 

FAPRI 2007 

Agricultural Outlook 

EPE (2007) 

Unica 

2000 2010 2020 2030 2040 

After domestic consumption is met, the rest of the ethanol can be available for exports to 

other countries. Potential worldwide exports basically equal the total production minus the total 

consumption. Given the available data, only three sources estimated both production and 

consumption for some of the years during 2010-2022. As such, these values were used to 

compute reasonable export volumes for Brazil as seen in Figure 1.5-12. Estimates from EPE and 

Unica indicate that as much as 3.8-4.2 billion gallons could be exported by Brazil in the 

2020/2022 timeframe. Longer timeframe estimates from sugarcane analyst Datagro project 

international ethanol sales to grow to 6.6 billion gallons by 2025.322 

145
 
 

 

Figure 1.5-12. Estimated Brazilian Export Volumes 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

Million Gallons

EPE (2007) 

Unica 

FAPRI 2007 

Agricultural Outlook 

2010 2012 2014 2016 2018 2020 2022 

1.5.2.1.2 The European Union (EU) 

Although the EU market has largely focused on biodiesel, ethanol has increasingly 

become important. Fuel ethanol demands are increasing due to the introduction of mandatory 

blending targets. In 2001 an EU Directive established that by 2005 biofuels should cover 2% of 

the total fuel consumption (energy basis), while the target for 2010 was set at 5.75%. However, 

in recent years the average biofuel contribution has been much less (i.e. 0.5%, 0.6% and 1% in 

2003, 2004, and 2005, respectively).323 

The EU is currently considering a binding target requiring 10% biofuel use for transport 

by 2020, although the target has recently come under criticism due to concerns over 

deforestation and food security problems.324 The International Energy Outlook (IEO) 2007 

forecasts OECD European countries will consume 159 billion gasoline gallons equivalent (gge) 

of transport fuel in 2010, growing to 167 gge by 2030.325 Assuming a split of nearly 70% fuel 

volume consumed as diesel and 30% consumed as gasoline (current use), a 10% by energy 

requirement would require roughly 7.3 billion gallons of ethanol in 2022.TT,326 However, this 

may be a slight overestimate of gasoline use since the overall gasoline consumption in the EU is 

declining as a result of the increasing popularity of more economic diesel-powered cars. Other 

sources indicate smaller gasoline consumption volumes are possible by the 2020/2022 timeframe 

which when translated equals 5.2-5.4 billion gallons of ethanol assuming a 10% energy 

requirement.327,328 

TT Assuming energy contents 115,000 Btu/gal for gasoline and 77,930 Btu/gal for denatured ethanol and 164 gge in 

146
 

2022 
 

However, many believe that even 10% is unrealistic and are calling for a lower 

percentage for biofuels. Most recently, the EU Energy Committee has passed draft legislation 

that if approved is expected to forbid the 27 EU countries from importing ethanol produced with 

excessive use of natural resources such as water or stimulates forest devastation.329 As a result, 

Brazilian stakeholders are monitoring such potential modifications in EU biofuels policy as it 

will affect the potential demand for ethanol from the EU. 

Fuel ethanol production in the EU has been much lower than this, with less than 1 billion 

gallons produced historically (457 million gallons in 2007).330 Germany, Spain, France, Poland, 

and Sweden represent almost 90% of the production in 2007. According to the “World Biofuels: 

FAPRI 2007 Agricultural Outlook”, ethanol production in the EU is expected to grow to 1.5 

billion gallons by 2016. Taking this into account, the EU would need to import approximately 4­

6 billion gallons of ethanol in order to meet the 10% volume requirement if only traditional crops 

are used. It should be noted, however, that the EU production estimates in the FAPRI 

Agricultural Outlook does not reflect the EC directive volume requirement since the targets were 

announced after the report was issued. This could spur greater production in the EU and reduce 

the amount needed from ethanol exporters such as Brazil. 

As of March 1, 2009, the installed capacity of the EU ethanol industry is 1.4 billion 

gallons, while a further 1 billion gallons are under construction and another 3 billion gallons has 

been announced. 331,332 Totaling these capacity estimates, the EU would have 5 billion gallons 

ethanol capacity. While not all the announced projects in the EU will be completed, this gives an 

estimate of how fast and large ethanol production in the EU could grow. If we assumed that EU 

could produce this volume by 2022, as much as 2 billion gallons would need to be imported from 

other countries assuming a 7.3 billion gallon demand due to the 10% mandate. It appears likely 

from the above analysis that the EU will continue to be a net importer of biofuels under most 

future scenarios. 

Due to constraints in ethanol production from current available technologies and 

feedstocks, the EU is continuing its development of second generation biofuels based on 

cellulosic materials. The majority of attention has been in Sweden, and to a lesser extent, the 

UK, Spain, and Netherlands. If ethanol from cellulosics proves feasible and commercial-scale 

production is realized in the future, additional ethanol supplies from such feedstocks may help 

lessen the amount needed from imports. 

1.5.2.1.3 Japan 

Until recently, Japan did not produce much ethanol and imported the majority of their 

consumption.333 Now the government is showing signs of encouraging biofuels production by 

promoting (not mandating) a 3% blend of ethanol in gasoline. At the very least, a non-mandatory 

3% blend will create a demand of 106-132 million gallons of ethanol. 334 This is similar to 

Japan’s Agency for Natural Resources and Energy target to replace 132.1 million gallons of 

transportation fuel by 2010, using ethanol and biodiesel.335 

With the passage of legislation calling for a 3% ethanol mandate in gasoline blend, 

Brazilian ethanol companies are hopeful that trade will increase substantially with Japan (this 

147
 
may even reach over 1.5 billion gallons annually if a 10% ethanol blend was implemented 

nationwide in Japan, approximately 500 million gallons with E3 blends).336 While in the future 

use of greater than E3 blends in Japan may be unlikely, the Japanese government has mandated 

that all gasoline powered vehicles run on E-10 blends by 2030 and will also enact legislation to 

require all new vehicles to be E-10 compatible by 2012. 337,338 

The prospect for large domestic production of ethanol in Japan appears to be quite small 

due to limitations on feedstock. The Agriculture Ministry states that Japan has enough feedstock 

to produce 26.4 million gallons per year, however, the Ministry of Environment (MOE) expects 

Japan to meet only 10% of the 132.1 million gallon target (or 13.2 million gallons) with domestic 

ethanol production.339 The Ministry of Agriculture and Fisheries (MAFF), on the other hand, 

predicts that Japan could reasonably expect to supply approximately 95 million gallons. Even 

with these higher domestic production estimates, Japan would still be a net importer of fuel 

ethanol if the biofuels target is met. The potential estimated demand for imported ethanol ranges 

from 37 million gallons to 1572 million gallons depending on the type of mandate assumed and 

the differences in the estimates of domestic ethanol production. 

Table 1.5-24 details new plants that are under construction. The total capacity is much 

lower than the 132.1 million gallons of ethanol goal and further supports the argument that Japan 

will likely be heavily dependent on imports. 

Table 1.5-24. Upcoming/Recent Plants in Japan340 

Plant Capacity Feedstock Year 

3 from Agriculture ~4 million Local crops: rice, low-quality 

Ministry gallons/year wheat, sugarbeet, sugarcane 

Hokkaido 3.96 million Sugar beets that aren’t 2007­

Prefectural Union of gallons/year; targeted for domestic sugar construction 

Agricultural start producing and substandard wheat 2009-

Cooperatives 3961 gal/year unusable for food production 

Nippon Steel Plant 104.89 gallons Food waste from: April 2007­

daily (38,285 supermarkets, restaurants, operational 

gallons/year) schools, hospitals. (10 tons 

annually) 

Mitsui Engineering Agricultural wastes: felled 2010: trial 

& Shipbuilding Co. oil palm trunks, empty fruit 

bunches, fibrous fruit wastes, 

kernel shells 

operations if 

ag. waste is 

successful 

Up until now, Japan has seen Brazil as the only possible reliable supplier of ethanol. In 

early 2005, Japan and Brazil signed an agreement for a bilateral biofuels program to export 

Brazilian ethanol and biodiesel to Japan. Japan’s investment will be used to install new ethanol 

facilities, increase acreage of sugarcane production, and modernize the infrastructure necessary 

for the transportation of ethanol. 

One such partnership is between Brazilian oil company (Petrobras) and trading house 

Mitsui & Co., with financial support from Japan Bank for International Cooperation are in the 

148
 
 

 

process of analyzing 40 projects evaluated at $8 billion for building 40 new processing plants 

which produce alcohol and sugar from sugar cane. According to Paulo Roberto Costa, head of 

Petrobras’ supply division, “Our target is to produce ethanol to be exported only to Japan.” 

Within two to three months (perhaps at the end of 2007) Petrobras will sign a pioneer contract to 

produce a total of 1 billion liters (264 million gallons) of alcohol annually at five processing 

plants in the states of Mato Grosso, Goias, and Minas Gerais. Each of the five processing plants 

will produce approximately 50 million gallons per year within the next 2 1⁄2 years, and the whole 

production will be exported to Japan. In order to help convince Japan that Petrobras has 

adequate ethanol supplies it has noted that their processing facilities will not be able to produce 

sugar, only alcohol.341 With this amount (264 million gallons) slated for Japan only, other 

countries will have to either develop their own contracts with Brazil to ensure a stable supply or 

risk receiving the leftover supply. 

Petrobras also recently bought a 90 percent stake in Exxon Mobil’s Okinawa oil refinery 

that may serve as a staging point for Brazilian ethanol exports to Japan and the rest of Asia. This 

may help mitigate one of the main problems for Petrobras and other major exporters, a lack of 

offloading infrastructure.342 

Another challenge is the distribution of ethanol in Japan. As ethanol in blends of E5 or 

higher have shown to be corrosive to aluminum and rubber car parts, Japan is looking into using 

ETBE blends of 7% and even 20-25% instead of ethanol.343 The Petroleum Association of Japan 

has announced that gasoline containing ETBE blends of 7% will be available for general public 

consumption by 2010. As ETBE is produced using ethanol as a feedstock, this could create a 

domestic ethanol demand of 90-100 million gallons.344 

1.5.2.1.4 India 

India has the potential to increase its ethanol production due to its long agricultural 

tradition. Unfortunately it is still in the very young stages of raising its biofuel industry, which 

leaves some analysts doubting this program’s stability.345 

Currently, India imports more than 70% of its energy needs. In addition to not being able 

to sustain its own current energy demands, the UN is predicting that India will become the most 

populated country by 2030 (surpassing China), and it will be consuming about a third of the 

world’s energy by 2050. 

The amount of ethanol blended into gasoline in India has fluctuated in recent years. In 

October 2004, ethanol blending in gasoline for example, had to be halted because of a lower 

sugar output due to a drought, which increased prices. However, production started back up in 

late 2005 when a fuller sugarcane molasses crop became available. Then in September 2006 the 

government announced the second phase of the EBP program that mandates 5% blending ethanol 

with gasoline in 20 states and eight union territories. The mandate was effective starting in 

November 2006 and would have required about 145 million gallons to be used. However, the 

program only started with 10 states and was not implemented in other states due to high state 

taxes, excise duties and levies. 

149
 
 

 

 

A recent USDA Attaché report estimated that only 66 million gallons of ethanol will be 

blended with gasoline in 2006/07, compared with the original target of 145 million gallons. The 

government plans to extend the ethanol blend ratio to 10% in a third stage once the program is 

extended to all target states. Some local sources report plans to introduce E-10 mandates in 

several cane-producing states such as Tamil Nadu, Andhra Pradesh, and Maharashtra.346 The 

original plan on a minimum of 10% blend of ethanol by October 2008, however, was put on hold 

because of the sharp fall in crude oil prices and because of technical concerns raised by the 

Society of Indian Automobile Manufacturers. The main concern is from vehicles with older 

engines that may not be able to use a 10% blend without engine modifications (e.g. twowheelers). Regardless, the government announced as part of its new biofuels policy to raise the 

blending level to 20% of total fuel usage by 2017 (includes biodiesel).347 

India has about 300 distillers with a production capacity of about 845 million gallons. 

Due to the government’s ethanol policy, over 110 distilleries have modified their plants to 

include an ethanol production line, with a total production capacity of 343 million gallons per 

year, enough to meet the estimated demand for E-5. For an E-10 mandate, however, the current 

ethanol production capacity would need to be enhanced. 

As of May 2006, India’s largest sugar and ethanol manufacturing company (Bajaj 

Hindusthan) is trying to acquire ethanol production plants in other countries with large sugarcane 

outputs (i.e. Brazil—but no concrete plans have been made). This way, the company can increase 

its production from 30.86 million gallons to 77.15 million gallons. Yet after several months of 

courting mill owners in Brazil, the company has not been able to come to any concrete 

agreements.348 

Some oil companies are instead pushing for imports of ethanol. However, as of today, 

there is still an import duty of 198.96% on the cif value for denatured and 59.08% for 

undenatured ethanol.349 The c.i.f. (cost, insurance, and freight) value represents the landed value 

of the merchandise at the first port of arrival in a given country. In comparison to the U.S. which 

has a tariff of 54 cents per gallon (with 45 cents per gallon offset by the ethanol subsidy) and a 

smaller ad valorem tax of 2.5% for denatured ethanol, import duties in India are much higher. 

The analysis of India’s biofuels developments appears to indicate that it will be selfsustaining if E5 is mandated (as noted by the sugar industry). However, as India strives to meet 

its E10 goal, it may need to rely on imports from other countries. As noted above, India’s own 

domestic production may grow from its current production of 66 million gallons of ethanol, with 

production capacity expanding to 343 million gallons per year. At E5 and E10 mandates, 

approximately 145 million gallons and 290 million gallons per year of ethanol, respectively, is 

required. Therefore, depending on the amount of ethanol that India chooses to mandate, India 

could either be an importer of 230 million gallons of ethanol or be able to meet its goals with 

domestically produced ethanol. 

150
 
 

 

 

1.5.2.1.5 China 

In 2007, China was the world’s fourth largest fuel ethanol producer, producing 486 

million gallons.350 Approximately 80% of fuel ethanol currently made in China is from corn.351 

Less than 20 percent of China’s corn crop is used for the industrial sector, and only 44.5 percent 

of that is put towards fuel ethanol.352 

China began mandating fuel ethanol blended into gasoline since June 2002. 353 In 2004, 

the Chinese government introduced an ethanol mandate of 10% ethanol blended in gasoline 

(E10) in several provinces (Helongjiang, Jilin, Liaoning, Henan, and Anhui). This mandate was 

further expanded to 27 cities in the provinces of Shandong, Jiangsu, Hebei, and Hubei in 2006. 

To keep up with fuel demand, a National Plan calls for fuel ethanol to rise from approximately 

330 million gallons of ethanol per year to 660 million gallons by 2010 and 3.3 billion gallons by 

2020.UU,354 

However, there have been recent concerns in China about the security of their food 

supply and the inflationary impact of biofuels which use grains as feedstock. With a population 

of 1.3 billion people, corn growers have to meet the demand for food (which might increase 

about 0.22 million tons) while also providing feedstock for fuel. In addition, they supply 

livestock feed for which demand is estimated to rise to roughly 100 million metric tons for 

2007.355 

In response to these food and feed demands for corn according to the National 

Development and Reform Commission (NDRC), China has stopped approvals for industrial corn 

processing for three years (until 2010) and has suspended approved projects which have not yet 

started construction.356 Over the next three years, corn consumption by the deep-processing 

sector (i.e. transformation of corn into industrial products like ethanol) will be restricted to 26 

percent of China's total corn consumption. 

The National Development and Reform Commission (NDRC) stated in their 11th Five 

Year Plan (2006-2010) that the production of approximately 2 billion gallons of grain-based 

ethanol will not threaten the country’s grain security. Currently, there are four fuel ethanol plants 

operating in the country which have a production capacity of approximately 300 million gallons 

(since 2005): Jilin Fuel Alcohol Company Ltd, Anhui Fengyuan Petrochemical Ltd, Henan 

Tianguan Group and the Heilongjiang Huarun Jinyu Ltd (China Resources).357,358 These plants 

were established after 2000 to address a surplus of grains in China at the time. Plans for ethanol 

plant expansions could reach up to approximately 550 million gallons of ethanol by 2007. These 

companies, as well as announced expansions are listed in the following Table 1.5-25. 

UU Assuming a conversion of 1 million tonnes of ethanol equals 330 million gallons. 

151
 
 

Table 1.5-25. Current and Future Fuel Ethanol Production in China359 

Province Company Name Feedstock 2005 Production (Gal) 2007 Production (Gal) 

Heilongjiang China Resources Alcohol Co. Corn 33,423,025 33,423,025 

Jilin Jilin Fuel Ethanol Co. Corn 100,269,074 200,538,149 

Henan Henan Tian Guan Fuel-Ethanol Co. Wheat 66,846,050 66,846,050 

Anhui Anhui BBCA Biochemical Co. Corn 106,953,679 106,953,679 

Guangxi China Resources Alcohol Co. Cassava 0 36,765,327 

Hebei China Resources Alcohol Co. Sweet potato, corn, etc. 0 76,872,957 

Hubei Tian Guan Fuel-Ethanol Co. Grains 0 33,423,025 

Total 307,491,828 554,822,211 

As seen in the above table, several distilleries have been looking into alternative 

feedstocks.360 Examples of alternative feedstocks include sorghum, wheat, cassava, and sweet 

potato. These crops, however, are grown in much smaller quantities as compared to corn, and if 

China ethanol production expands from cassava, for example, China will have to rely on 

imported cassava. 361 China may soon become a major importer of ethanol, especially if the E10 

blend is extended across the country. With a nationwide E10 blend in 2020, biofuels demand 

would be approximately 7.6 billion gallons of ethanol.362 Even if the National Plan which calls 

for China’s domestic fuel ethanol production to reach 3.3 billion gallons by 2020 is met, a 

nationwide E10 blend would result in a supply shortfall of about 4.3 billion gallons of ethanol.363 

Another study, the “World Biofuels: FAPRI 2007 Agricultural Outlook” also indicates that 

China would be a net importer of ethanol in the future (out to 2016), where domestic production 

only reaches approximately 1 billion gallons. In addition, if only food crops are assumed to be 

used to produce ethanol, China is estimated to only produce 0.6 billion gallons. 364 Assuming a 

possible E10 mandate nationwide and the projections for domestically produced ethanol, China 

would need to import approximately 4.3-7.0 billion gallons of ethanol per year. 

1.5.2.1.6 Other Countries 

Although Brazil is the largest exporter of ethanol, there may still be other countries that 

could provide additional ethanol to the U.S. In fact, trace amounts of ethanol entered the U.S. 

market from Argentina, Canada, Netherlands, and Pakistan in 2006.365 The North American 

Free Trade Agreement (NAFTA) is similar to the Caribbean Basin Initiative (CBI) in that it 

welcomes tariff-free ethanol imports from Canada and Mexico. 

In addition, there may also be other countries that are beginning biofuels programs and 

could demand smaller volumes of ethanol in the future. We provide a list of the potential 

mandates and goals for other countries below in Table 1.5-26. This list is not meant to be allinclusive, but rather to give idea of the biofuel outlook in other countries. 

152
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table 1.5-26 

Potential Mandates and Goals for Various Countries366,367,368,369,370,371 

Argentina Argentine President Nestor Kirchner signed a law in February 2007 implementing tax breaks and 

fuel-content mandates for biofuels. The Biofuels Act includes tax breaks for companies investing in 

the biofuels sector and mandates 5% ethanol in gasoline by 2010. The Secretary for Agriculture 

estimates that the country would need 200 million liters per year of ethanol (528,000 gallons) to 

satisfy the E5 requirements. 

Australia 

The Australian government has set a biofuels target of 93 Mgal by 2010 according to the 'Biofuels 

for Cleaner Transport' 2001 election policy. This target was never mandated in legislative form. 

Queensland- In early August 2006 a mandate for a minimum of 5% ethanol from December 21, 

2010. 

New South Wales (NSW)- Beginning in September 2007, fuel supplied to wholesalers in New South 

Wales will be required to contain 2% ethanol. Proponents of ethanol in the region want to increase 

the mandate to 4% in 2009 and 10% in 2010. 

Australian Capital Territory (ACT)- The ACT does not plan to mandate ethanol. Generally this 

territory follows the policies of NSW because most of their fuel supplies are sourced from NSW. 

Victoria- Biofuels target of 5% of fuel market by 2010 (106 Mgal), this includes biodiesel. 

South Australia- No plans to mandate of set a target for biofuels use. 

Northern Territory- No plans to mandate or set a target for biofuels known. 

Western Australia- No plans to mandate or set a target for biofuels known. 

Tasmania- The alternative fuels policy is currently based on CNG use. 

No plans to mandate or set a target for biofuels known. 

Canada On June 26, 2008, the Canadian Senate passed Bill C-33, which will require the use of 5% 

renewable content in gasoline by 2010. Canada's Government General Michaelle Jean signed the 

bill after it was passed in the senate, making it official. 

Saskatchewan- Enacted in October 2006 a 7.5% ethanol mandate in gasoline (approximately 131 

Mgal) 

Ontario- Enacted in January 2007 a 5% ethanol mandate in gasoline 

British Columbia- Bill C-16 to pass soon, 5% ethanol by 2010 to support federal plan 

Alberta- Has not set its own standard as it prefers a national approach 

Manitoba- As of Jan. 1, 2008, 8.5% in gasoline (approximately 130 Mgal) 

Quebec- 5% ethanol in gasoline by 2012, expects source to be met with cellulosic ethanol 

production 

Nova Scotia- No goals for biofuels 

New Brunswick- No goals for biofuels 

Newfoundland Labrador,PIE- Interest on the East Coast, but nothing as of May 2008 

North West Territories, Yukon, Nunavut- No goals for biofuels 

Columbia In September 2001, the Colombian Government issued Law 693, which made it mandatory to use 

10% ethanol blends in gasoline in cities with populations larger than 500,000 inhabitants by the year 

2008. The law went into effect in September 2005. Ethanol production, however, could not cover 

the entire country's demand, and thus the government established a phase-in period throughout the 

country for mandatory ethanol use. 

Mexico There is currently no specific bio-fuels promotion program operation in Mexico. On April 26, 2007, 

the Mexican congress approved the Law for Promotion and Development of Biofuels (LPBD). The 

law, though lacking in any actual mandates, sets the state for further legislative actions on biofuels 

development and use. 

1.5.2.1.7 Summary of Potential Import/Export Demands 

For the main countries we have analyzed from above, there appears to be a large potential 

demand from the EU, Japan, India, and China for imported ethanol. See Table 1.5-27 for a 

summary of potential import demand by 2020/2022. Total import potential demand from all 

these countries would range from approximately 5-15 billion gallons. If these countries decide 

to meet their mandated ethanol blends or enact new mandates, this could greatly increase the 

amount that each country would demand from other countries, primarily from Brazil. As shown 

in Section 1.5.2.1.1, Brazil is only expected to export 3.8-4.2 billion gallons by 2022. This is 

significantly below the volume we estimated that could be potentially demanded by other 

153
 
 

countries in the future. Therefore, it is likely that unless Brazil increases production much more 

than its government projects, the EU, Japan, India, and China will not be able to meet their stated 

goals. This also indicates that the U.S. will likely compete with other foreign countries for 

exports from Brazil. This analysis, however, only considers non-cellulosic biofuel potential. If 

cellulosic biofuel production develops in these countries, it is entirely possible that the biofuel 

demands could be lower due to greater supplies. 

Table 1.5-27. Potential Import Demand: 

EU, Japan, India, and China by 2020/2022 (billion gallons).VV
 

Country EU Japan India China Total 

Potential Domestic Production 

(non-cellulosic) 1.5-5.0 0-0.1 0.1-0.3 0.6-3.3
 

Potential Domestic Consumption
 

Petrobras Contract n/a 0.3 n/a n/a
 

E3 n/a 0.5 n/a n/a
 

E5 n/a n/a 0.1 n/a
 

E10 (or 10% by energy for EU) 5.2-7.3 1.6 0.3 7.6
 

7% ETBE n/a 0.1 n/a n/a
 

Potential Import Demand 0.2-5.8 0.1-1.6 0-0.2 4.3-7.0 4.6-14.6 

1.5.2.1.8 Potential for U.S. Ethanol Exports 

Ethanol exports in the U.S. have averaged only approximately 100 million gallons per 

year since 2000, mostly to Canada, Mexico, and the E.U. See Figure 1.5-13. There is a trend 

over the past five years of exporting larger quantities to fewer countries, with declining volumes 

to Asia and increasing volumes to the E.U. and India. Based on this historical data, it does not 

seem likely that volume of ethanol exports will change drastically in the future. 

VV Ranges are calculated assuming the potential values for production and consumption 

154
 
 

0 

20 

40 

60 

80 

100 

120 

140 

Million Gallons 

Others 

Mexico 

India 

Canada 

Japan 

EU 

Figure 1.5-13. 

U.S. Ethanol Exports (includes hydrous, dehydrated, and denatured volumes).372 

2001 2002 2003 2004 2005 

1.5.2.2 Projected Growth Under RFS2 

As long as imported ethanol is cost-competitive with gasoline, there will continue be a 

demand for it. As our analysis from above shows, Brazil is the only country that will likely be 

able to provide a significant volume of ethanol to the U.S. Accordingly, Brazil will ship ethanol 

to countries via the most cost-effective way. 

The pathway Brazil chooses to ship ethanol will likely depend on the tariffs and taxes put 

in place by other nations. Specifically, the U.S. places a 54 cent tariff on all imported ethanol (as 

well as a 2.5 percent ad valorem tax for un-denatured ethanol and a 1.9 percent tax for denatured 

ethanol). A key reason for establishing a tariff was to offset a tax incentive for ethanol-blended 

gasoline, which is set at 45 cents per gallon of pure ethanol.WW This analysis assumes that both 

the tax subsidy and the tariff will continue in the future. 

The tariff can be avoided by first shipping ethanol to countries under the Caribbean Basin 

Initiative (CBI) and then to the U.S. Historically, the majority of CBI ethanol to the U.S. comes 

from dehydrating ethanol from Brazil. Legislation and agreements since the 1980s have waived 

or significantly reduced the tariff on imports from Canada, Mexico, and those nations covered 

under the CBI. There are currently nineteen countries that can benefit from the CBI program. 

These countries are: Antigua and Barbuda, Aruba, Bahamas, Barbados, Belize, British Virgin 

WW Prior to the 2008 Farm Bill, the tax incentive was set at 54 cents per gallon 

155
 
 

 

Islands, Costa Rica, Dominica, Grenada, Guyana, Haiti, Jamaica, Montserrat, Netherlands 

Antilles, Panama, St. Kitts and Nevis, St. Lucia, St. Vincent and the Grenadines, and Trinidad 

and Tobago.373 

Under the Caribbean Basin Economic Recovery Act (CBERA), which created the CBI, 

countries in Central America and the Caribbean have had duty-free access to the United States 

since 1989 for ethanol produced from regional feedstocks. Although most analysts believe there 

is sufficient land available for sugar cane production in some CBI nations, there has been 

insufficient economic potential to spur sugar cane planting for ethanol production.374 Ethanol 

derived from non-regional feedstocks has been limited to 7 percent of total U.S. ethanol 

consumption (based on figures from the previous year). There are also country-specific 

allocations for El Salvador (5.2 million gallons in first year (2006) and an annual increase of 1.3 

million gallons per year, not to exceed 10% of CBI quota) and Costa Rica (31 million gallons 

annually) established by the U.S. Free Trade Agreement with Central America and the 

Dominican Republic (CAFTA-DR).375 Thus far, Costa Rica, El Salvador, Jamaica, Trinidad and 

Tobago, and the U.S. Virgin Islands (since 2007) are the only countries that have ever exported 

ethanol to the U.S. under the CBI quota. 

Historically, the CBI nations have had little ethanol production capacity of their own but 

have supplemented it by importing hydrous Brazilian ethanol where it is further dehydrated 

before being re-exported to the U.S. duty-free. CBI countries have also relied on surplus wine 

alcohol from France, Italy, Spain and other Mediterranean countries in the past.376 According to 

the United States International Trade Commission, the majority of fuel ethanol imports to the 

United States came through CBI countries between 1996 and 2003. Although CBI ethanol 

imports to the U.S. in 2006 totaled over 170 million gallons, imports to the U.S. from Brazil 

totaled 3 times that amount, or approximately 430 million gallons. This data indicates that in 

2006 it was economical to import significant quantities of ethanol directly from other nations due 

to the withdrawal of MTBE and high oil prices. However, it is not clear on how much of this 

volume the tariff was paid, as there have been other means for importers to avoid the tariff. 

In the past, companies have also imported ethanol from Brazil through a duty 

drawback.377 The drawback is a loophole in the tax rules which allowed companies to import 

ethanol and then receive a rebate on taxes paid on the ethanol when jet fuel is sold for export 

within three years. The drawback considered ethanol and jet fuel as similar commodities 

(finished petroleum derivatives).378,379 Most recently, however, Senate Representative Charles 

Grassley from Iowa included a provision into the 2008 Farm bill that ended such refunds. The 

provision states that “any duty paid under subheading 9901.00.50 of the Harmonized Tariff 

Schedule of the United States on imports of ethyl alcohol or a mixture of ethyl alcohol may not 

be refunded if the exported article upon which a drawback claim is based does not contain ethyl 

alcohol or a mixture of ethyl alcohol.”380 The provision became effective on or after October 1, 

2008 and companies have until October 1, 2010 to apply for a duty drawback on prior 

transactions. With the loophole closed, it is anticipated that there may be less ethanol directly 

exported from Brazil in the future.381 

CBI countries have not yet exceeded the tariff rate quotas (TRQs) for ethanol imports. 

The TRQ has been limited to 7 percent of total U.S. ethanol consumption (based on figures from 

156
 
the previous year). The fill rate, or percent of the TRQ used, has ranged from 22-77% between 

1990 and 2008. See Figure 1.5-14. Thus, there is still considerable room for growth in CBI 

imported ethanol. 

Figure 1.5-14. U.S. Fuel Ethanol CBERA TRQ, 1990-2009 

0 

100 

200 

300 

400 

500 

600 

700 

Million Gallons 

TRQ Used TRQ Available 

1990199219941996199820002002200420062008

*TRQ Used data for 2009 is not yet available. 

In October 2003, the California Energy Commission (CEC) reported four active CBI 

ethanol dehydration plants, two in Jamaica, one in Costa Rica, and one in El Salvador. At the 

time, CEC concluded that reprocessing capacity was the limiting factor on CBI imports, with a 

total of 90 million gallons per year.382 Since then, several companies have expanded plants or 

announced new plants as described below: 

•	 Jamaica- In 2005, Petrojam Ethanol Limited (PEL), upgraded and expanded their ethanol 

dehydration plant in Jamaica to a capacity of 40 million US gallons. Currently, the 

production of anhydrous (fuel grade) ethanol at the plant is based on a marketing 

agreement with the Brazilian company, Coimex Trading, where the feedstock - hydrous 

ethanol is supplied from Brazil. 

383,384 Jamaica Broilers Group (JBG) launched fuel 

ethanol production at its 60 million gallon dehydration plant this year. The first shipment 

of 5.5 million gallons of ethanol , which arrived in June 2007, will be converted to 

anhydrous ethanol for export to the U.S. JBG has a deal with Bauche Energy for the 

supply of 50 million gallons of hydrous ethanol out of Brazil for the first year of 

operation.385 Jamaica Ethanol Processing Ltd, which is ED & F Man’s subsidiary on the 

island, has a small plant that dehydrates ethanol from Brazil at a capacity of 55 million 

gallons. 

157
 
 

 

 

 

•	 Costa Rica- LAICA (cane co-op) has a plant currently dehydrating ethanol at 38 million 

gallons.386 

•	 El Salvador and Panama- In 2004, it was reported that Cargill and Chevron Texaco had 

announced plans to construct new dehydration plants in El Salvador and Panama. These 

plants could produce 60 million gallons per year and between 50 and 100 million gallons 

per year, respectively.387 Plants currently in operation include Gasohol de El Salvador 

(Liza/Vitol) at 100 million gallons per year and ARFS (CASA/Cargill/Crystalsev) at 60 

million gallons per year.388 

•	 Trinidad- EthylChem Inc. has reported plans to build an ethanol dehydration operation at 

the Petrotrin Refinery in Point-a-Pierre, a southern port city in Trinidad. The plant will 

dehydrate ethanol at a capacity of 100 million gallons per year and is expected to be 

complete between March and April of 2007.389 The cost to build the plant is estimated at 

$20 million.390 It is probable, however, that not all the ethanol would be exclusively for 

U.S. consumption. According to Ron White, the executive director of Ethylchem, "While 

EthylChem intends to export the fuel to the United States the company is examining the 

possibility of shipping the product to other markets in the world".391 Another company, 

Angostura Ltd., started processing ethanol in 2005.392 The plant has an overall capacity 

of 100 million gallons per year, with 50 million gallons per year in the first phase.393 

•	 Others- An idled ethanol plant in Haiti has attracted some investors and there are also 

projects in the works in Guyana, the Dominican Republic and Aruba. The U.S. Virgin 

Islands has one plant dehydrating ethanol at 100 million gallons per year capacity 

(Geonet).394 A new ethanol dehydration plant is proposed to be built at the Bulk Terminal 

Facility near Spring Garden Highway in Barbados, with construction expected to 

commence by the end of 2008.395 There is a proposal to build a US$36 million ethanol 

plant near Bridgetown, Barbados. The plant is expected to produce about 132 million 

gallons by refining ethanol imported from Brazil.396 

In total, current fuel ethanol plant capacity for dehydration in the Caribbean is 500 

million gallons per year. Plans to expand total approximately 200 million gallons.397 This 

means that there could be 700 million gallons per year of fuel ethanol capacity in the next few 

years. 

Some stakeholders, however, have expressed concern that the CBI countries are not as 

stable for investment. Both Brazilian ethanol and European wine alcohol are susceptible to 

factors including availability, price fluctuations, trade regulations, currency movements and 

freight rates. Availability of European surplus wine alcohol has diminished since the World 

Trade Organization (WTO) placed limitations on export subsidies and has found new markets in 

Spain and Sweden.398 CBI countries also need to compete for Brazilian ethanol. For example, 

Angostura’s ethanol subsidiary, Trinidad Bulk Traders Ltd., wasn’t profitable in 2006 because it 

could not get enough fuel from Brazil.399 

There are other prohibitive factors to CBI ethanol production that exist. For instance, 

many of the CBI countries have no oil, natural gas or coal. Permitting is often a huge challenge 

and fresh water is typically scarce.400 

158
 
 

 

In addition, increasing significantly beyond the 7% limit may be challenging. Few 

Caribbean countries are in any position to produce ethanol from domestic feedstocks such as 

sugar cane. Currently, all three plants exist in Central America (CATSA in Costa Rica, Pantleon 

Group in Guatemala, and Pellas Group in Nicaragua). Capacity for each plant is approximately 

10 million gallons per year. The majority of this domestic fuel ethanol is shipped to the EU for 

fuel use rather than US due to higher opportunity prices and similar tariff free treatment.401 In 

addition, the governments of Trinidad, St. Kitts and Barbados have already decided the sugar 

sectors of their islands are not worth further investment. Rum distillers such as Trinidad’s 

Angostura and Jamaica’s Appleton Ltd. have also had to import molasses from Fiji for their 

spirits.402 Thus, it may take years before Caribbean countries are able to domestically produce 

large volumes of ethanol. As noted above, however, as dehydration capacity gets close to the US 

CBI quota, processors will need to consider blending indigenous ethanol. 

As a result of the economic benefit of shipping ethanol through CBI nations, we 

anticipate that the majority of the TRQ will be met in the future. If we assume that 90 percent of 

the TRQ is met and that total domestic ethanol (corn and cellulosic ethanol) consumed in the 

prior year was 28.5 Bgal, then approximately 1.8 Bgal of ethanol could enter the U.S. through 

CBI countries.XX Brazilian ethanol exports not entering the CBI will compete on the open 

market with the rest of the world demanding some portion of direct Brazilian ethanol. We 

calculated the amount of direct Brazilian ethanol exported in 2022 to the U.S. as the total 

imported ethanol required to meet the Act subtracted by imported ethanol from CBI countries 

(e.g. 3.14 Bgal of imported ethanol is required to meet EISA in 2022, while 1.8 Bgal can enter 

CBI due to the TRQ limit, thus leaving 1.34 Bgal needed directly from Brazil). The total 

imported ethanol required by the Act was projected for each year based on the required volumes 

needed to meet the advanced biofuel standard after accounting for the volumes from cellulosic 

biofuel, biodiesel, and renewable diesel. See Table 1.5-28. 

Table 1.5-28. 

Projected Contribution of Ethanol from CBI Countries and 

Direct Brazilian exports in 2022 (billion gallons) 

Ethanol 

From CBI 

Countries 

Ethanol 

Directly 

From Brazil 

Total 

Imported 

Ethanol 

1.80 1.34 3.14 

The amount of Brazilian ethanol available for direct shipment to the U.S. will be 

dependent on the biofuels mandates and goals set by other foreign countries (i.e., the EU, Japan, 

India, and China). Our estimates show that there could be a potential demand for imported 

ethanol of 4.6-14.6 billion gallons by 2020/2022 from these countries as noted in Section 

1.5.2.1.7. This is due to the fact that some countries are unable to produce large volumes of 

ethanol because of e.g. land constraints or low production capacity. Therefore, unless Brazil 

increases production much more than its government projects there may be a limited supply for 

imported ethanol to satisfy all foreign country mandates and goals. 

XX Total Domestic Ethanol is based on the amount needed to meet EISA (i.e. for 2021: 15 Bgal Corn Ethanol, 13.5 

Bgal Cellulosic Ethanol; for 2022: 15 Bgal Corn Ethanol, 16 Bgal Cellulosic Ethanol). 

159
 
 

 

 

1.5.2.2.1 Origin of Projected Imports 

A summary of our projections of the breakdown of ethanol imports that would come 

directly from the Brazil versus that which would come through the CBI countries is contained in 

Table 1.5-19. To estimate the future breakdown of ethanol imports from CBI countries by 

country of origin, we evaluated historical ethanol import data from the International Trade 

Commission (ITC) and trends regarding potential growth in such imports. Table 1.5-29 contains 

2005-2007 data from the ITC on ethanol imports from CBI countries.403 Table 1.5-30 contains 

January – March 2008 data from the ITC on ethanol imports from CBI countries.404 

Table 1.5-29. Ethanol Imports from CBI Countries 2005-2007 

2005 2006 2007 

% of CBI 

imports 

Volume 

(Million 

Gallons) 

% of CBI 

imports 

Volume 

(Million 

Gallons) 

% of CBI 

imports 

Volume 

(Million 

Gallons) 

Costa Rica 32% 33.4 22% 35.9 17% 39.3 

El Salvador 23% 23.7 23% 38.5 32% 73.3 

Jamaica 35% 36.3 40% 66.8 33% 75.2 

Trinidad 

and Tobago 

10% 10 15% 24.8 19% 42.7 

Source: International Trade Commission 

Table 1.5-30. Ethanol Imports from CBI Countries, January through March 2008 

January February March 

% of CBI 

imports 

Volume 

(Million 

Gallons) 

% of CBI 

imports 

Volume 

(Million 

Gallons) 

% of CBI 

imports 

Volume 

(Million 

Gallons) 

Costa Rica 26% 5.4 27% 5.4 0 0 

El Salvador 13% 2.6 0 0 23% 4.6 

Jamaica 19% 4.0 32% 6.4 39% 7.9 

Trinidad 

and Tobago 

20% 4.1 21% 4.2 29% 6 

Virgin 

Islands 

22% 4.6 21% 4.2 9% 1.9 

Source: International Trade Commission 

Based on our review of the January through March 2008 data, we assumed that ethanol 

exports from the Virgin Islands would continue to grow to equal those of Trinidad and Tobago in 

2022. By accommodating this assumption into our review of 2005 though 2007 historical 

ethanol import data, we arrived at our projections regarding the future breakdown of ethanol 

imports from CBI countries which is contained in Table 1.5-31. 

160
 
 

Table 1.5-31. 

Projected Future Breakdown of 

Ethanol Imports from CBI Countries
 

% of Total Ethanol Imports from 

CBI Countries 

Costa Rica 

El Salvador 

Jamaica 

Trinidad and Tobago 

Virgin Islands 

20% 

20% 

30% 

15% 

15% 

1.5.2.2.2 Destination of Projected Imports 

For our distribution and air quality analyses, we had to make a determination as to where 

the projected imported ethanol would likely enter the United States. As mentioned above, we 

started by looking at historical ethanol import data and made assumptions as to which countries 

would likely contribute to the CBI ethanol volumes in Table 1.5-19, and to what extent (see 

Table 1.5-22). 

From there, we looked at 2006-2007 import data and estimated the general destination of 

Brazilian ethanol and the five contributing CBI countries’ domestic imports.405 Based on these 

countries’ geographic locations and import histories, we estimated that in 2022 82% of the 

ethanol would be imported to the East and Gulf Coasts and the remaining 18% would go to the 

West Coast and Hawaii. The destination of imports from Brazil and the CBI countries in 2022 is 

detailed in Table 1.5-32. 

Table 1.5-32. 

2022 Projected Destination of Ethanol Imports from Brazil 

and CBI Countries Based on 2006-2007 Import Data
 

Origin Destination of Ethanol Imports (% of imported volume) 

West Coast Hawaii East & Gulf Coasts 

Costa Rica 83% 35% 47% 

El Salvador 18% 9% 88% 

Jamaica 3% 0% 17% 

Trinidad & Tobago 0% 32% 68% 

Virgin Islands 3% 9% 88% 

Brazil (direct) 7% 0% 93% 

Total 11% 7% 82% 

Source: Energy Information Administration historical gasoline and ethanol import data: 

http://www.eia.doe.gov/oil_gas/petroleum/data_publications/company_level_imports/cli_historical.html 

To estimate the 2022 ethanol import locations on a finer level, we looked at coastal ports 

that had received ethanol or finished gasoline imports in 2006. We chose to include ports which 

imported finished gasoline (in addition to ethanol) because we believe finished gasoline will be 

one of the first petroleum products to be replaced under the proposed RFS2 rule. And 

161
 
 

 

presumably, these ports cities already have existing gasoline storage tanks that could be 

retrofitted to accommodate fuel ethanol. All together, we arrived at 28 potential ports in 16 

coastal states that could receive ethanol imports in 2022 (refer to Figure 1.5-14 below).YY 

To determine how much ethanol would arrive at each port location, we started by 

examining each receiving state’s imported ethanol consumption potential. To do this, we 

considered each state’s maximum ethanol consumption potential (based on projected gasoline 

energy demand) and deducted the projected 2022 corn and cellulosic ethanol production 

(detailed in Sections 1.5.1.2 and 1.5.3.4, respectively). While we are not concluding that each 

state would necessarily consume all the ethanol it produces, we believe this serves as an 

appropriate assumption in determining each port state’s relative imported ethanol consumption 

potential. Once we determined the amount of imported ethanol that each state would receive in 

2022 under RFS2, for states with multiple ethanol ports, we allocated the ethanol among port 

locations based on each port county’s relative energy demand - using projected 2022 vehicle 

miles traveled (VMT) from EPA’s MOVES model 2022 VMT. A summary of the projected 

ethanol imports volumes by port location is found in Figure 1.5-15. 

YY We are considering adding Hampton Roads, VA and Baltimore, MD to the list of future ethanol import locations 

and may adjust our analysis for the final rule accordingly. 

162
 
 

Figure 1.5-15. 

Projected RFS2 Ethanol Import Locations and Volumes (Million Gallons)ZZ
 

1.5.3 Cellulosic Biofuel 

In this subsection, we will discuss the state of the evolving cellulosic biofuel industry. 

The bulk of this discussion focuses on the cellulosic ethanol industry since it is the cellulosic 

biofuel we assumed for our RFS2 volume and impact analyses. However, as discussed in 

Section 1.2.1 (and throughout this package) cellulosic diesel could also count towards meeting 

the 16 billion gallon cellulosic biofuel standard. We are becoming aware of more and more 

companies pursuing plans to produce diesel through Fischer-Tropsch gasification of biomass as 

well as thermal, thermochemical, and biological depolymerization of biomass to produce 

synthetic diesel fuel. We plan on doing a more robust assessment of these companies and 

technologies for the final rulemaking. In the meantime, a discussion of the cellulosic diesel 

production plans we are aware of is provided in Section 1.5.3.3. For more on the cellulosic 

biofuel conversion technologies mentioned in this section, refer to Section 1.4.3. Finally, we 

end this section with a discussion of how the nation is on track for meeting the 2010 cellulsic 

biofuel standard and where more commercial-level plants might be located in 2022 based on 

feedstock availability. 

ZZ We are considering adding Hampton Roads, VA and Baltimore, MD to the list of future ethanol import locations 

and may adjust our analysis for the final rule accordingly. 

163
 
 

 

1.5.3.1 Cellulosic Ethanol Production/Plans 

Presently, all commercial-level ethanol produced in the U.S. comes from plants 

processing corn and other grains or starches. However, cellulosic feedstocks have the potential 

to greatly expand domestic ethanol production, both volumetrically and geographically. Before 

the fuel can be economically produced at commercial levels in today’s marketplace, technical 

and logistical barriers must be overcome. In addition to today’s RFS2 program which sets 

aggressive goals for all ethanol production, the Department of Energy (DOE) and other federal 

and state agencies are helping to spur industry growth. 

The cellulosic ethanol industry is essentially in its infancy. No commercial-scale plants 

are currently operating in the U.S. However, numerous state and federal agencies, national 

laboratories, universities, and private companies are working towards making cellulosic ethanol 

commercially viable. These organizations are pursuing second-generation conversion 

technologies and experimenting with a variety of feedstocks. Some researchers are focusing on 

processing corn residues, e.g., corn stover, cobs, and/or fiber. Some are focusing on other 

agricultural residues such as sugarcane bagasse, rice, and wheat straw. Others are looking at 

waste products such as forestry residues, citrus residues, pulp or paper mill waste, municipal 

solid waste (MSW), and construction and demolition (C&D) debris. Dedicated energy crops 

including switchgrass and poplar trees are also being investigated. 

The majority of the groups pursuing cellulosic ethanol production are currently 

conducting laboratory research or experimenting with pilot- or demonstration-level production. 

Based on an April 2009 assessment of information available on the public domain, there are 

presently 25 small cellulosic ethanol plants operating in the United States.AAA Most of these 

facilities operate intermittently and produce insignificant volumes of ethanol. A list of these 

facilities and their locations, feedstocks, ethanol production capacities (if applicable/available), 

estimated operation dates, and technologies is provided in Table 1.5-33. The date listed in the 

table indicates when the facility first began operations. 

AAA Our April 2009 cellulosic ethanol industry assessment was based on researching DOE- and USDA-supported 

projects, plants referenced in HART’s Ethanol & Biodiesel News (through the April 14, 2009 issue), plants included 

on the Cellulosic Ethanol Site (http://www.thecesite.com/), and plants referenced on other biofuel industry websites. 

164
 
165 

Table 1.5-33. 

Operational Pilot- and Demonstration-Scale Cellulosic Ethanol Plants
 

Company or Organization Name Location Feedstocks 

Prod Ca

(MGY) 

Abengoa Bioenergy Corporationb York, NE Wheat straw, corn stover, energy crops 0.02 

AE Biofuelsb Butte, MT Switchgrass, small-grain straw, corn stover N/A 

Arkenol Technology Center Orange, CA Biomass N/A 

Auburn University / Masada Resources Groupc Auburn, AL Wood N/A 

Bioengineering Resources, Inc. (BRI) Fayetteville, AK MSW, wood waste, coal 0.04 BPI & Universal Entech Phoenix, AZ Paper waste (sorted MSW) 0.01 

Chemrec & Weyerhaeuser New Bern, NC Paper mill waste N/A 

ClearFuels Technology / Hawaii Natural Energy Institute Kauai, HI Sugarcane bagasse N/A 

Cornell University’s Biofuels Research Laboratory (BRL) Ithaca, NY Perennial grasses, woody biomass N/A 

Coskata Warrenville, IL Reformed natural gas, biomass N/A 

DOE National Renewable Energy Laboratory (NREL) Golden, CO Corn stover, other biomass N/A 

Gulf Coast Energy Livingston, AL Wood waste (sorted MSW) 0.20 Mascoma Corporation Rome, NY Wood chips 0.20 Novozymes Franklinton, NC Corn stover N/A Pan Gen Global (formerly Colusa Biomass) Colusa County, CA Rice straw & hulls N/A Pearson Technologies Inc. (PTI) Aberdeen, MS Wood residues, rice straw N/A POET Research Centerb Scotland, SD Corn cobs & fiber N/A 

POET Project Bellb Scotland, SD Corn cobs & fiber 0.02 PureVision Technology, Inc. Fort Lupton, CO Corn stover, wood, sugarcane bagasse N/A 

PureVision Technology, Inc. Fort Lupton, CO Corn stover, wood, sugarcane bagasse N/A Range Fuels Broomfield, CO Wood waste N/A USDA Citrus & Subtropical Products Laboratory Winter Haven, FL Citrus residues N/A 

Verenium Jennings, LA Sugarcane bagasse 0.05 

Verenium Jennings, LA Sugarcane bagasse, wood, energycane 1.50 Western Biomass Energy, LLC. (WBE) Upton, WY Wood waste (softwood) 1.50 

Total Existing Production Capacity >3.5 MG

aBio = biochemical cellulosic ethanol technology, Therm = thermochemical cellulosic ethanol technology, Both = investigating both technologies. bCellulosic pilot plant is collocated with a corn ethanol plant. cIn December of 2007, Masada donated the Tennessee Valley Authority's biomass pilot plant facilities and equipment in Muscle Shoals, AL to Auburn Uni
166 

 

 

As shown in Table 1.5-33, today’s cellulosic ethanol plants are run by a combination of 

academic, government, and private organizations. Some of the privately-owned companies are 

existing corn ethanol producers, but the majority are start-up companies entering the ethanol 

industry for the first time. Verenium Corp. received a $10 million grant from DOE to help build 

their demonstration-level plant in Jennings, LA that just recently came online. 

To date, the majority of cellulosic ethanol research has focused on biochemical pretreatment technologies, i.e., the use of acids and/or enzymes to break down cellulosic materials 

into fermentable sugars. However, there are a growing number of companies investigating 

thermochemical conversion which involves gasification of biomass into a synthesis gas or 

pyrolysis of biomass into a bio-crude oil for processing. Cellulosic diesel, a diesel fuel 

replacement discussed more in Section 1.5.3.3, can also be made from thermochemical 

conversion processes. Many companies are also researching the potential of co-firing biomass to 

produce plant energy in addition to biofuels. For more on the biofuel processing technologies, 

refer to Section 1.4.3 

In addition to the 25 existing facilities, three additional cellulosic ethanol plants are 

currently under construction in the United States. Like the existing plants, two are pilot-level 

facilities that are still working towards proving their conversion technologies. However, Range 

Fuels, a company that received $76 million from DOE and an $80 loan guarantee from USDA 

funding to build one of the first commercial-scale cellulosic ethanol plants in the U.S., is 

currently building a 40 million gallon per year plant in Soperton, GA.BBB At this time, the 

company is just working on the initial 10 million gallon per year phase). A summary of the 

cellulosic ethanol plants currently under construction in the U.S., is presented in Table 1.5-34. 

As shown in Tables 1.5-33 and 1.5-34, unlike corn ethanol production, which is primarily 

located in the Midwest near the Corn Belt, cellulosic ethanol production is spread throughout the 

country. The geographic distribution of plants is due to the wide variety and availability of 

cellulosic feedstocks. Corn stover is found primarily in the Midwest, while the Pacific 

Northwest, the Northeast, and the Southeast all have forestry residues. Some southern states have 

access to sugarcane bagasse and citrus waste while MSW and C&D debris are available in highly 

populated areas throughout the country. For more information on cellulosic feedstock 

availability, refer to Section 1.1.2. 

BBB Range Fuels’ ultimate goal is to expand the Soperton, GA facility to produce 100 million gallons of cellulosic 

ethanol per year. 
167 

Table 1.5-34. 

Small-Scale Cellulosic Ethanol Plants Currently Under Construction
 

Company/Plant Name Location Feedstocks 

Prod Ca

(MGY

Coskata DuPont Dansico Cellulosic Ethanol (DDCE) Range Fuels 

Madison, PA 

Vonore, TN 

Soperton, GA 

MSW, natural gas, woodchips, bagasse, switchgrass 

Corn cobs then switchgrass 

Wood waste, switchgrass 

0.04 0.25 

10.00 

Total Under Construction Production Capacity >10 MG

aBio = biochemical cellulosic ethanol technology, Therm = thermochemical cellulosic ethanol technology. 
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168 
169 

 

Increased public interest, government support, technological advancement, and the 

recently-enacted EISA have helped spur many plans for new cellulosic biofuel plants. Although 

more and more plants are being announced, most are limited in size and contingent upon 

technology breakthroughs and efficiency improvements at the pilot and demonstration level. 

Additionally, because cellulosic biofuel production has not yet been proven on a commercial 

level, financing of these projects has primarily been through venture capital and similar funding 

mechanisms, as opposed to conventional bank loans. 

Consequently, recently-announced Federal grant and loan guarantee programs may serve 

as a significant asset to the cellulosic biofuel industry in this area. In February 2007, DOE 

announced that it would invest up to $385 million in six commercial-scale ethanol projects over 

the next four years.406 Since the announcement, two of the companies have forfeited their 

funding. Iogen has decided to locate its first commercial-scale plant in Canada and Alico has 

discontinued plans to build an ethanol plant all together. The four remaining “pioneer” plants 

(including Range Fuels) hold promise and could very well be some of the first plants to 

demonstrate the commercial-scale viability of cellulosic biofuel production. However, there is 

still more to be learned at the pilot level. Although technologies needed to convert cellulosic 

feedstocks into ethanol (and diesel) are becoming more and more understood, there are still a 

number of efficiency improvements that need to occur before cellulosic biofuel production can 

compete in today’s marketplace. 

In May 2007, DOE announced that it would provide up to $200 million to help fund 

small-scale cellulosic biorefineries experimenting with novel processing technologies that could 

later be expanded to commercial production facilities.407 Four recipients were announced in 

January 2008 and three more were announced in April 2008.408,409 Three months later, DOE 

announced that it would provide $40 million more to help fund two additional small-scale 

plants.410 Of the nine total small-scale plants, seven were pursuing cellulosic ethanol production 

(including Verenium Corp.) and two were planning on producing cellulosic diesel. However, 

Lignol Innovations, recently suspended plans to build a 2.5 million gallon per year ethanol plant 

in Grand Junction, CO due to market uncertainty. 

The Department of Energy has also introduced a loan guarantee program to help reduce 

risk and spur investment in projects that employ new, clean energy technologies. In October 

2007, DOE issued final regulations and invited 16 project sponsors who submitted preapplications to submit full applications for loan guarantees.411 Of those who were invited to 

participate, five were pursuing cellulosic biofuel production. However, only three of the 

companies appear to still be eligible.CCC Of the three remaining companies, two are pursuing 

cellulosic ethanol production (and are also DOE grant recipients) and one is pursuing cellulosic 

diesel production. The U.S. Department of Agriculture is also providing an $80 million loan 

guarantee to Range Fuels to help support commercialization of cellulosic ethanol. For a list of 

the cellulosic biofuel projects receiving DOE grants and/or loan guarantees that are still on the 

table, refer to Table 1.5-35. For more information on the cellulosic diesel companies listed in this 

table, and other privately funded plants and proposed projects, refer to Section 1.5.3.2. 

CCC Iogen and Alico have also forfeited potential loan guarantees from DOE. 
170 

Table 1.5-35. 

Cellulosic Biofuel Plants Receiving DOE or USDA SupportDDD
 

Company/Plant Name Location Feedstocks 

Prod Cap 

(MGY) 

Est. Op. 

Datea 

Conv

Tech

Cellulosic Ethanol Abengoa Bioenergy Corp.c Hugoton, KS Corn stover, wheat straw, milo stubble, switchgrass 11.4 2012 Bio 

BlueFire Mecca, LLC. El Sobrante, CA Woodchips, grass cuttings, and other yard waste 17.0 TBD Bio 

Ecofin / Alltech Springfield, KY Corn cobs 1.3 2010 Bio 

ICM Inc.c St. Joseph, MO Corn fiber/stover, sorghum, switchgrass 1.5 2010 Bio 

Mascoma Corporation Kinross, MId Wood fiber 40.0 2012 Bio 

Pacific Ethanolc Boardman , OR Wheat straw, wood chips, corn stover 2.7 TBD Bio 

POET Project Libertyc Emmetsburg, IA Corn cobs & fiber 25.0 2011 Bio Range Fuelse Soperton, GA Wood waste, switchgrass 40.0 2011 Therm 

RSE Pulp & Chemical Old Town, ME Woody biomass 2.2 2010 Bio 

Verenium Corp. Jennings, LA Sugarcane bagasse, wood, energycane 1.5 Online Bio 

Cellulosic Diesel Choren U.S.A. Flambeau River Biofuels New Page Corporationg 

TBD (Southeast U.S.) 

Park Falls, WI 

Wisconsin Rapids, WI 

Ag residues, forestry biomass, biogenic waste 

Forestry residues 

Woody biomass, mill residues 

TBD 

6.0 

5.5 

TBD 

2010 

2012 

FT 

FT 

FT 

aBased on current production plans. In many cases, these estimated production dates are further out than the originally-announced construction timeline. bBio = biochemical cellulosic ethanol technology, Therm = thermochemical cellulosic ethanol technology, FT = Fischer-Tropsch biomass-to-liquids diesel tecCellulosic ethanol plant will be collocated with a corn ethanol plant. dMascoma was originally issued a DOE grant to help build a demonstration-level plant in Vonore, TN. However, that location has since been rescinded and 

DOE funding towards their planned commercial-level plant in Kinross, MI. This project, a joint venture between Mascoma and JM Longyear, is also known Resources. 

eThe first 10 MGY phase is currently under construction. fEstimated DOE funding. 

gProject formerly owned by Stora Enso. 

DDD Based on information provided on DOE plant fact sheets and 7/14/08 DOE Small-Scale Biorefinery Project Overview 

(http://www.doe.gov/media/Small_Scale_Biorefineries_Matrix.pdf.) supplemented with information provided on company websites. 
171 

 

In addition to the aforementioned companies receiving DOE funding, numerous 

privately-funded companies have announced plans to build cellulosic ethanol plants in the U.S. 

These projects vary in scope and status. The facilities range in size from pilot and 

demonstration-level plants (similar to those currently operational or under construction), to small 

commercial plants (similar to the four commercial-scale plants receiving DOE funding), to large 

commercial plants (similar in size to an average corn ethanol plant). These facilities are at 

various states of planning from conducting feasibility studies, to securing funding/financing, to 

acquiring construction permits, to securing E&C contractors. Some of the projects (“planned” 

plants) are further along in the planning stage while others are in the very early stages of 

planning (“proposed” plants). There are also several companies with even less definitive 

cellulosic biofuel production plans. We will continue to track these companies and plan on 

providing more information on these projects in the final rulemaking. All in all, while it is 

uncertain which (if any) of these production plans will come to fruition, we believe the success 

of such projects will be greatly improved by the impending success of the DOE-supported 

projects. A summary of the “planned” and “proposed” cellulosic ethanol plants that we are 

aware of based on our April 2009 industry assessment is provided in Tables 1.5-36 and 1.5-37 

below. 
172 

Table 1.5-36. 

Planned Cellulosic Ethanol Plants/Capacity 

Company/Plant Name Location Feedstocks 

Prod Cap 

(MGY) 

Es

D

Abengoa Bioenergy Corporation Hugoton, KSb Corn stover, wheat straw, milo stubble, switchg 11.4 Earl

BlueFire Ethanol, Inc. Lancaster, CA Woodchips, grass cuttings, and other yard wast 3.9 TBlueFire Mecca, LLC. El Sobrante, CA Woodchips, grass cuttings, and other yard wast 17.0 T

ClearFuels Technologyc Kauai, HI Sugarcane bagasse, cane trash, wood waste 1.5 End 

Coskata TBD (Southeast U.S.) Woody biomass 50.0 2

Ecofin / Alltech Springfield, KY Corn cobs 1.3 2

Fulcrum Bioenergyd Storey County, NV Post-recycled organic waste from MSW 10.5 2

ICM Inc. St. Joseph, MOb Corn fiber/stover, sorghum, switchgrass 1.5 2

Mascoma Corporatione Kinross, MI Wood fiber 40.0 2

Pacific Ethanol Boardman , ORb Wheat straw, wood chips, corn stover 2.7 Earl

POET Project Liberty Emmetsburg, IAb Corn cobs & fiber 25.0 End 

Range Fuels Soperton, GA Wood waste, switchgrass 30.0 2

RSE Pulp & Chemical Old Town, ME Woody biomass 2.2 2

Southeast Renewable Fuels LLC Clewiston, FL Sweet sorghum, bagasse 20.0 End 

Verenium / BP Lake Okeechobee, FL Energycane, high-biomass sorghum 36.0 2

ZeaChem Boardman, OR Wood chips, saw dust, logging debris 1.5 2

Total Planned Plant Capacity 255 MGY 

aBio = biochemical cellulosic ethanol technology, Therm = thermochemical cellulosic ethanol technology, Both = investigating both technolo

unknown pretreatment technology. 

bCellulosic ethanol plant will be collocated with a corn ethanol plant. cLocated at the Gay & Robinson sugar mill. dProject also known as known as Sierra Biofuels. eThis project, a joint venture between Mascoma and JM Longyear, is also known as Frontier Renewable Resources. fThe first 10 MGY phase is currently under construction in Soperton, GA. Once this second 30 MGY phase is added, the plant will be capab

MGY of cellulosic ethanol. 
173 

Table 1.5-37. Proposed Cellulosic Ethanol Plants/Capacity 

Company/Plant Name Location Feedstocks 

Prod C

(MGY

AEE Distilleries New Milford, CT Forest residues, sawdust and yard wastes 24.0 

Agresti Biofuels Pike County, KY MSW 20.0 

Central Minnesota Ethanol Co-op (CMEC) Little Falls, MNb Woodchips 10.0 

Chemrec & NewPage Corp Escanaba, MI Paper mill waste 13.0 

Citrus Energy Clewiston, FL Citrus residues 4.0 Coskata TBD (Southeast U.S.) Woody biomass 50.0

Enerkem Pontotoc, MS MSW 20.0 Florida Crystals Corp. Okeelanta, FL Sugarcane bagasse, yard waste 1.5 Genahol Lake County, IN MSW 35.0 

Gulf Coast Energy Livingston, AL Wood waste 35.0 Gulf Coast Energy Mossy Head, FL Wood waste 35.0 

Gulf Coast Energy Cleveland, TN Wood waste 35.0 

New Age Energy / Liquafaction Moses Lake, WAb Wheat straw, corn stover, sorghum 40.0 

Orion Ethanol / Dimmitt Ethanol Dimmitt, TXb Corn Stover 10.0 

Pan Gen Global (formerly Colusa Biomass) Colusa County, CA Rice straw & hulls 12.5 Pencor Masada OxyNol Middletown, NY MSW 9.0 

Range Fuels Soperton, GA Wood waste, switchgrass 60.0

Raven Biofuels TBD (MS) Wood waste 20.0 Raven Biofuels TBD (WA) Wood waste 20.0 

Raven Biofuels TBD (ID) Corn cobs 20.0 Raven Biofuels TBD (PA) Wood waste 20.0 Southeast Renewable Fuels LLC Clewiston, FL Sweet sorghum, bagasse 80.0

Total Proposed Plant Capacity 384 MG

aBio = biochemical cellulosic ethanol technology, Therm = thermochemical cellulosic ethanol technology, Unkn = cellulosic conversion technology is unknowbCellulosic ethanol plant will be collocated with a corn ethanol plant. cPlanned expansion project. Production capacity is in addition to the volumes listed in Tables 1.5-34 and 1.5-36. 
174 

1.5.3.2 Federal/State Production Incentives 

In addition to helping fund a series of small-scale cellulosic biofuel plants, the 

Department of Energy, along with the U.S. Department of Agriculture (USDA), is helping to 

fund critical research to help make cellulosic ethanol production more commercially viable. In 

March 2007, DOE awarded $23 million in grants to four companies and one university to 

develop more efficient microbes for ethanol refining.412 In June 2007, DOE and USDA awarded 

$8.3 million to 10 universities, laboratories, and research centers to conduct genomics research 

on woody plant tissue for bioenergy.413 Later that same month, DOE announced its plan to 

spend $375 million to build three bioenergy research centers dedicated to accelerating research 

and development of cellulosic ethanol and other biofuels. The centers, which will each focus on 

different feedstocks and biological research challenges, will be located in Oak Ridge, TN, 

Madison, WI, and Berkeley, CA.414 In December 2007, DOE awarded $7.7 million to one 

company, one university, and two research centers to demonstrate the thermochemical 

conversion process of turning grasses, stover, and other cellulosic materials into biofuel.415 In 

February 2008, DOE awarded another $33.8 million to three companies and one research center 

to support the development of commercially-viable enzymes to support cellulose hydrolysis, a 

critical step in the biochemical breakdown of cellulosic feedstocks.416 Finally, in March 2008, 

DOE and USDA awarded $18 million to 18 universities and research institutes to conduct 

research and development of biomass-based products, biofuels, bioenergy, and related 

processes.417 Since 2007, DOE has announced more than $1 billion and since 2006, USDA has 

invested almost $600 million for the research, development, and demonstration of new biofuel 

technology. 

Numerous states are offering grants and tax incentives to help encourage biofuel 

production. The majority of efforts are centered on expanding ethanol production, and more 

recently, cellulosic ethanol production. According to a July 2008 assessment of DOE’s Energy 

Efficiency and Renewable Energy (EERE) website, 33 states currently offer some form of 

ethanol production incentive.418 The incentives range from support for ethanol producers to 

support for research and development companies to support for feedstock suppliers. As shown 

in Table 1.5-38, 30 states offer ethanol producers support, 19 states offer R&D companies 

support, and four states offer feedstock suppliers support. 
Table 1.5-38. 

State Ethanol Production Incentives 

State 

Ethanol Production R&D Feedstocks 

Grant Tax Credit Grant Tax Credit Grant Tax Credit 

Arkansas 

California 

Colorado 

Connecticut 

Florida 

Georgia 

Hawaii 

Illinois 

Indiana 

Iowa 

Kansas 

Kentucky 

Maine 

Maryland 

Michigan 

Minnesota 

Mississippi 

Missouri 

Montana 

New Mexico 

New York 

North Carolina 

North Dakota 

Oklahoma

Oregon 

Pennsylvania 

South Carolina 

South Dakota 

Texas 

Vermont 

Virginia 

Washington 

Wyoming 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

The grant and tax credit programs offered to ethanol producers are similar for most of the 

states that have them. The grants provide funds to help companies cover expenses associated 

with opening a production facility. These expenses can include land acquisition, site permitting, 

and plant construction. They typically require the grant amount to be matched by the producers’ 

own funding. The tax credits are given to facilities after they start production and are based on 

the number of gallons of ethanol produced at each facility. The incentives offered to R&D 

companies have similar stipulations as the production incentives. However, the grants are less 

likely to require the organization doing the research to provide matching funds. States that offer 

tax breaks to biofuel R&D companies tend to either give tax credits based on the company’s 

175
 
 

research expenses, or give property tax breaks to the lab facilities. Feedstock support is 

generally in the form of grants given to feedstock processing and/or grain handling facilities or 

tax credits issued to feedstock producers and distributors. 

Out of the 33 states offering ethanol production incentives (shown in Table 1.5-29), only 

Kansas, Maryland, and South Carolina offer specific incentives towards cellulosic ethanol 

production or research. Kansas offers revenue bonds through the Kansas Development Finance 

Authority to help fund construction or expansion of a cellulosic ethanol plant. Additionally, 

these newly-built or expanded facilities are exempt from state property tax for 10 years. 

Maryland offers a credit towards state income tax for 10 percent of cellulosic ethanol research 

and development expenses. They also have a $0.20 per gallon production credit for cellulosic 

ethanol. South Carolina gives a $0.30 per gallon production credit to cellulosic ethanol 

producers that meet certain requirements. 

In addition to the production incentives described above, a group of states in the Midwest 

have joined together to pursue ethanol and other biofuel production and usage goals as part of the 

Midwest Energy Security and Climate Stewardship Platform.419 As of June 2008, Indiana, Iowa, 

Kansas, Michigan, Minnesota, North Dakota, Ohio, South Dakota, and Wisconsin had all 

committed to these goals which emphasize energy independence through the growth of cellulosic 

ethanol production and availability of E85. The Platform goals are to produce cellulosic ethanol 

on a commercial level by 2012 and to have E85 offered at one-third of refueling stations by 

2025. They also want to reduce the energy intensity of ethanol production and supply 50% of 

their transportation fuel needs by regionally produced biofuels by 2025. 

Finally, the passage of the Food, Conservation, and Energy Act of 2008 (also known as 

the “2008 Farm Bill”) is also projected to spur cellulosic ethanol production and use.420 The 

2008 Farm Bill modifies the existing $0.51 per gallon alcohol blender credit to give preference to 

ethanol and other biofuels produced from cellulosic feedstocks. Starting in 2009, corn ethanol 

will receive a reduced tax credit of $0.45/gal while cellulosic biofuel will earn a credit of 

$1.01/gal.EEE The 2008 Farm Bill also has provisions that enable USDA to assist with the 

commercialization of second-generation biofuels. Section 9003 authorizes loan guarantees for 

the development, construction and retrofitting of commercial scale biorefineries. Section 9004 

provides payments to biorefineries to replace fossil fuels with renewable biomass. Section 9005 

provides payments to producers to support and ensure production of advanced biofuels. And 

finally, Section 9008 provides competitive grants, contracts and financial assistance to enable 

eligible entities to carry out research, development, and demonstration of biofuels and biomassbased based products. 

1.5.3.3 Cellulosic Diesel Production/Plans 

There has been an emphasis towards ethanol as a renewable fuel which seems to have 

focused the research and development priorities, as well as the government incentives, towards 

ethanol as a cellulosic biofuel. This focus is obvious by the number of U.S. companies 

developing cellulosic ethanol technologies compared to those developing cellulosic diesel fuel 

EEE Refer to Part II, Subparts A and B (Sections 15321 and 15331). 

176
 
technologies. Ethanol does have a regulatory advantage in that it is already registered to be used 

in gasoline. Cellulosic diesel fuel, however, must be registered by EPA to be used as a 

blendstock in highway diesel fuel, or used as its own fuel. 

Several issues associated with the future use of ethanol may cause entrepreneurial 

companies to focus more of their research and development efforts towards other cellulosic 

biofuels such as cellulosic diesel fuel. Recently, the greater worldwide demand for diesel fuel 

has increased diesel fuel prices relative to those of gasoline. This price difference is likely to 

continue. Worldwide diesel fuel demand is expected to continue to increase faster than gasoline 

demand. This is true for the U.S. as well because the expected increase in vehicle efficiency will 

cause gasoline demand by the light-duty fleet of vehicles here in the U.S. to diminish relative to 

that of heavy-duty diesel vehicles. Furthermore, the more aggressive pursuit of corn and 

cellulosic ethanol technologies will tend to further expand the gasoline pool even as gasoline 

demand falls. Looking towards the future, distributing and blending in more ethanol as E85 is 

challenging in that it would likely require that ethanol be priced substantially lower than 

gasoline. The potential for a mid-ethanol blend waiver, allowing the blending and use of higher 

ethanol blends like E15, could alleviate some of the challenges for using substantial volumes of 

cellulosic ethanol. However, reaching RFS2 volumes will ultimately require another solution. 

Despite the past emphasis towards ethanol, Congress has recognized that cellulosic diesel 

fuel be provided the same opportunity as cellulosic ethanol. The very significant $1.01 federal 

subsidy for developing technologies for converting cellulosic feedstocks into fuels also applies to 

cellulosic diesel fuel. Additionally, DOE and USDA have provided some grant money or loan 

guarantees to cellulosic diesel fuel technologies as summarized above in Table 1.5-35. 

 In Table 1.5-39 we provide a list of the two companies which are commercially 

producing cellulosic diesel fuel, or conducting development work on cellulosic diesel fuel 

technologies through pilot plant operations. Despite the focus of most government research and 

support for ethanol, the company which appears to be the furthest along among all the cellulosic 

biofuel companies is Cello Energy which has started up a 20 million gallon per year 

demonstration diesel fuel production plant, the only commercial scale cellulosic biofuel plant in 

the U.S. In addition, Bell Bio-Energy is aggressively developing its diesel fuel technology 

through the eventual establishment of 7 pilot plants in different Army bases across the country. 

177
 
Table 1.5-39. 

Current Cellulosic Diesel Plants 

Company/Plant Name Location Feedstocks 

Prod Cap 

(MGY) 

Est Op 

Date Conv Tech 

Cello Energy 

Bell BioEnergy 

Bay Minette, AL 

Fort Stewart, GA 

Wood Chips, Hay 

Wood Chips 

20 

0.01 

2008 

2008 

Cat Depoly 

Biochm 

As mentioned above, Bell Bio-Energy is committed to constructing 7 pilot plants in 7 

different Army bases across the country. Also, Bell Bio-Energy is projecting that they will be 

able to construct and start up a 150 million gallon per year cellulosic diesel plant sometime in 

2011. There are several other companies planning on building cellulosic diesel fuel plants in the 

U.S. Flambeau River Biofuels, Baard Energy and New Page/Chemrec are all biomass to liquids 

technologies which primarily produce diesel fuel through the thermochemical/Fischer Tropsch 

route. The earliest of these is Flambeau River Biofuels which is planning on starting up their 

plant in 2010. The Baard Energy plant is primarily a clean coal plant which will cofire biomass 

with the coal. 

Table 1.5-40. 

Under Construction & Planned Cellulosic Diesel Plants 

Company/Plant Name Location Feedstocks 

Prod Cap 

(MGY) 

Est Op 

Date Conv Tech 

Cello Energy TBD (AL) Forest Residue Catalytic 

Cello Energy TBD (AL) 

and Hay 

Forest Residue 

50 2010 Depoly 

Catalytic 

Cello Energy TBD (GA) 

and Hay 

Forest Residue 

50 2010 Depoly 

Catalytic 

and Hay 50 2010 Depoly 

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

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

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

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

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

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

Bell Bio-Energy ? Cellulose 150 2011 Bio 

Flambeau River Biofuels Park Falls, WI Forest Residue 6.00 2010 Therm-FT 

Baard Energy Wellsville, OH Forest and Ag 

Residue; cofired 

with coal 

17 2013 Therm-FT 

New Page/Chemrec Rapids, WI Forest Residue 5.50 2012 Therm-FT 

For a number of technologies summarized in Table 1.5-41, there are no immediate plans 

for producing cellulosic hydrocarbon biofuels in the U.S., however, they are strong candidates 

for eventual production in the U.S. Choren has a pilot plant in Germany and is planning to 

178 
construct a demonstration plant in Germany in 2011 or 2012. They did receive a commitment 

for a loan from DOE for building a plant in the U.S., so they have already have a commitment 

for at least some funding for a plant in the U.S. Also, Choren has developed a presence here in 

the U.S. UOP/ENI is building a pyrolysis plant in Italy in 2010. Since announcing that plant, 

UOP has formed a partnership with Ensyn which has been using pyrolysis to make a variety of 

food additives and other chemicals in Canada and here in the U.S. for many years. The pyrolysis 

technology being developed by UOP tends to produce more naphtha than diesel fuel. Logos 

Technologies received almost $20 million as a grant from the Department of Defense to develop 

aviation fuels from cellulose. Logos is pooling the expertise and experience of 12 organizations, 

half of them are universities and the other half are private companies, to derive low cost and 

highly productive technologies which could include the thermochemical and biochemical 

pathways. Swift Fuels has developed a technology for producing a high octane aviation gasoline 

from cellulose which would avoid the use of lead as an additive. The next several companies 

have developed technologies for converting sugar/starches to various hydrocarbon fuels. Virent 

is a U.S. based company which is reforming sugars to produce hydrocarbon based fuels. 

Amyris, Gevo and LS9 are all companies which are developing biochemical technologies for 

converting sugars/starch to hydrocarbons. For these companies to make the step to using 

cellulosic feedstocks, they would either have to develop the technology of converting the 

cellulose to sugars, or partner with other companies which have already mastered that step. 

Table 1.5-41. 

Propective Cellulosic Hydrocarbon Technologies in the U.S. 

Company/Plant Name Feedstocks Conv Tech 

Choren 

UOP/ENI and Ensyn 

Logos Technologies 

Swift Fuels 

Virent 

Amyris 

Gevo/Cargil and Bye Energy 

LS9 

Wood Chips and Ag residue 

Celllulose 

Cellulose 

Cellulose 

Sugars/Cellulose 

Sugars 

Sugars 

Sugars 

Therm-FT 

Pyrolysis 

Various 

Biochem 

Reforming 

Biochem 

Biochem 

Biochem 

1.5.3.4 Meeting the Proposed 2010 Cellulosic Biofuel Standard 

As described in Section III.E.b of the Preamble, not only does this notice of proposed 

rulemaking (NPRM) lay out the proposed biofuel standards through 2022, it sets the biofuel 

standards applicable in 2010. In accordance with EISA and the regulations set forth in this 

NPRM, the nation is required to blend 100 million gallons of cellulosic biofuel into U.S. 

transportation fuels by 2010. We believe our nation’s vehicles and distribution infrastructure are 

more than capable of accommodating this volume of cellulosic biofuel. Accordingly, we have 

focused our feasibility assessment on production feasibility. 

Building off our April 2009 cellulosic biofuel industry characterizations presented above 

in Sections 1.5.3.1 and 1.5.3.3, we considered existing, under construction, and planned nearterm plants with the potential to produce cellulosic ethanol or cellulosic diesel fuel in 2010. All 

179
 
together, we came up with 24 pilot- or demonstration-level plants and 7 commercial-level plants 

that we believe would allow us to meet the 100 million gallon cellulosic biofuel standard in 

2010. For plants scheduled to come on part way through the year, we assumed only a percentage 

of the total production capacity would count towards meeting the RFS2 standard. Still, we 

estimated that just over 100 million gallons of cellulosic biofuel could be produced and applied 

towards meeting the RFS2 standard in 2010. And since the majority (about 72%) of the volume 

is projected to come from cellulosic diesel fuel, the ethanol-equivalent compliance volume 

would be closed to 145 million gallons. For a summary of the plants that we believe could 

enable our nation to meet the 100 million gallon cellulsic biofuel standard in 2010, refer to Table 

1.5-42. 

180
 
 

 

 

 

 

 

 

Table 1.5-42. 

Projected Cellulosic Biofuel Production Capacity in 2010 

Company or Organization Name Location 

Prod Cap 

(MGY) 

Est. Op. 

Date 

Est. 2010 

Million 

Gallons 

Est 2010 

ETOHEquiv. 

Million 

Gallons 

Cellulosic Ethanol 

BPI & Universal Entech Phoenix, AZ 0.01 Online 0.01 0.01 

POET Project Bell Scotland, SD 0.02 Online 0.02 0.02 

Abengoa Bioenergy Corporation York, NE 0.02 Online 0.02 0.02 

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

Verenium Jennings, LA 0.05 Online 0.05 0.05 

Gulf Coast Energy Livingston, AL 0.20 Online 0.20 0.20 

Mascoma Corporation Rome, NY 0.20 Online 0.20 0.20 

Verenium Jennings, LA 1.50 Online 1.50 1.50 

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

Coskata Madison, PA 0.04 Jul-09 0.04 0.04 

DuPont Dansico Cellulosic Ethanol (DDCE) Vonore, TN 0.25 Dec-09 0.25 0.25 

Range Fuels Soperton, GA 10.00 Dec-09 10.00 10.00 

Ecofin / Alltech Springfield, KY 1.30 2010 0.65 0.65 

Fulcrum Bioenergy Storey County, NV 10.50 2010 5.25 5.25 

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

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

ZeaChem Boardman, OR 1.50 2010 0.75 0.75 

ClearFuels Technology Kauai, HI 1.50 End of 2010 0.38 0.38 

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

Cellulosic Diesel 

Cello Energy Bay Minette, AL 20.00 Online 20.00 32.00 

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

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

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

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

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

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

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

Cello Energy TBD (AL) 50.00 2010 16.67 26.67 

Cello Energy TBD (AL) 50.00 2010 16.67 26.67 

Cello Energy TBD (GA) 50.00 2010 16.67 26.67 

Flambeau River Biofuels Park Falls, WI 6.00 2010 3.00 4.80 

Total 2010 Production Forecast 100.74 144.57 

It is possible that some of the plants highlighted below may experience construction 

delays and not come online as soon as currently projected. It is also possible that a portion of the 

biofuel produced at these facilities may not meet the cellulosic biofuel definition based on the 

feedstocks and/or the fuel’s GHG reduction potential (refer to §80.1401). However, on the 

contrary, it is possible that other cellulosic biofuel plants could come online in this timeframe - 

especially if construction were to begin soon. Leading corn ethanol producers Archer Daniels 

181 
 

 

Midland and POET Biorefining are both pursuing cellulosic ethanol production. ADM is 

currently investigating cellulosic ethanol production through a cooperative research agreement 

with Purdue University. The ADM-Purdue project is focused on commercializing the use of 

highly-efficient yeast to converts cellulosic materials into ethanol through fermentation.421 In 

addition, ADM is also collaborating with Deere & Company and Monsanto Company on 

research that explores economically-sustainable methods for the harvest, storage and transport of 

corn stover for the production of animal feed, process energy, and/or cellulosic biofuel.422 

Depending on discoveries made during the research, it is possible that ADM could begin 

processing small amounts of corn stover and producing an appreciable volume of cellulosic 

biofuel at some of its existing U.S. ethanol plants in this timeframe. In addition, POET recently 

opened a 20,000 gallon-per-year demonstration-level cellulosic ethanol plant at its Scotland, SD 

research center (shown above in Table 1.5-39). It has plans to bring a 25 million-gallon-per-year 

plant online in Emmetsburg, IA in 2011. However, POET recently announced that it plans to 

produce cellulosic ethanol at six more of its existing corn ethanol plants in Iowa in the future.423 

Depending on how aggressive they are with pursuing these cellulosic ethanol production plans, 

POET could further contribute to meeting the 2010 cellulosic biofuel standard. In addition, a 

number of companies are currently building or operating demonstration-level cellulosic biofuel 

plants overseas. It is possible that these companies could export their production or decide to 

build a commercial plant in the United States in response to the proposed RFS2 standards. 

Finally, there could also be a number of start-up companies that we are unaware of that could 

contribute to meeting the 2010 cellulosic biofuel standard. 

1.5.3.5 Projected Cellulosic Feedstocks and Facilities Under RFS2 

As noted in Section 1.5.3.1, cellulosic ethanol production capacity needs to expand 

greatly in order to meet the cellulosic biofuel mandate of 16 billion gallons by 2022. While 

current production plans provide an initial idea of the types of feedstocks and potential plant 

locations that are being considered by biofuel producers, future production will be highly 

dependent on acquiring relatively cost-effective feedstocks in sufficient quantities. 

 A wide variety of feedstocks can be used for cellulosic ethanol production, including: 

agricultural residues, forestry biomass, municipal solid waste, construction and demolition waste, 

and energy crops. These feedstocks are much more difficult to convert into ethanol than 

traditional starch/corn crops or at least require new and different processes because of the more 

complex structure of cellulosic material. 

At least initially, the focus will be on feedstocks that are readily available, already 

produced or collected for other reasons, and even waste biomass which currently incurs a 

disposal fee. Consequently, initial volumes of cellulosic biofuels may benefit from low-cost 

feedstocks. However, to reach 16 Bgal will likely require reliance on more expensive feedstock 

sources purposely grown and or harvested for conversion into cellulosic biofuel. 

To determine the likely cellulosic feedstocks for production of 16 billion gallons 

cellulosic biofuel by 2022, we analyzed the data and results from various sources. Sources 

include agricultural modeling from the Forestry Agriculture Sector Optimization Model 

(FASOM) to establish the most economical agriculture residues and energy crops (see Section 

182
 
 

 

 

 

 

 

5.1 for more details on the FASOM), consultation with USDA-Forestry Sector experts for 

forestry biomass supply curves, and feedstock assessment estimates for urban waste.FFF 

An important assumption in our analysis projecting which feedstocks will be used for 

producing cellulosic ethanol is that an excess of feedstock would have to be available for 

producing the biofuel. Banks are anticipated to require excess feedstock supply as a safety factor 

to ensure that the plant will have adequate feedstock available for the plant, despite any 

feedstock emergency, such as a fire, drought, infestation of pests etc. For our analysis we 

assumed that twice the feedstock of MSW, C&D waste, and forest residue would have to be 

available to justify the building of a cellulosic ethanol plant. For corn stover, we assumed 50 

percent more feedstock than necessary. We used a lower safety factor for corn stover because it 

could be possible to remove a larger percentage of the corn stover in any year (usually only 50 

percent or less of corn stover is assumed to be sustainably removed in any one year).GGG 

Another assumption that we made is that if multiple feedstocks are available in an area, 

each would be used as feedstocks for a prospective cellulosic ethanol plant. For example, a 

particular area might comprise a small or medium sized city, some forest and some agricultural 

land. We would include the MSW and C&D wastes available from the city along with the corn 

stover and forest residue for projecting the feedstock that would be processed by the particular 

cellulosic ethanol plant. 

Previously, Section 1.1 described the total potential availability of various cellulosic 

feedstocks. Due to EISA, a substantial amount of the available feedstocks will need to be used 

for biofuels production. This section discusses the estimated amounts from each feedstock type 

needed to meet the EISA requirement of 16 Bgal of cellulosic biofuel by 2022 and also explains 

our projections for the locations of potential cellulosic biofuel facilities based on feedstock 

availability. 

Urban Waste 

Cellulosic feedstocks available at the lowest cost to the ethanol producer will likely be 

chosen first. This suggests that urban waste which is already being gathered today and which 

incurs a fee for its disposal may be among the first to be used. Urban wood wastes are used in a 

variety of ways. Most commonly, wastes are ground into mulch, dumped into land-fills, or 

incinerated with other municipal solid waste (MSW) or construction and demolition (C&D) 

debris. Urban wood wastes include a variety of wood resources such as wood-based municipal 

solid waste (MSW) and wood debris from construction and demolition. 

Urban waste (MSW wood, paper, and C&D debris) was estimated to be located near 

large population centers. We estimated a total of 42 million dry tons of MSW (paper, wood, and 

FFF It is important to note that our plant siting analysis for cellulosic ethanol facilities used the most current version 

of outputs from FASOM at the time, which was from April 2008. Since then, FASOM has been updated to reflect 

better assumptions. Therefore, the version used for the NPRM in Section 5.1 is slightly different than the one we 

used here. We do not believe that the differences between the two versions are enough to have a major impact on 

the plant siting analysis. 

GGG The FASOM results do not take into consideration these feedstock safety margins. Safety margins were used, 

however, for the plant siting analysis described in this section. 

183
 
yard trimmings) and C&D wood waste could be available nationwide for producing biofuels 

after factoring in the various assumptions on percent landfilled, percent moisture, percent 

contaminated, etc. as described in Section 1.1.2.3 on feedstock availability. We further assumed 

that approximately 25 million dry tons (of the total 42 billion dry tons) would be used, however, 

since many areas of the U.S. (e.g. much of the Rocky Mountain states) would not have a 

cellulosic facility in close enough proximity. 

We arrived at the 25 million dry tons with the following analyses. First, using the MSW 

and C&D wood waste estimates by state we calculated the tons of MSW and C&D wood waste 

material generated per person per state. We used the estimate of MSW and C&D wood waste 

material generated per person per state (i.e. tons/person) along with data on the population sizes 

of the largest cities within the state to allocate the total waste material in a state to specific cities. 

Much of the materials are already being collected and may be available to a potential 

ethanol producer at negligible costs. For instance, some additional sorting or size reduction may 

increase costs, however, tipping fees (fees for materials that are discarded at landfills) can also 

be avoided which would decrease the potential cost the feedstock. Chapter 4 of this DRIA 

further discusses feedstock costs. Assuming that the majority of this waste is of negligible cost 

to a potential ethanol producer, we calculated a minimum size for a cellulosic plant dedicated to 

MSW and C&D wood waste for various locations in the U.S. Sizes ranged from 9-60 million 

gallons per year. 

First we did not consider those cities, while small, may still be able to justify a cellulosic 

ethanol plant because some other source of biomass is also available that combined with the 

MSW and C&D wood waste can supply the cellulosic ethanol plant with sufficient feedstock. 

However, where non-MSW and C&D wood waste feedstocks are not available, we needed to 

estimate what the minimum plant size would be that would be competitive with other cellulosic 

ethanol plants. 

We conducted this analysis early on before NREL provided us with the cost information 

for a biochemical cellulosic ethanol plant. Instead we used a representation made by NREL in 

2007 for of a thermochemical ethanol plant. Using that cellulosic plant model we estimated the 

production cost for a 100 million gallon per year thermochemical plant which processed a 

cellulosic feedstock. We conducted this analysis in different parts of the country using different 

capital cost factors that account for how capital costs vary in different parts of the country. The 

different regions were Petroleum Administration for Defense Districts (PADDs) for which we 

have plant installation costs. In each part of the country, we estimated the cost of the ethanol 

produced processing the cellulosic feedstock assuming that the feedstock cost about $70 per dry 

ton. Next, we set the feedstock costs to zero cost in our cost spreadsheet and determined at what 

plant size, when scaling the capital costs as the plant size became smaller, the resulting cellulosic 

production costs matched those of the non-MSW and C&D wood waste plants. See Table 1.5-43. 

184
 
 

 

 

Table 1.5-43 

Breakeven Plant Size for MSW and C&D Wood Waste Cellulosic Ethanol Plants 

PADD 1 PADD 2 PADD 3 PADD 4 PADD 5 CA 

Ethanol Production 

Cost (c/gal) 

1.33 1.24 1.10 1.29 1.19 1.57 

Breakeven Plant 

Size (million 

gals/yr) 

28 19 9 23 15 60 

We then identified the cities that had large enough MSW and C&D wood waste to justify 

a dedicated cellulosic facility. By dedicated cellulosic facility, we mean that only MSW and 

C&D wood waste is used as a feedstock, as opposed to a facility that has multiple mixed 

feedstocks. Nineteen facilities were identified to meet such criteria, as shown in Table 1.5-44. 

The total contribution from dedicated cellulosic MSW and C&D wood waste is approximately 

640 million gallons. 

Table 1.5-44. 

Projected Dedicated Cellulosic MSW and C&D 

Wood Waste Facilities by Location and Size for 2022 

State County City PADD Size of Facility (Mgal) 

1 Alabama Jefferson Birmington 3 11 

2 Arizona Maricopa Phoenix 5 20 

3 California Los Angeles Los Angeles 5 56 

4 California Riverside Riverside 5 24 

5 California San Francisco San Francisco 5 17 

6 Colorado Adams Denver 4 28 

7 Florida Miami Fort Lauderdale 1 31 

8 Georgia Cobb Atlanta 1 43 

9 Illinois Cook Chicago 2 79 

10 Michigan Oakland Detroit 2 33 

11 Nevada Clark Las Vegas 5 17 

12 New York New York City New York 1 72 

13 Oregon Clackamas Portland 4 15 

14 Pennsylvania Philadelphia Philadelphia 1 42 

15 Texas Dallas Dallas 3 52 

16 Texas Fort Bend Houston 3 49 

17 Texas Bexar San Antonio 3 16 

18 Texas Travis Austin 3 14 

19 Washington King Seattle 5 17 

 We did assume that in areas with other cellulosic feedstocks (forest and agricultural 

residue), that the MSW would be used even if the MSW could not justify the installation of a 

plant on its own. MSW used in mixed feedstock plants is shown in Table 1.5-36. Therefore, we 

have estimated that urban waste could help contribute to the production of approximately 2.2 

185
 
 

billion gallons of ethanol.HHH Subsequent to initiating our analysis, however, we realized that 

the the renewable biomass definition in the statute may preclude the use of most MSW. See 

Section III.B.1 of the Preamble for a discussion of renewable biomass. When the definition of 

renewable biomass is finalized, it could preclude the use of waste paper and C&D waste for use 

in producing cellulosic biofuel for use toward the RFS2 standard. If this is the case, our FRM 

analysis will be adjusted to reflect this. 

Agricultural and Forestry Residues 

The next category of feedstocks chosen will likely be those that are readily produced but 

have not yet been commercially collected. This includes both agricultural and forestry residues. 

Agricultural residues are expected to play an important role early on in the development 

of the cellulosic ethanol industry due to the fact that they are already being grown. Agricultural 

crop residues are biomass that remains in the field after the harvest of agricultural crops. The 

most common residue types include corn stover (the stalks, leaves, and/or cobs), straw from 

wheat, rice, barley, or oats, and bagasse from sugarcane. The eight leading U.S. crops produce 

more than 500 million tons of residues each year, although only a fraction can be used for fuel 

and or energy production due to sustainability and conservation constraints.424 Crop residues can 

be found all over the United States, but are primarily concentrated in the Midwest since corn 

stover accounts for half of all available agricultural residues. 

Agricultural residues play an important role in maintaining and improving soil tilth, 

protecting the soil surface from water and wind erosion, and helping to maintain nutrient levels. 

Thus, collection and removal of agricultural residues must take into account concerns about the 

potential for increased erosion, reduced crop productivity, depletion of soil carbon and nutrients, 

and water pollution. Sustainable removal rates for agricultural residues have been estimated in 

various studies, many showing tremendous variability due to local differences in soil and erosion 

conditions, soil type, landscape (slope), tillage practices, crop rotation managements, and the use 

of cover crops. These are described in more detail in Section 1.1. One of the most recent studies 

by top experts in the field showed that under current rotation and tillage practices, ~30% of 

stover (about 59 million metric tonnes) produced in the US could be collected, taking into 

consideration erosion, soil moisture concerns, and nutrient replacement costs. The same study 

showed that if farmers chose to convert to no-till corn management and total stover production 

did not change, then ~50% of stover (100 million metric tonnes) could be collected without 

causing erosion to exceed the tolerable soil loss. 425 This study, however, did not consider 

possible soil carbon loss which other studies indicate may be a greater constraint to 

environmentally sustainable feedstock harvest than that needed to control water and wind 

erosion.426 Experts agree that additional studies are needed to further evaluate how soil carbon 

and other factors affect sustainable removal rates. Despite unclear guidelines for sustainable 

removal rates due to the uncertainties explained above, our agricultural modeling analysis 

assumes that 0% of stover is removable for conventional tilled lands, 35% of stover is removable 

for conservation tilled lands, and 50% is removable for no-till lands. In general, these removal 

guidelines are appropriate only for the Midwest, where the majority of corn is currently grown. 

HHH Assuming approximately 90 gal/dry ton ethanol conversion yield 

186
 
 

 

 

As already noted, removal rates will vary within regions due to local differences. Given 

the current understanding of sustainable removal rates, we believe that such assumptions are 

reasonably justified. We invite comment on these assumptions. Based on our research we also 

note that residue maintenance requirements for the amount of biomass that must remain on the 

land to ensure soil quality is another approach for modeling sustainable residue collection 

quantities, therefore we also invite comment on this approach. This approach would likely be 

more accurate for all landscapes as site specific conditions such as soil type, topography, etc. 

could be taken into account. This would prevent site specific soil erosion and soil quality 

concerns that would inevitably exist when using average values for residue removal rates across 

all soils and landscapes. At the time of our analyses we had limited data on which to accurately 

apply this approach and therefore assumed the removal guidelines based on tillage practices. 

Refer to the Section 1.1 of this DRIA for more discussion on sustainable removal rates. 

Our agricultural modeling (FASOM) suggests that corn stover will make up the majority 

of agricultural residues used by 2022 to meet the EISA cellulosic biofuel standard 

(approximately 83 million dry tons used to produce 7.8 billion gallons of cellulosic ethanol).III 

Smaller contributions are expected to come from bagasse, which is a by-product from the 

production of sugarcane, (1.2 bgal ethanol) and sweet sorghum pulp (0.1 bgal ethanol). At the 

time of this proposal, FASOM was able to model agricultural residues but not forestry biomass 

as potential feedstocks. As a result, we relied on USDA-Forest Service (FS) for information on 

the forestry sector. 

Using the assumptions from FASOM on residue and ethanol yields, we determined if it is 

possible to site potential cellulosic plants based on the acres currently harvested. We identified 

that there are enough harvested acres to produce 7.8 Bgal of ethanol from corn stover by 2022 

without having to rely on new lands. Therefore, the siting of many of the cellulosic facilities will 

likely be located where corn is typically grown today. See Table 1.5-45 for a summary of the 

states producing corn stover, and their projected volume contribution to meeting the EISA 

cellulosic requirement by 2022. 

III Assuming 94 gal/dry ton ethanol conversion yield for corn stover in 2022 

187
 
188 

 

 

 

 

Table 1.5-45. 

Projected Ethanol Produced to Meet EISA in 2022 from Corn StoverJJJ
 

Total Sustainably Sustainably 

Harvested Total Residue Total Residue Removable Residue Removable 

Acres Yield Available Yield Residue Available Residue Used 

State (in 2022) (tons/acre) (Million tons) (tons/acre) (Million tons) (Million tons) 

Total 71,784,020 n/a 380 n/a 122 82 

Illinois 12,994,100 5.43 71 1.62 21 15 

Indiana 6,209,463 5.58 35 2.09 13 10 

Iowa 14,482,313 5.47 79 1.59 23 17 

Kansas 3,026,615 5.33 16 1.65 5 3 

Kentucky 1,473,023 5.08 7 2.04 3 1 

Michigan 2,238,321 4.30 10 1.79 4 3 

Minnesota 7,509,658 5.37 40 1.60 12 8 

Missouri 2,732,875 4.73 13 2.93 8 5 

Nebraska 10,135,162 5.88 60 1.28 13 9 

Ohio 3,712,612 4.91 18 1.89 7 5 

South Dakota 4,268,425 4.01 17 1.41 6 4 

Wisconsin 3,001,454 4.74 14 2.33 7 5 

JJJ Corn stover is given in dry tons/acre and assumes an ethanol yield of 94 gal/dry ton; Sustainably removable 

residue yields assumes only the fraction that can be removed after accounting for sustainable removal rates based on 

tillage practices. This table gives approximate averages by state based on our agricultural modeling, actual yields 

will vary greatly depending on specific soil type, slope, etc. Also, the values above are calculated using the FASOM 

data outputs from April 2008 and thus are slightly different from those found in Section 5.1 of this DRIA which use 

more updated runs. 
189 

 

 

Sugarcane, on the other hand, is grown mainly in Florida, Louisiana, and Texas, although 

plans are underway to also grow sugarcane in California as well. See Section 1.1.1.2 of this 

DRIA for more discussion on sugarcane ethanol produced in the U.S. If all the sugarcane acres 

harvested today in the U.S. were used to produce ethanol from the bagasse, using the 

assumptions from FASOM on residue and ethanol yields, only approximately 700 million 

gallons could be produced, see Table 1.5-46. FASOM, however, predicts that the production of 

1.2 billion gallons of ethanol could be economically feasible from sugarcane bagasse. This 

means that between now and 2022, more sugarcane may be grown, allowing for more 

availability of bagasse in the future. 

Table 1.5-46. 

Projected Ethanol Produced to Meet EISA in 2022 from Sugarcane Bagasse 

Total Bagasse Ethanol 

Total Harvested Yield Residue Used Produced 

State Acres (in 2007) (tons/acre) (Million tons) (Million gallons) 

Total 810,800 n/a 10 707 

Florida 382,000 14.71 6 389 

Louisiana 389,600 10.25 4 277 

Texas 39,200 15.23 1 41 

Using FASOM, we analyzed the types of land likely to be supplanted by additional 

sugarcane acres in 2022 in the states of Florida, Louisiana, and Texas. In Florida, sugarcane 

crops appear to replace mainly corn, soy, and hay acres. In Louisiana, sugarcane crops appear to 

have replaced mainly corn, soy, wheat, sorghum, and hay acres. In Texas, sugarcane crops 

appear to have replaced mainly soy and sorghum crops. For these three states we gathered 

available data on corn, soy, wheat, and sorghum acres currently harvested by county (data on hay 

acres were unavailable and appeared to show small changes compared to corn and soy).427 We 

then identified the top counties (in terms of acres available) in close proximity to each other that 

could potentially be converted from corn to sugarcane crops, soy to sugarcane, wheat to 

sugarcane, etc in order to produce enough ethanol for half a billion gallons. 

Sweet sorghum pulp is predicted to be used to produce approximately 0.1 billion gallons 

of ethanol. According to the National Agriculture and Statistics Service (NASS) of the 

Department of Agriculture, there is not current available data on sweet sorghum acres grown in 

the United States. Therefore, we used FASOM to predict the types of crops that sweet sorghum 

is mainly replacing, which is corn and soybeans. Similar to the analysis done for sugarcane, we 

identified the top counties (in terms of acres available) in close proximity to each other that could 

potentially be converted from corn to sweet sorghum crops and soy to sweet sorghum crops in 

order to produce enough ethanol for 0.1 billion gallons. 

The U.S. has vast amounts of forest resources that could potentially provide feedstock for 

the production of cellulosic biofuel. One of the major sources of woody biomass could come 

from logging residues. The U.S. timber industry harvests over 235 million dry tons annually and 

produces large volumes of non-merchantable wood and residues during the process.428 Logging 
 

residues are produced in conventional harvest operations, forest management activities, and 

clearing operations. In 2004, these operations generated approximately 67 million dry tons/year 

of forest residues that were left uncollected at harvest sites.429 Other feedstocks include those 

from other removal residues, thinnings from timberland, and primary mill residues. 

Harvesting of forestry residue and other woody material can be conducted throughout the 

year. Thus, unlike agricultural residue which must be moved to secondary storage, forest 

material could be “stored on the stump.” Avoiding the need for secondary storage and the 

transportation costs for moving the feedstock there potentially provides a significant cost 

advantage for forest residue over agricultural residue. This could allow forest residue to be 

transported from further distances away from the cellulosic plant compared to agricultural 

residue at the same feedstock price. Section 1.1.2.2 further details some of challenges with using 

forestry biomass as a feedstock. 

EISA does not allow forestry material from national forests and virgin forests that could 

be used to produce biofuels to count towards the renewable fuels requirement under EISA. 

Therefore, we required forestry residue estimates that excluded such material. Most recently, the 

USDA-FS provided forestry biomass supply curves for various sources (i.e., logging residues, 

other removal residues, thinnings from timberland, etc.). This information suggested that a total 

of 76 million dry tons of forest material could be available for producing biofuels (excluding 

forest biomass material contained in national forests as required under the Act). See Section 

1.1.2.2 for more information on forest residue feedstock availability. However, much of the 

forest material is in small pockets of forest which because of its regional low density, could not 

help to justify the establishment of a cellulosic ethanol plant. After conducting our availability 

analysis, we estimated that approximately 44 million dry tons of forest material could be used, 

which would make up approximately one fourth, or 3.8 billion gallons, of the 16 billion gallons 

of cellulosic biofuel required to meet EISA. 

Dedicated Energy Crops 

While urban waste, agricultural residues, and forest residues will likely be the first 

feedstocks used in the production of cellulosic biofuel, there may be limitations to their use due 

to land availability, sustainable removal rates, etc. Energy crops which are not yet grown 

commercially but have the potential for high yields and a series of environmental benefits could 

help provide additional feedstocks in the future. Dedicated energy crops are plant species grown 

specifically as renewable fuel feedstocks. Various perennial plants have been researched as 

potential dedicated feedstocks. These include switchgrass, mixed prairie grasses, hybrid poplar, 

miscanthus, and willow trees. 

In addition to estimating the extent that agricultural residues might contribute to 

cellulosic ethanol production, FASOM also estimated the contribution that energy crops might 

provide.KKK FASOM covers all cropland and pastureland in production in the 48 conterminous 

United States, however it does not contain all categories of grassland and rangeland captured in 

USDA’s Major Land Use data sets. Therefore, it is possible there is land appropriate for 

KKK Assuming 16 Bgal cellulosic biofuel total, 2.2 Bgal from Urban Waste, and 3.8 Bgal from Forestry Biomass; 10 

Bgal of cellulosic biofuel for ag residues and/or energy crops would be needed. 

190
 
 

 

 

growing dedicated energy crops that is not currently modeled in FASOM. Furthermore, we 

constrained FASOM to be consistent with the 2008 Farm Bill and assumed 32 million acres 

would stay in CRP.LLL These constraints on land availability may have contributed to the model 

choosing a substantial amount of agricultural residues mostly as corn stover and a relatively 

small portion of energy crops as being economically viable feedstocks. The use of other models, 

such as USDA’s Regional Environment and Agriculture Programming (REAP) model and 

University of Tennessee’s POLYSYS model, have shown that the use of energy crops in order to 

meet EISA may be more significant than our current FASOM modeling results.MMM As such, 

we plan to revisit these land availability assumptions in order to arrive at a more consistent basis 

for the FRM. 

Given the constraints outlined above, FASOM projects that 0.9 billion gallons of 

cellulosic ethanol from switchgrass is economically feasible by 2022. The majority of 

switchgrass is projected to likely be grown in Oklahoma, where the majority of acres are 

replacing wheat and hay. A smaller portion is expected to come from West Virginia and New 

Hampshire where hay is mainly replaced. Similar to the analysis done for sugarcane and sweet 

sorghum, we identified the top counties (in terms of acres available) in close proximity to each 

other that could potentially be converted from wheat to switchgrass or hay to switchgrass in 

order to produce enough ethanol for 0.9 billion gallons. 

Summary of Cellulosic Feedstocks for 2022

 Table 1.5-47 summarizes our internal estimate of cellulosic feedstocks and their 

corresponding volume contribution to 16 billion gallons cellulosic biofuel by 2022 for the 

purposes of our impacts assessment. 

LLL Beside the economic incentive of a farmer payment to keep land in CRP, local environmental interests may also
 

fight to maintain CRP land for wildlife preservation. Also, we did not know what portion of the CRP is wetlands 

which likely could not support harvesting equipment.

MMM Biomass Research and Development Initiative (BR&DI), “Increasing Feedstock Production for Biofuels: 

Economic Drivers, Environmental Implications, and the Role of Research,” http://www.brdisolutions.com, 

December 2008. 

191
 
 

 

 

Table 1.5-47. 

Cellulosic Feedstocks Assumed to Meet EISA in 2022 

Feedstock Volume (Bgal) 

Agricultural Residues 9.1 

Corn Stover 7.8 

BagasseNNN 1.2 

Sweet Sorghum Pulp 0.1 

Forestry Biomass 3.8 

Urban Waste 2.2 

Dedicated Energy Crops 

(Switchgrass) 

0.9 

Total 16.0 

Cellulosic Plant Siting 

Future cellulosic biofuel plant siting was based on the types of feedstocks that would be 

most economical as shown in Table 1.5-35, above. As cellulosic biofuel refineries will likely be 

located close to biomass resources in order to take advantage of lower transportation costs, 

we’ve assessed the potential areas in the U.S. that grow the various feedstocks chosen. To do 

this, we used data on harvested acres by county for crops that are currently grown today, such as 

corn stover and sugarcane (for bagasse).430 In some cases, crops are not currently grown, but 

have the potential to replace other crops or pastureland (e.g. dedicated energy crops). We used 

the output from our economic modeling (FASOM) to help us determine which types of land are 

likely to be replaced by newly grown crops. For forestry biomass, USDA-Forestry service 

provided supply curve data by county showing the available tons produced. Urban waste (MSW 

wood, paper, and C&D debris) was estimated to be located near large population centers. 

Our analyses also take into account the locations of planned cellulosic facilities as well as 

any corn facilities or pulp and paper mills when we project where cellulosic plants are located 

into the future. While not all planned cellulosic facilities will likely come to fruition, it was 

important to look at the locations of these facilities as their locations are likely to be chosen for 

good reasons (i.e. close to resources, infrastructure in place, etc.). We analyzed current corn 

facilities and pulp and paper mill sites as well since they are likely to be close to their respective 

feedstocks (i.e. corn stover and wood residues) and could have many synergies with cellulosic 

biofuel production, such as shared steam and electricity production. However, this does not 

mean that we have chosen to place cellulosic facilities at all the locations where there are current 

corn facilities and pulp and paper mills. The locations are only used to help select areas that 

could be preferential towards building a cellulosic facility 

Using feedstock availability data by county/city, we located potential cellulosic sites 

across the U.S. that could justify the construction of a cellulosic plant facility. Table 1.5-48 

shows the volume of cellulosic facilities by feedstock by state projected for 2022. The total 

NNN Bagasse is a byproduct of sugarcane crushing and not technically an agricultural residue. Sweet sorghum pulp is 

also a byproduct of sweet sorghum processing. We have included it under this heading for simplification due to 

sugarcane being an agricultural feedstock. 

192
 
 

 

volumes given in Table 1.5-35 match the total volumes given in Table 1.5-36 within a couple 

hundred million gallons. As these differences are relatively small, we believe the cellulosic 

facilities sited are a good estimate of potential locations. 

Table 1.5-48. 

Projected Cellulosic Ethanol Volumes by State (million gallons in 2022) 

State 

Total 

Volume Ag Volume 

Energy Crop 

Volume 

Urban Waste 

Volume 

Forestry 

Volume 

Alabama 532 0 0 140 392 

Arkansas 298 0 0 0 298 

California 450 0 0 221 229 

Colorado 28 0 0 28 0 

Florida 421 390 0 31 0 

Georgia 437 0 0 67 370 

Illinois 1,525 1,270 0 198 58 

Indiana 1,109 948 0 101 60 

Iowa 1,697 1,635 0 32 30 

Kansas 310 250 0 29 32 

Kentucky 70 70 0 0 0 

Louisiana 1,001 590 0 103 308 

Maine 191 0 0 2 189 

Michigan 505 283 0 171 51 

Minnesota 876 750 0 50 76 

Mississippi 214 0 0 22 192 

Missouri 654 504 0 78 72 

Montana 92 0 0 9 83 

Nebraska 956 851 0 31 75 

Nevada 17 0 0 17 0 

New Hampshire 171 0 35 29 107 

New York 72 0 0 72 0 

North Carolina 315 0 0 98 217 

Ohio 598 410 0 156 32 

Oklahoma 793 0 777 0 16 

Oregon 244 0 0 44 200 

Pennsylvania 42 0 0 42 0 

South Carolina 213 0 0 57 156 

South Dakota 434 350 0 6 78 

Tennessee 97 0 0 19 78 

Texas 576 300 0 131 145 

Virginia 197 0 0 95 102 

Washington 175 0 0 17 158 

West Virginia 149 0 101 0 48 

Wisconsin 581 432 0 43 106 

Total Volume 16,039 9,034 913 2,139 3,955 

Each of the cellulosic plants was chosen to produce approximately 100 million gallons 

per year of ethanol. In some cases we had to resort to lower volumes due to limited resources in 

193 
 

 

 

 

 

 

 

 

 

 

 

a given area. In other cases, we used greater than 100 million gallons per year because relatively 

close materials were available that would otherwise go unused. In addition, we limited biomass 

transport distances to be approximately 100 miles each way or less (radius from proposed 

facility), as large transport distances are economically prohibitive. We found that the majority of 

corn stover cellulosic facilities required smaller transport distances than the assumed 100 mile 

limit due to relatively close proximity to available feedstocks. Forest residues, on the other hand, 

typically required greater distances as collectable material appeared to be sparser. The following 

Table 1.5-49 lists the 180 cellulosic ethanol facilities that we project could be used to produce 16 

Bgal of cellulosic biofuel by 2022. See Figure 1.5-16 for a visual representation of the locations 

of these facilities. 

Table 1.5-49. 

Projected Cellulosic Facilities 

(million gallons in 2022)
 

County State 

Total Volume 

(million gallons/yr) 

Escambia Alabama 112 

Greene Alabama 108 

Morgan Alabama 96 

Russell Alabama 101 

Talledega Alabama 115 

Cleveland Arkansas 99 

Howard Arkansas 97 

Woodruff Arkansas 102 

Butte California 94 

Orange California 133 

San Joaquin California 120 

Siskiyou California 102 

Adams Colorado 28 

Broward Florida 31 

Hendry Florida 90 

Palm Beach Florida 100 

Palm Beach Florida 100 

Palm Beach Florida 100 

Glynn Georgia 108 

Grady Georgia 130 

Richmond Georgia 101 

Treutlen Georgia 98 

Bureau Illinois 130 

Carroll Illinois 77 

 Champaign Illinois 89 

 Coles Illinois 77 

De Witt Illinois 100 

Du Page Illinois 128 

Grundy Illinois 77 

 Iroquois Illinois 80 

Knox Illinois 89 

Menard Illinois 99 

 Montgomery Illinois 78 

194
 
 

 

 

 

 

 

 

 Morgan 

Ogle 

 Richland 

Shelby 

 Tazewell 

 Washington 

Illinois 

Illinois 

Illinois 

Illinois 

Illinois 

Illinois 

67 

95 

81 

68 

107 

85 

Benton 

Clinton 

Daviess 

De Kalb 

Fulton 

Jasper 

 Jennings 

 Madison 

 Morgan 

Parke 

Union 

Vanderburgh 

Wells 

Indiana 

Indiana 

Indiana 

Indiana 

Indiana 

Indiana 

Indiana 

Indiana 

Indiana 

Indiana 

Indiana 

Indiana 

Indiana 

92 

80 

93 

91 

74 

82 

94 

78 

100 

92 

82 

74 

77 

Benton 

Buchanan 

Buena Vista 

Cerro Gordo 

Chickasaw 

Des Moines 

Dubuque 

Franklin 

Grundy 

Guthrie 

Ida 

Mahaska 

Muscatine 

O Brien 

Page 

Palo Alto 

Pottawattamie 

Sioux 

Story 

Union 

Webster 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

Iowa 

69 

83 

84 

79 

82 

87 

70 

80 

83 

85 

88 

80 

83 

80 

81 

75 

84 

72 

89 

76 

86 

Logan 

Nemaha 

Sedgwick 

Stevens 

Kansas 

Kansas 

Kansas 

Kansas 

75 

78 

71 

87 

Webster Kentucky 70 

Bienville 

E. Baton Rouge 

E. Carroll 

Jeff Davis 

Allen 

Louisiana 

Louisiana 

Louisiana 

Louisiana 

Louisiana 

115 

106 

103 

87 

50 

195
 

 

 

 

 

 

 

 

 

 

 

 

 

 

Avoyelles 

Iberville 

La Fourche 

Lafayette 

Pt. Coupe 

St Landry 

Louisiana 

Louisiana 

Louisiana 

Louisiana 

Louisiana 

Louisiana 

100 

90 

50 

100 

100 

100 

Penobscot 

Piscataquis 

Maine 

Maine 

100 

91 

Calhoun 

Ionia 

Tuscola 

Van Buren 

Wayne 

Michigan 

Michigan 

Michigan 

Michigan 

Michigan 

109 

117 

105 

89 

85 

Chippewa 

Dakota 

Dodge 

Faribault 

Lyon 

Martin 

Rock 

Sibley 

Stearns

Stevens 

Minnesota 

Minnesota 

Minnesota 

Minnesota 

Minnesota 

Minnesota 

Minnesota 

Minnesota 

 Minnesota 

Minnesota 

92 

114 

86 

88 

84 

95 

73 

102 

68 

76 

Forrest 

Grenada 

Mississippi 

Mississippi 

107 

107 

Audrain 

Chariton 

Clark 

Gentry 

New Madrid 

Ray 

St. Louis 

Missouri 

Missouri 

Missouri 

Missouri 

Missouri 

Missouri 

Missouri 

86 

74 

89 

95 

84 

100 

125 

Sanders Montana 92 

Boone 

 Custer 

 Harlan 

 Hitchcock 

Holt 

 Lancaster 

 Lincoln 

 Nuckolls 

 Saunders 

Wayne 

 York 

Nebraska 

Nebraska 

Nebraska 

Nebraska 

Nebraska 

Nebraska 

Nebraska 

Nebraska 

Nebraska 

Nebraska 

Nebraska 

98 

84

78

83

91 

74 

81 

76 

100 

96 

94 

Clark Nevada 17 

Carroll 

Carroll 

New Hampshire 

New Hampshire 

136 

35 

West Chester New York 72 

Cumberland 

Forsyth 

North Carolina 

North Carolina 

110 

104 

196
 
 

 

 

 

 

 

 

 

Martin North Carolina 102 

Auglaize 

Clinton 

Franklin 

Logan 

Portage 

Richland 

Wood 

Ohio 

Ohio 

Ohio 

Ohio 

Ohio 

Ohio 

Ohio 

80 

100 

77 

75 

98 

83 

85 

Craig 

Grady 

Hughes

Kingfisher 

Lincoln 

Muskogee 

Osage 

Oklahoma 

Oklahoma 

 Oklahoma 

Oklahoma 

Oklahoma 

Oklahoma 

Oklahoma 

130 

108 

91 

110 

120 

118 

116 

Lane 

Yamhill 

Oregon 

Oregon 

126 

118 

Montgomery Pennsylvania 42 

Berkeley 

Spartanburg 

South Carolina 

South Carolina 

105 

108 

Day 

 Edmunds 

 Kingsbury 

Lake 

 Turner 

South Dakota 

South Dakota 

South Dakota 

South Dakota 

South Dakota 

85 

80 

98 

83 

89 

Monroe Tennessee 97 

Angelina 

Bexar

Cameron 

Dallas 

Harris 

Hidalgo 

Travis 

Willacy 

Texas 

Texas 

Texas 

Texas 

Texas 

Texas 

Texas 

Texas 

114 

16 

100 

52 

80 

100 

14 

100 

Halifax 

Prince George 

Virginia 

Virginia 

98 

99 

Chelan 

Thurston 

Washington 

Washington 

78 

97 

Harrison West Virginia 149 

Calumet 

Dane 

Dunn 

Eau Claire 

Grant 

Jefferson 

Marquette 

Wood 

Wisconsin 

Wisconsin 

Wisconsin 

Wisconsin 

Wisconsin 

Wisconsin 

Wisconsin 

Wisconsin 

91 

76 

63 

65 

68 

94 

65 

59 

Total 16039 

197
 
Figure 1.5-16. Projected Cellulosic Facilities

Bagasse Plant 

MSW Plant 

Switchgrass Plant 

Ag. Residue Plant 

Forest Residue Plant 

 It is important to note, however, that there are many more factors other than feedstock 

availability to consider when eventually siting a plant. We have not taken into account, for 

example, water constraints, availability of permits, and sufficient personnel for specific 

locations. As many of the corn stover facilities are projected to be located close to corn starch 

facilities, there is the potential for competition for clean water supplies. Therefore, as more and 

more facilities draw on limited resources, it may become apparent that various locations are 

infeasible. Nevertheless, our plant siting analysis provides a reasonable approximation for 

analysis purposes since it is not intended to predict precisely where actual plants will be located. 

Other work is currently being done that will help address some of these issues, but at the time of 

this proposal, was not yet available.431

 As we are projecting the location of cellulosic plants in 2022, it is important to keep in 

mind the various uncertainties in the analysis. For example, future analyses could determine 

better recommendations for sustainable removal rates. In the case where lower removal rates are 

recommended, agricultural residues may be more limited and could promote more growth in 

dedicated energy crops. Given the information we have to date, we believe our projected 

locations for cellulosic facilities represent a reasonable forecast for estimating the impacts of this 

rule. 

1.5.4 Biodiesel & Renewable Diesel

Biodiesel 

 The biodiesel industry differs significantly in profile from the ethanol industry, in that it 

is comprised of plants with a wide variety of sizes, ranging from less than one million gallons to 

more than 50 million gallons per year production capacity, using feedstock ranging from virgin 

soy oil to recycled cooking grease and rendered fats. The industry capacity has expanded 

198
 

rapidly, going from a sparse network of small businesses selling locally to one with large 

companies selling internationally in less than a decade. Approximately 176 plants reported being 

on-line for production in 2008, with a mean size of 13 million gallons per year and a median size 

of just 5 million gallons per year. Figure 1.5-17 below shows historical aggregate capacity, sales 

volumes, and apparent capacity utilization rates. 

Figure 1.5-17. Recent biodiesel industry capacity and production trends. 

0 

500 

1,000 

1,500 

2,000 

2,500 

2003 2004 2005 2006 2007 2008 

Million Gallons 

0% 

5% 

10% 

15% 

20% 

25% 

30% 

35% 

Utilization 

Capacity 

Production 

Utilization 

a 

a 2008 capacity figure is as of January; annual production figures were not available for 2008 at the time of this 

writing. 

The average utilization capacity has stayed around 30% for the past few years due to 

continued expansion of on-line capacity despite apparently adequate existing capacity. We can 

speculate that this is primarily because of the relatively low capital cost (typically 5-10% of 

operating cost) of these plants, which enables them to operate only part of the year or at reduced 

capacity, depending on feedstock prices or other market conditions. Besides fuel, some of these 

plants also produce non-fuel oleochemicals for use in detergents, lubricants or other products, 

providing additional sources of revenue for part of the industry. 

In order to conduct our emissions and distribution analyses, we needed to have an 

industry characterization at the time of the fully phased-in program, the year 2022. This was not 

a simple task because of the unusual nature of the biodiesel industry. We generally assumed that 

the demand for biodiesel would stabilize at approximately the level of the standard, which 

seemed reasonable given the relatively high cost for biodiesel feedstocks as well as the uncertain 

status of the current tax incentives. We estimated how many plants would continue to produce 

biodiesel and where they might be located based on three factors: state incentives for production 

and sales, BQ-9000 certification, and capabilities for handling multiple feedstock types. Plants 

199
 
13/15

105/123

0.8/1

0.4/0.5

35/85 41/60

113/158

56/60

9.2/22

75/80

13/30

17/20

38/45

NJ: 38/40

CT: 3.3/4

MA: 0.4/0.5

RI: 0.2/0.3

42/50

67/80

25/30

FL: 17/18

8.3/10

88/105

0.4/0.5

7.5/8

Biodiesel Production/Capacity 

(million gal/yr) in 2022

13/15

105/123

0.8/1

0.4/0.5

35/85 41/60

113/158

56/60

9.2/22

75/80

13/30

17/20

38/45

NJ: 38/40

CT: 3.3/4

MA: 0.4/0.5

RI: 0.2/0.3

42/50

67/80

25/30

FL: 17/18

8.3/10

88/105

0.4/0.5

7.5/8

with more of these advantages were expected to be more likely to survive over those that had 

fewer. We projected that a number of very small plants processing waste greases/fats would 

continue to operate based on local market niches regardless of these criteria. In an effort to be 

realistic in this forecast, other practical considerations were made, such as avoiding siting several 

plants in the same state (except in the Midwest). 

We project that between now and 2022 plants will continue to compete and consolidate to 

make fewer plants of larger size. During this period most plants will have added the pretreatment and feedstock segregation capacity to process any mix of feedstock types available in 

their area. By the out-years of this analysis, we expect production capacity use factors to reach 

80-90% in nearly all fuel plants. Multi-product plants will retain the capacity to produce 

biodiesel, but it is not expected to be their primary product due to higher margins for more 

specialized products like surfactants, lubricants, or renewable oleochemical feedstocks for resale. The map in Figure 1.5-18 represents what the industry might look like by 2022. Table 1.5­

50 summarizes key parameters of the industry as it is currently and in the 2022 forecast. 

Figure 1.5-18. Biodiesel industry forecast for 2022 

88/105 

35/85 41/60 

8.3/10 MA: 0.4/0.5 

17/20 RI: 0.2/0.3 

0.4/0.5 0.4/0.5 113/158 

9.2/22 

75/80 

13/30 

38/45 

NJ: 38/40 

CT: 3.3/4 

7.5/8 0.8/1 

56/60 

42/50 

13/15 25/30 

67/80 

105/123 

Biodiesel Production/Capacity 

(million gal/yr) in 2022 FL: 17/18 

200
 
 

Table 1.5-50. Summary of current biodiesel industry and forecast.432 

2008 2022 

Total production capacity on-line (million gal/yr) 2,610 1,050
 

Number of operating plants 176 35 

Median plant size (million gal/yr) 5 30 

Total biodiesel production (million gal) 700 810
 

Average capacity factor 0.27 0.77 

Renewable Diesel 

Since December, 2007, ConocoPhillips has been producing a small amount (300-500 

bbl/day) of renewable diesel at their Borger, Texas, refinery from beef tallow generated by 

Tyson Foods, Inc. in Amarillo, Texas.433 In 2007, Dynamic Fuels, LLC., was formed by 

Syntroleum Corp. and Tyson Foods, Inc., to produce liquid renewable fuels. This fall Dynamic 

Fuels has announced ground-breaking for a 75 million gallon per year plant (5,000 bbl/day) in 

Geismar, Louisiana, that will use Tyson meat processing fats as feedstock to Syntroleum’s BioSynfining process. Start-up is scheduled for 2010, with the primary product being high-quality 

diesel fuel that will be fungible within the existing petroleum supply system. 434 

The earlier years of our industry projection are based primarily on feasibility and 

construction announcements by Dynamic Fuels, LLC, while the later years are based on the 

available supply of rendered fats and greases as feedstocks, assuming the continued expansion of 

fuel conversion facilities to utilize them. We project a mix of stand-alone and refinery colocated facilities. Stand-alone facilities receive feedstocks, process them, and ship out finished 

products, and are generally self-sufficient in terms of material and energy. Conversion facilities 

that are located within the boundaries of existing petroleum refineries can take advantage of 

utilities such as steam and hydrogen already available on-site, as well as hydrocarbon 

blendstocks, and tankage and pipeline, rail, and port terminals. Material that is processed at 

existing refineries can either be co-processed in the same equipment trains with petroleum, or 

processed separately and blended just before leaving the facility. 

The Geismar, Lousiana, facility plans to utilize supplies of hydrogen available in the 

industrial park where it will be located, as well as rail and shipping infrastructure already in 

place nearby.435 However, it is not co-located with existing petroleum production, and therefore 

would be considered a stand-alone facility in our analyses. 

Based on public material released by Syntroleum earlier this year, it appears that a second 

plant of 150 million gallons per year capacity is also under consideration for construction, but 

location, timeline, and feedstock source are not known at this time. 436 Table 1.5-51 shows the 

industry forecast used in our analyses of renewable diesel production in 2022. The Geismar, 

Lousiana, facility comprises part of the 125 million gallons per year in 2022 of new facility fuel 

shown in the table below, while the facility expansion values represent production we expect to 

come on-line at existing refineries in the future. 

201
 
 

 

 

 

 

Table 1.5-51. Projected renewable diesel volumes (million gallons in 2022) 

Expansion at existing refinery New stand-alone facility 

Co-processed with petroleum 188 -

Not co-processed with petroleum 63 125 

1.6 Biofuel Distribution 

1.6.1 Biofuel Distribution Overview 

The discussion in this section pertains to the distribution of biofuels within the U.S. 

Significant volumes of ethanol would be imported into the U.S. to meet the volume of ethanol 

that we project would be used to Satisfy the RFS2 standards. The importation of ethanol into the 

U.S. under the RFS2 standards is discussed in Section 1.5.2 of this DRIA. 

The modes of distributing renewable fuels to the end user vary depending on constraints 

arising from their physical/chemical nature and their point of origination. Some fuels are 

compatible with the existing fuel distribution system, while others currently require segregation 

from other fuels up to the point where they are blended with petroleum based fuels. The location 

of renewable fuel production plants is also often dictated by the need to be close to the source of 

the feedstocks used rather than to fuel demand centers or to take advantage of the existing 

pipeline distribution system for petroleum products.OOO Once blended with petroleum-based 

fuels, some biofuels (such as E10, B2, and B5) can be handled in the conventional fuel 

distribution downstream of the terminal (including retail) and used in conventional vehicles.PPP 

However, E85 must be used in flex-fuel vehicles and dispensed from retail equipment that has 

been manufactured to tolerate the high ethanol concentration. Hence, the distribution of 

renewable fuels raises unique concerns and in many instances requires the addition of new 

transportation, storage, blending, and retail equipment. 

Significant challenges must be faced in reconfiguring the distribution system to 

accommodate the large volumes of ethanol and to a lesser extent biodiesel that we project would 

be used to meet the proposed standards. While some uncertainties remain, there is no barrier that 

appears insurmountable. The response of the transportation system to date to the recent 

unprecedented increase in ethanol use is encouraging. A recent U.S. Department of Agriculture 

(USDA) report concluded that logistical concerns have not hampered ethanol production growth 

to date, but that concerns may arise about the adequacy of transportation infrastructure as the 

growth in ethanol production continues.437 

Considerations related to the distribution of ethanol, biodiesel, and renewable diesel are 

discussed in the following sections as well as the changes to each segment in the distribution 

system that would be needed to support the volumes of these biofuels that we project would be 

OOO A discussion of the projected locations of ethanol production facilities can be found in chapter 1.5 of this DRIA. PPP E10 is a mixture of 10% ethanol and 90% gasoline. B2 is a mixture of 2% biodiesel and 98% petroleum-based 

diesel. B5 is a mixture of 5% biodiesel and 95% petroleum-based diesel. 

202
 
 

 

 

 

 

used to satisfy the RFS2 standards. The costs associated with making the necessary changes to 

the fuel distribution infrastructure are discussed in Section 4.2 of this DRIA. 

Considerable efforts are underway by individual companies in the fuel distribution 

system, consortiums of such companies, industry associations, independent study groups, and 

inter-agency governmental organizations to evaluate what steps might be necessary to facilitate 

the necessary upgrades to the distribution system to support compliance with the RFS2 

standards.QQQ EPA will continue to participate in or monitor these efforts as appropriate to keep 

abreast of potential problems in the biofuel distribution system which might interfere with the 

use of the volumes of biofuels that we project will be needed to comply with the RFS2 standards. 

To the extent that biofuels other than ethanol and biodiesel are produced in response to 

the RFS2 standards, the need for added segregation during distribution might be lessened. For 

example, we expect renewable diesel fuel could be handled like a petroleum-based diesel blend 

stock in the distribution system. Distillate fuel produced from cellulosic feedstocks could also 

likely be treated as a petroleum-based diesel fuel blendstock or finished diesel fuel in the 

distribution system. Likewise, bio-gasoline or bio-butanol could likely be treated as petroleumbased gasoline blendstocks.RRR The ability to treat such bio-based blendstocks in that same 

fashion as petroleum-based fuel blendstocks might enhance the possibility for transport by 

pipeline. However, the location of the production plants for such biofuels relative to petroleum 

pipeline origination points would continue to be an issue limiting the usefulness of existing 

pipelines.SSS 

1.6.1.1 Overview of Ethanol Distribution 

Denatured ethanol is shipped from production and import facilities to petroleum 

terminals where it is blended with gasoline. Pipelines are the preferred method of shipping large 

volumes of petroleum products over long distances because of the relative low cost and 

reliability. However, ethanol is not commonly shipped by pipeline currently because it can cause 

stress corrosion cracking in pipeline walls and its affinity for water and solvency can result in 

product contamination concerns. The location of ethanol production and demand centers also 

would tend to limit the extent to which existing petroleum pipelines could be used to ship 

ethanol. Shipping ethanol in pipelines that carry distillate fuels as well as gasoline also presents 

unique difficulties in coping with the volumes of a distillate-ethanol mixture which would 

typically result.TTT It is not possible to re-process this mixture in the way that diesel-gasoline 

QQQ For example: 1) The “Biomass Research and Development Board”, an inter-governmental group, has formed a 

group that is focused on evaluating biofuels distribution infrastructure issues. 2) The National Commission on 

Energy Policy, an independent organization, has formed a Biofuels Infrastructure Task Force composed of industry 

experts to evaluate what steps need to be taken to support the distribution of the volumes of biofuels mandated under 

the Energy Information and security Act (EISA) on which the RFS2 standards are based. 3) The Association of Oil 

Pipelines is conducting research to evaluate what steps a necessary to allow the distribution of ethanol blends by 

pipeline.

RRR Biogasoline might also potentially be treated as finished fuel. SSS The projected location of biofuel plants would not be affected by the choice of whether they are designed to 

produce ethanol, distillate fuel, bio-gasoline, or butanol. Proximity to the feedstock would continue to be the 

predominate consideration.

TTT Different grades of gasoline and diesel fuel are typically shipped in multi-product pipelines in batches that abut 

each other. To the extent possible, products are sequenced in a way to allow the interface mixture between batches 

203
 
 

 

 

 

 

 

 

 

 

mixtures resulting from pipeline shipment are currently handled.UUU Substantial testing and 

analysis is currently underway to resolve these concerns so that ethanol may be shipped by 

pipeline either in a batch mode or blended with petroleum-based fuel.438 By the time of the 

publication of this proposal, results of these evaluations may be available regarding what actions 

are necessary by multi-product pipelines to overcome safety and product contamination concerns 

associated with shipping 10% ethanol blends. A short gasoline pipeline in Florida also started 

shipping commercial batches of denatured ethanol in December of 2008.439 Thus, there is the 

potential that existing petroleum pipelines in some areas of the county may play a role in the 

shipment of ethanol from the points of production/importation to petroleum terminals. 

However, the location of ethanol plants in relation to existing pipeline origination points 

will continue to limit the role that can be played by pipelines in the shipment of ethanol.VVV 

Current corn/starch ethanol production facilities are primarily located in the Midwest far from 

the origination points of most existing product pipelines and the primary gasoline demand 

centers.WWW This is also projected to primarily be the case for future corn/starch ethanol 

plants.XXX While the projected future cellulosic ethanol plants are expected to be somewhat 

more dispersed throughout the country, we project that most will be located in the Midwest.YYY 

Some imported ethanol could be brought into ports near the origination points of product 

pipelines in the gulf coast and the Northeast. Nevertheless, the majority of ethanol will continue 

to be produced at locations distant from the origination points of product pipelines and gasoline 

demand centers. The gathering of ethanol from production facilities located in the Midwest and 

shipment by barge down the Mississippi for introduction to pipelines in the gulf coast is under 

consideration. However, the additional handling steps to bring the ethanol to the pipeline origin 

points in this manner would diminish the potential benefit of shipment by existing petroleum 

pipelines compared to direct shipment by rail. 

Evaluations are also currently underway regarding the feasibility of constructing a new 

dedicated ethanol pipeline from the Midwest to the East coast.440 Under such an approach, 

ethanol would be gathered from a number of Midwest production facilities to provide sufficient 

volume to justify pipeline operation. To the extent that ethanol production would be further 

concentrated in the Midwest due to the citing cellulosic ethanol plants there, this would tend to 

help justify the cost of installing a dedicated ethanol pipeline. There are substantial issues that 

would need to be addressed before construction on such a pipeline could proceed, including 

those associated with securing new right of ways and establishing sufficient surety regarding the 

return on the several billion dollar investment. 

to be cut into one of the adjoining products. In cases where diesel fuel abuts gasoline in the pipeline, the resulting 

mixture must typically reprocessed into its component parts by distillation for resale as gasoline and diesel fuel. UUU We believe that it may not currently possible to separate ethanol from a gasoline/diesel mixture sufficiently by 

distillation. Hence, a significant amount of ethanol may remain in the gasoline and diesel fractions separated by 

distillation. Gasoline-ethanol mixtures can be blended into finished gasoline provided the applicable maximum 

allowed ethanol concentration is not exceeded. However, diesel-ethanol mixtures can not be used as motor fuel. VVV Some small petroleum product refineries are currently limited in their ability to ship products by pipeline 

because their relatively low volumes are not sufficient to justify connection to the pipeline distribution system. WWW The location of current corn/starch ethanol production facilities is discussed in Section 1.5.1.1 of this DRIA. XXX The projected growth in corn/starch ethanol plants under the proposed RFS2 standards is discussed in Section 

1.5.1.2 of this DRIA. YYY The projected location of cellulosic ethanol plants is discussed in Section 1.5.3 of this DRIA. 

204
 
 

Due to the uncertainties regarding the degree to which pipelines will be able to participate 

in the transportation of ethanol, we assumed that ethanol will continue to be transported by rail, 

barge, and truck to the terminal where it would be blended into gasoline. There is substantial 

room for the distribution by these modes to be further optimized primarily through the increased 

shipment by unit train and installation of additional hub delivery terminals that can accept large 

volumes of ethanol for further distribution to satellite terminals. To the extent that pipelines do 

eventually play a role in the distribution of ethanol, this could tend to the reduce distribution 

costs and improve reliability in supply. 

The United States Department of Agriculture estimated that in 2005, approximately 60% 

of ethanol was transported by rail, 30% was transported by tank truck, and 10% was transported 

by barge.441 When practicable, shipment by unit train is the preferred method of rail shipment 

rather than shipping on a manifest rail car basis.ZZZ Manifest rail car shipment refers to the 

shipment of ethanol in rail tanks cars that are incorporated into trains which are composed of a 

variety of other commodities. The use of unit trains, sometimes referred to as a virtual pipeline, 

substantially reduces shipping costs and improves reliability compared to manifest rail car 

shipment. Unit trains are composed entirely of 70-100 ethanol tank cars, and are dedicated to 

shuttle back and forth to large hub terminals.AAAA Unit train receipt facilities can either be 

located at petroleum terminals (when there is sufficient room available) or at rail terminals. 

When unit train facilities are located at rail facilities, ethanol is further shipped to petroleum 

terminals by tank truck or barge. 

Unit trains can be composed at a single ethanol production plant or if a group of plants 

are not large enough to support such service individually, can be formed at a central facility 

which gathers ethanol from a number of producers. The Manly Terminal in Iowa, the first such 

ethanol gathering facility, accepts ethanol from a number of nearby ethanol production facilities 

for shipment by unit train. Regional (Class 2) railroad companies are an important link bringing 

ethanol to gathering facilities for assembly into unit trains for long-distance shipment by larger 

(Class 1) railroads. 

Ethanol is sometimes carried by multiple modes before finally arriving at the terminal 

where it is blended into gasoline. The practice of pumping ethanol directly from rail cars to 

tanks trucks for further delivery to petroleum terminals at rail terminals is an important means of 

bringing ethanol into developing markets.BBBB This practice delays the need to install substantial 

ethanol handling and storage facilities at rail receipt facilities. However, we believe that it may 

not be a viable long term solution due to the logistical demands associated with ensuring the safe 

transfer of ethanol directly from rail cars to tank trucks. We anticipate that once the ethanol 

distribution system is fully developed all ethanol shipped to rail terminals will be delivered into 

storage tanks prior to further distribution to petroleum terminals. Similarly, the practice of 

sequential delivery of gasoline and ethanol into a tank truck at the terminal so that mixing to the 

finished fuel specification takes place within the tank truck during delivery is an important 

AAAA Hub ethanol receipt terminals can be located at large petroleum terminals or at rail terminals. BBBB This practice is sometimes referred to as transloading. 

205
 
 

 

 

means of bringing ethanol to developing markets.CCCC This practice allows the blending of 

ethanol in markets prior to the installation of in-line ethanol blending equipment at petroleum 

terminals. In-line blending refers to the practice of delivering a pre-blended ethanol/gasoline 

mixture into the tank truck. Due to the improved efficiency of delivery and greater assurance of 

achieving the target blend ratio and a properly mixed final blend that accompanies in-line 

blending, we anticipate that all terminals will eventually install in-line blending equipment.DDDD 

As is the case for conventional gasoline, delivery of ethanol blends to retailers and fleets 

operators is accomplished by tank truck. Typically no changes are needed to dispense E10 at 

retail and fleet facilities. However, some retail facilities in parts of the country that have not 

used E10 in the past are projected to need to prepare their systems for E10 service primarily by 

removing water from their storage tanks. E10 can be used in conventional engines. E85 requires 

specially certified retail dispensing hardware and can only be used in flexible fuel vehicles.EEEE 

1.6.1.2 Overview of Biodiesel Distribution 

Biodiesel is currently transported from production plants to petroleum terminals by tank 

truck, manifest rail car, and by barge where it is blended with petroleum-based diesel fuel. 

Unblended biodiesel must be transported and stored in insulated/heated containers in colder 

climes to prevent gelling. Insulated/heated containers are not needed for biodiesel that has been 

blended with petroleum-based diesel fuel in low concentrations (i.e. B2, B5, B20). Biodiesel 

plants are not as dependent on being located close to feedstock sources as are corn and cellulosic 

ethanol plants.FFFF This has allowed some biodiesel plants to be located adjacent to petroleum 

terminals. Biodiesel production facilities are more geographically dispersed than ethanol 

facilities and the production volumes also tend to be smaller than ethanol facilities.GGGG These 

characteristics in combination with the smaller volumes of biodiesel that we project will be used 

under the RFS2 standards compared to ethanol allow relatively more biodiesel to be used within 

trucking distance of the production facility. However, we project that there will continue to be a 

strong and growing demand for biodiesel as a blending component in heating oil which could not 

be satisfied alone by local sources of production. It is likely that State biodiesel mandates will 

also need to be satisfied in part by out-of-State production. Fleets are also likely to continue to 

be a substantial biodiesel user, and these will not always be located close to biodiesel producers. 

Thus, we are assuming that a substantial fraction of biodiesel will continue to be shipped long 

distances to market. Downstream of the petroleum terminal, B2 and B5 can be distributed in the 

same manner as petroleum diesel and used in conventional diesel engines. 

CCCC This practice is sometimes referred to as splash blending. The term splash blending can also refer to blending 

ethanol with a gasoline blendstock that is not formulated in anticipation of the addition of ethanol. Matched 

blending refers to the practice of blending ethanol with a specially formulated gasoline blendstock that in itself can 

not typically be sold as finished gasoline. 

DDDD Most terminals are likely to install in-line ethanol blending equipment by 2013 as the use of E10 becomes 

virtually nationwide. The growth in ethanol consumption under the proposed RFS2 standards is discussed in Section 

1.7.1.2 of this DRIA. EEEE A discussion of Underwriters Laboratories certification requirements for E85 dispensing equipment can be 

found at http://ulstandardsinfonet.ul.com/outscope/outscope.asp?fn=0087a.html 

FFFF Biodiesel feedstocks are typically preprocessed to oil prior to shipment to biodiesel production facilities. This 

can substantially reduce the volume of feedstocks shipped to biodiesel plants relative to ethanol plants. 

GGGG Section 1.5.4 of this DRIA contains a discussion of our projections regarding the location of biodiesel 

production facilities. 

206
 
 

 

 

Concerns remain regarding the shipment of biodiesel by pipeline (either by batch mode 

or in blends with diesel fuel) related to the potential contamination of other products (particularly 

jet fuel), the solvency of biodiesel, and compatibility with pipeline gaskets and seals. The 

smaller anticipated volumes of biodiesel and the more dispersed and smaller production facilities 

relative to ethanol also make biodiesel a less attractive candidate for shipment by pipeline. Due 

to the uncertainties regarding the suitability of transporting biodiesel by pipeline, we assumed 

that biodiesel which needs to be transported over long distance will continue be carried by rail 

car and to a lesser extent by barge. Due to the relatively small plant size and dispersion of 

biodiesel plants, we anticipate the volumes of biodiesel that can be gathered at a single location 

will continue to be insufficient to justify shipment by unit train. To the extent that pipelines do 

eventually play a role in the distribution of biodiesel, this could tend to the reduce distribution 

costs and improve reliability in supply. 

1.6.1.3 Overview of Renewable Diesel Distribution 

We believe that renewable diesel fuel will be confirmed to be sufficiently similar to 

petroleum-based diesel fuel blendstocks with respect to distribution system compatibility. 

Hence, renewable diesel fuel could be treated in the same manner as any petroleum-based diesel 

fuel blendstock with respect to transport in the existing petroleum distribution system. 

Approximately two-thirds of renewable diesel fuel is projected to be produced at petroleum 

refineries.HHHH The transport of such renewable diesel fuel would not differ from petroleumbased diesel fuel since it would be blended to produce a finished diesel fuel before leaving the 

refinery. The other one-third of renewable diesel fuel is projected to be produced at stand-alone 

facilities located more closely to sources of feedstocks. We anticipate that such renewable diesel 

fuel would be shipped by tank trucks to nearby petroleum terminals where it would be blended 

directly into diesel fuel storage tanks. Because of its high cetane, we anticipate that all 

renewable diesel fuel would likely be blended with petroleum based diesel fuel prior to use. 

Downstream of the terminal, renewable/petroleum diesel fuel mixtures would be distributed the 

same as petroleum diesel. 

1.6.2 Shipment of Ethanol to Petroleum Terminals 

There is considerable uncertainty regarding how ethanol would be shipped to petroleum 

terminals once the market matures under the RFS2 standards. Our evaluation for this NPRM is 

based on an assessment of current trends in ethanol distribution and engineering judgment 

regarding how these trends are likely to develop over time. As discussed below, there is a lack 

of data on existing biofuels distribution facilities and capabilities as well as uncertainties 

regarding how the distribution system would respond to increased biofuels volumes. Hence, we 

were compelled to make certain assumptions based on a review of available literature and 

discussions with industry. A study was recently completed for EPA by Oakridge National 

Laboratories (ORNL) which modeled the transportation of ethanol from production/import 

facilities to petroleum terminals.442 The ORNL model optimizes freight flows over the rail, 

marine, and road distribution net while addressing the use of multiple shipping modes. We plan 

HHHH A discussion of the projected location of renewable diesel fuel production facilities is contained in Section 

1.5.4 of this DRIA. Renewable diesel fuel produced at petroleum refineries would either be co-processed with crude 

oil or processed in separate units located at the refinery for blending with other diesel blendstocks at the refinery. 

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to use the results of the ORNL study to adjust our projections regarding how ethanol would be 

shipped to petroleum terminals for the final rule, particularly with respect to how much ethanol 

can be shipped directly by tank truck from production facilities and the relative roles of unit 

train, manifest rail, and barge in the distribution chain. 

USDA estimated that approximately 30% of direct ethanol deliveries from production 

facilities to petroleum terminals in 2005 were accomplished by tank truck.443 As the total 

volume of ethanol used increases and ethanol is shipped to more markets that are distant from 

production centers (e.g. in the Southeast), we expect that shipments by rail would increase and 

direct tank truck shipments to petroleum terminals to decrease to 20%. We believe that for 

transportation distances of less than 200 miles all shipments of ethanol to petroleum terminals 

would be by tank truck. Transportation by tank truck for a distance over 200 miles typically 

requires an overnight layover which significantly increases costs. Thus, we anticipate that only a 

limited volume of ethanol would be transported by tank truck for a distance of between 200 and 

300 miles and essentially none over 300 miles once the market matures. 

The amount of ethanol that can be shipped directly by truck from production 

plants/import centers to petroleum terminals is a function of the relative location of production 

plants/import centers to petroleum terminals, the ethanol production/import capacity of 

production/import facilities, and the potential ethanol demand at each terminal. Ethanol demand 

at a given terminal is governed by ethanol cost considerations relative to gasoline, State ethanol 

use incentives, the penetration of E85 into the market, and the total gasoline motor vehicle 

demand served the terminal. As an input to the ORNL study, we provided our estimates of the 

location of ethanol production plants and imports centers as well as our estimate of how much 

ethanol would be used on a State-by-State basis.IIII ORNL allocated ethanol usage to terminals 

located within a given State on a population weighted basis given the terminals service areas. 

Thus, we anticipate that the ORNL study will provide an enhanced estimate of the volume of 

ethanol that could be shipped to petroleum terminals by tank truck. 

Where shipping distances are greater than 300 miles, we assumed that unit train would be 

the preferred means of transport where ethanol volumes are sufficiently large. We estimated that 

shipment by manifest rail car would continue to be an important means of bringing ethanol to a 

subset of petroleum terminals that could not support the receipt of unit trains or otherwise 

receive ethanol from hub terminals that are equipped for unit train receipt.JJJJ We assumed that 

10% of ethanol production/imports would be shipped to petroleum terminals by manifest rail car. 

We also assumed that shipment by barge would continue to be a significant means of moving 

ethanol from certain hub terminals in the Northeast that receive ethanol via unit train to other 

Northeast terminals. We anticipate that the analysis of the relative merits of the various modes 

for long distance transportation of ethanol inherent in the ORNL modeling work will provide 

additional basis for us to adjust our estimates of the relative extent to which the different modes 

would be utilized. 

IIII A discussion of our estimates of where ethanol would be used under the RFS2 standards is contained is contained 

in Section 1.7 of this DRIA. A discussion of our estimates of where ethanol would be produced / imported in 

response to the RFS2 standards is contained in Section 1.5 of this DRIA. 

JJJJ Manifest rail car shipment refers to the practice of shipping several ethanol rail cars in a train that is composed of 

rail cars carrying various products. 

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The extent to which multiple shipping links are needed to bring ethanol to petroleum 

terminal depends on two principal factors. The first is whether the ethanol production facility is 

configured to support shipment by unit train. The Manly unit train gathering facility was 

constructed to serve a number of ethanol production plants that were either too small to support 

unit train service themselves or otherwise chose not to install a unit train shipping facility. Our 

analysis indicates that the vast majority of new ethanol production plants will have a production 

capacity of at least 70 million gallons per year (MGY).KKKK The current industry rule of thumb 

is that ethanol production plants need to have a production capacity of approximately 80 million 

MGY to support the installation of a unit train loading facility. This appears to be based on the 

assumption of an ~2 week cycle time for unit train rail cars which we believe is widely accepted 

for ethanol shipments by unit train, and the use of a 100 car unit train.LLLL A 70 MGY ethanol 

plant could only support the shipment of a 100 car unit train every 17 days, resulting in a 20% 

less efficient use of rail cars compared to a 2 week cycle. Rail car lease costs are estimated at 

$750 per month per car and thus can constitute a significant fraction to total ethanol freight costs. 

Ethanol unit trains range between a minimum of 70 to a maximum of 100 rail cars. By 

reducing the number of cars in a unit train to 90, a 70 MGY ethanol could support a two week 

rail car cycle time. Thus, we believe that a 70 MGY ethanol plant should be able to support the 

installation of a unit train shipping facility. It is also likely that the level of ethanol demand at 

some downstream ethanol unit train receipt facilities would be better suited to the receipt of 

smaller sized unit train than 100 rail cars. We anticipate that all ethanol production facilities of 

sufficient scale to support unit train service other than those currently served by the Manly 

facility will choose to install such service due to the associated market advantages. We assume 

that the new production plants that are too small to support installation of unit train service 

would primarily serve local markets by tank truck and ship the remainder of their production to 

terminal by manifest rail car. Based on the above discussion, we are assuming that no additional 

unit train rail gathering facilities would be needed. Hence, we are projecting that no additional 

manifest rail car shipments to form unit trains would be needed as a result of the RFS2 standards. 

The second factor influencing the need for secondary shipments of ethanol is the extent to 

which ethanol will be shipped to hub terminals via unit train for further distribution to satellite 

terminals and the degree to which such hub terminals are located at petroleum terminals as 

opposed to being located at rail terminals. A significant challenge facing terminals and one that 

is currently limiting the volume of ethanol that can be used is the ability to receive ethanol by 

rail. Only a small fraction of petroleum terminals currently have rail receipt capability and a 

number likely have space constraints (particularly those in the Northeast) or are located too far 

from the rail net to allow installation of such capability. 

There is significant uncertainty regarding the extent to which additional rail receipt 

facilities can be accommodated at petroleum terminals. This is true regarding the installation of 

manifest rail receipt capability as well as unit train receipt capability. Comprehensive data on 

the current rail receipt capability at petroleum terminals or on logistical considerations regarding 

the addition of such capability does not exist. For the purpose of our analysis, we are assuming 

KKKK A discussion of the projected locations of ethanol production facilities can be found in chapter 1.5 of this 

DRIA. 

LLLL Rail car cycle time for shipment of ethanol by manifest rail car is typically one month. 

209
 
that 50% of new ethanol unit train facilities would be located at petroleum terminals and 50% 

would be located at rail terminals. The ORNL study estimated that all new ethanol rail receipt 

capability would be installed at existing rail terminals given the limited ability to install such 

capability at petroleum terminals. We intend to review our estimates regarding the location of 

the additional ethanol rail receipt facilities for the final rule in light of the ORNL study. 

Ethanol not blended at hub petroleum terminals or shipped to rail terminals would need to 

be further shipped to smaller “satellite” petroleum terminals. We assume that 20% of the ethanol 

received by unit train at a petroleum terminal would be blended into gasoline at that terminal. 

The remaining 80% would be further shipped to satellite petroleum terminals. We are assuming 

that 90% of such secondary shipments would be done by tank truck and 10% by barge. We also 

assumed the ethanol shipped by unit train to rail terminals would be shipped to petroleum 

terminals by the same means. At one ethanol unit train hub facility at a rail terminal, there are 

plans to ship ethanol by a short pipeline to a nearby petroleum terminal. We anticipate that this 

practice will expand as the industry matures. However, due to a lack of information on the 

extent to which short pipelines could feasibly play such a role, and to provide a conservatively 

high estimate of ethanol distribution costs, we assumed that all secondary shipments from rail 

terminals would be by tank truck and barge. We anticipate that the results from the ORNL 

modeling work will provide the means for us to modify our estimates of the extent to which 

secondary shipments of ethanol will need to be made from unit train receipt facilities at 

petroleum terminals and the breakdown of the transportation modes that would be used for 

secondary shipments from all ethanol unit train receipt facilities (including those at rail 

terminals). 

Our estimate of how ethanol would be shipped to petroleum terminals in 2022 is 

summarized in Table 1.6-1. A discussion of ethanol freight costs can be found in Section 4.2 of 

this DRIA. 

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Table 1.6-1. Estimated 2022 Ethanol Shipping Volumes by Link/Mode of Shipment 

Shipping Link / Shipment Mode 

Million Gallons of Ethanol 

Shipped Annually in 2022 

Total Volume 

Change from 

Reference 

Caseb 

From production facilities by manifest 

rail car and tank truck to unit train 

gathering facility 

1,000 0 

From production/import facility to 

petroleum terminal by tank truck 

6,830 

(20% production/import vol.) a 4,190 

From production or unit train 

gathering facility to petroleum 

terminal by unit train 

11,950 

(35% production/import vol.) a 7,340 

From production/import facility to 

petroleum terminal by manifest rail 

car 

3,410 

(10% production/import vol.) a 2,100 

From production or unit train 

gathering facility to rail terminal by 

unit train 

11,950 

(35% production/import vol.) a 7,340 

From petroleum terminals that receive 

ethanol by unit train by barge to 

satellite petroleum terminals 

960 590 

From petroleum terminals that receive 

ethanol by unit train by tank truck to 

satellite petroleum terminals 

8,600 5,280 

From rail terminals that receive 

ethanol by unit train or port facilities 

that receive imported ethanol by barge 

to satellite petroleum terminals 

1,190 730 

From rail terminals that receive 

ethanol by unit train by tank truck to 

satellite petroleum terminals 

10,750 6,600 

a

 34.14 BGY of ethanol would be produced/imported by 2022 to satisfy the RFS2 standards. 

b

 Total – the AEO 2007 based 2022 reference case absent the RFS2 standards. Our ethanol consumption projections 

under RFS2 standards are discussed in Section 1.7.1 of this DRIA.
 

1.6.3 Shipment of Biodiesel to Petroleum Terminals 

We projected the volumes of biodiesel that would be used on a State-by-State basis to 

meet anticipated State biodeisel mandates/incentives and the estimated demand for biodiesel as a 

blending component in heating oil.MMMM Using the estimated locations of biodiesel production 

MMMM A discussion of our estimates regarding the location of biodiesel production facilities and centers of biodiesel 

demand is contained in Section 1.5.4 of this DRIA. 

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facilities and their volumes, we evaluated the most efficient means of meeting this projected 

demand while minimizing shipping distances (and cost). The remaining biodiesel production 

volume that was not taken up meeting this demand was assumed to be used in the same State it 

was produced to the extent that the State’s diesel fuel did not already contain 5% biodiesel. We 

believe that this should provide a somewhat conservatively high estimate of biodiesel 

distribution costs since biodiesel might be used in excess of 5% even absent a State mandate. If 

the State was already saturated with 5% biodiesel, the remaining volume was assumed to be 

shipped out of State within a 1,000 mile shipping distance. A 1,000 mile shipping distance was 

selected to ensure that all biodiesel not used to satisfy a State mandate or for bio-heat could find 

a market. It is likely that some fraction would not need to travel quite as far. Therefore, this 

assumption is also likely to result in a conservatively high estimate of biodiesel freight costs. It 

was assumed that biodiesel production volumes will continue to be insufficiently concentrated to 

justify shipment by unit train. Where distances are beyond 300 miles, shipment by manifest rail 

was assumed to be the preferred option other than in cases on the East coast where there were 

apparent barge routes from production to demand centers. In no case was it assumed that 

biodiesel would need to be shipped by multiple modes prior to delivery at the petroleum terminal 

where it is blended with petroleum-based distillate fuel. 

Table 1.6-2 contains our estimate of how biodiesel would be shipped to petroleum 

terminals in 2022. Additional discussion on our estimate of how biodiesel used to comply with 

the RFS2 standards would be transported to petroleum terminals can be found in Section 4.2 of 

this DRIA on biodiesel freight costs. 

Table 1.6-2. 

Estimated 2022 Biodiesel Shipping Volumes by Link/Mode of Shipment 

Shipping Link / Shipment 

Mode 

Million Gallons of Biodiesel Shipped Annually in 2022 

Total Volume Change from 

Reference Case b 

From production facility to 

petroleum terminal by tank 

truck 

696 

(86% of total production volume) a 369 

From production facility to 

petroleum terminal by 

manifest rail car 

109 

(13% of total production volume) a 5 

From production facility to 

petroleum terminal by barge 

5 

(1% of total production volume) a 3 

a

 810 MGY of biodiesel would be produced in 2022 to satisfy the RFS2 

b

 Total – the AEO 2007 based 2022 reference case absent the RFS2 standards. Our ethanol consumption projections 

under RFS2 standards are discussed in Section 1.7.2 of this DRIA. 

1.6.4 Shipment of Renewable Diesel to Petroleum Terminals 

We project that the distribution of the 2/3 of renewable diesel fuel (251 MGY in 2022, or 

potentially earlier) produced to petroleum terminals would be transparent with respect the impact 

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on the distribution system.NNNN We assume that the remaining 125 MGY would be shipped to 

nearby terminals or petroleum refineries (within a 200 mile radius) by tank truck to be blended 

with petroleum-based diesel fuel. 

1.6.5 Changes in Freight Tonnage Movements Due to RFS2 

In order to evaluate the magnitude of the challenge to the distribution system up to the 

point of receipt at the terminal, we compared the growth in freight tonnage for all commodities 

from the AEO 2007 reference case to the growth in freight tonnage under the RFS2 standards in 

which ethanol increases, as does the feedstock (corn) and co-products (distillers grains). We did 

not include a consideration of the transportation of cellulosic feedstocks in this analysis. The 

distribution of cellulosic feedstocks is discussed in Section 1.3.3 of this DRIA. For purposes of 

this analysis, we focused on only the ethanol portion of the renewable fuel goals for ease of 

calculation and because ethanol represents the vast majority of the total fuel. The resulting 

calculations serve as an indicator of changes in freight tonnages associated with increases in 

renewable fuels. We calculated the freight tonnage for the total of all modes of transport as well 

as the individual cases of rail, truck, and barge. 

In calculating the AEO 2007 reference case percent growth rate in total freight tonnage, 

we used data compiled by the Federal Highway Administration to calculate the tonnages 

associated with these commodities. We then calculated the growth in freight tonnage for 2022 

under the RFS2 standards and compared the difference with the AEO 2007 reference case. The 

comparisons indicate that across all transport modes, the incremental increase in freight tonnage 

of ethanol and accompanying feedstocks and co-products associated with the increased ethanol 

volume under the RFS2 standards are small. The percent increase for total freight across all 

modes (rail, barge, truck, and pipeline) by 2022 is 0.9 percent. Because pipelines currently do 

not carry ethanol, and the increase in volume of ethanol displaces a corresponding volume of 

gasoline, pipelines showed a decrease in tonnage carried. The displaced gasoline also resulted in 

some decrease in tonnage in other modes that slightly reduced the overall increases in tonnage 

reflected in the totals. 

To further evaluate the magnitude of the increase in freight tonnage under the RFS2 

standards, we calculated the portion of the total freight tonnage from the rail, barge, and truck 

modes made up of ethanol-related freight for both the AEO 2007 based 2022 reference case and 

control cases. The freight associated with ethanol constitutes only a very small portion of the 

total freight tonnage for all commodities. Specifically, ethanol freight represents approximately 

0.5 and 2.5% of total freight for the AEO 2007 based 2022 reference case and RFS2 standards 

case, respectively. For the rail mode only, the fright associated with ethanol represents 

approximately 3.2% of the total for the RFS2 case. The results of this analysis, suggest that it 

should be feasible for the distribution infrastructure upstream of the terminal to accommodate the 

additional freight associated with this RFS2 standards especially given the lead time available. 

Specific issues related to transportation by rail, barge, and tank truck are discussed in the 

NNNN A discussion of the projected location of renewable diesel fuel production facilities is contained in Section 

1.5.4 of this DRIA. Renewable diesel fuel produced at petroleum refineries would either be co-processed with crude 

oil or processed in separate units located at the refinery for blending with other diesel blendstocks at the refinery. 

213
 
 

 

following sections. Our estimate of the percent changes in total freight tonnage by mode for 

2022 required to satisfy the RFS2 standards is contained in Table 1.6-3. 

Table 1.6-3. 

Estimate of Percent Changes in Total Freight Tonnage by Mode for 2022 

Reference 

Case RFS2 case % change a 

Total freight tonnage for all commodities 

(thousands of tons) 25,161,284 25,673,207 1.99% 

Portion of total freight tonnage made up of ethanolrelated freight (thousands of tons) 135,018 643,418 

Percent ethanol related freight to total freight 0.54% 2.51% 

Total freight tonnages for specific transport 

modes (thousands of tons) 

Reference 

Case RFS2 case % change a 

Truck 16,521,816 16,884,804 2.15% 

Rail 2,552,227 2,636,173 3.18% 

Water 714,483 734,292 2.70% 

Pipeline 5,372,758 5,417,937 0.83% 

a

Total – the AEO 2007 based 2022 reference case absent the RFS2 standards. Our ethanol consumption projections 

under RFS2 standards are discussed in Section 1.7.1 of this DRIA. 

We intend to incorporate the results of the recently completed study by Oak Ridge 

National Laboratories (ORNL) on the potential constraints in ethanol distribution into the 

analysis for the final rule. The ORNL study concluded that the increase in ethanol transport 

would have minimal impacts on the overall transportation system. However, the ORNL study 

did identify localized areas where significant upgrades to the rail distribution system would 

likely be needed. 

1.6.6 Rail Transportation System Accommodations 

Many improvements to the freight rail system will be required in the next 15 years to 

keep pace with the large increase in the overall freight demand. Much of the projected increase 

in rail freight demand is associated with the expected rapid growth of inter-modal rail transport. 

Most of the needed upgrades to the freight rail system are not specific to the transport of 

renewable fuels and would be needed irrespective of today’s proposed rule. The modifications 

required to satisfy the increase in demand include upgrading tracks to allow the use of heavier 

trains at faster speeds, the modernization of train braking systems to allow for increased traffic 

on rail lines, the installation of rail sidings to facilitate train staging and passage through 

bottlenecks. 

214
 
 

 

 

Some industry groupsOOOO and governmental agencies in discussions with EPA, and in 

testimony provided for the Surface Transportation Board (STB) expressed concerns about the 

ability of the rail system to keep pace with large increase in demand even under the AEO 2007 

reference case (27% by 2022). For example, the electric power industry has had difficulty 

keeping sufficient stores of coal in inventory at power plants due to rail transport difficulties and 

has expressed concerns that this situation will be exacerbated if rail congestion worsens. One of 

the more sensitive bottleneck areas with respect to the movement of ethanol from the Midwest to 

the East coast is Chicago. The City of Chicago commissioned its own analysis of rail capacity 

and congestion, which found that the lack of rail capacity is “no longer limited to a few choke 

points, hubs, and heavily utilized corridors.” Instead, the report finds, the lack of rail capacity is 

“nationwide, affecting almost all the nation’s critically important trade gateways, rail hubs, and 

intercity freight corridors.” This is due, in part, to the lack of critical linkages between the 27 

major rail yards located in the Chicago-land area. 

To help improve east-west rail connections through the city, federal, state, and local 

officials announced an agreement in 2006 to invest $330 million over three-years in city-wide 

rail infrastructure designed to improve the flow of rail traffic through the area. The State of 

Illinois, the City of Chicago, and seven Class I rail carriers, as well as Amtrak and Metra, the 

area's transit system, also committed $1.5 billion in improvements. Chicago is the largest rail 

hub in the country with more than 1,200 trains passing through it daily carrying 75% of the 

nation's freight valued at $350 billion; 37,500 rail freight cars pass through the city every day 

projected to increase to 67,000 by 2020. Chicago is the only city where all six Class I railroads 

converge and exchange freight. The plan calls for the creation of five rail corridors to aid in 

alleviating the bottleneck. 

Significant private and public resources are focused on making the modifications to the 

rail system to cope with the increase in demand. Rail carriers report that they typically invest 16 

to 18 billion dollars a year in infrastructure improvements.444 Substantial government loans are 

also available to small rail companies to help make needed improvements by way of the Railroad 

Rehabilitation and Improvement Finance (RRIF) ProgramPPPP, administered by Federal Railroad 

Administration (FRA), as well as Section 45G Railroad Track Maintenance Credits, offered by 

the Internal Revenue Service (IRS). 

The RRIF program offers loans to railroads for a variety of capital purposes including 

track and equipment rehabilitation at “cost of money” for 25 year terms. Typically, short line 

railroads cannot secure this kind of funding in the private markets. Under this program, FRA is 

OOOO Industry groups include the Alliance of Automobile Manufacturers, American Chemistry Council, and the 

National Industrial Transportation League; governmental agencies include the Federal Railroad Administration 

(FRA), the General Accountability Office (GAO), and the American Association of State Highway Transportation 

and Officials (AASHTO). Testimony for the STB public hearings includes Ex Parte No. 671, Rail Capacity and 

Infrastructure Requirements and Ex Parte No. 672, Rail Transportation and Resources Critical to the Nation’s 

Energy Supply.

PPPP The RRIF program was established by the Transportation Equity Act for the 21st Century (TEA-21) and 

amended by the Safe Accountable, Flexible and Efficient Transportation Equity Act: a Legacy for Users 

(SAFETEA-LU). RRIF funding may be used to: acquire, improve, or rehabilitate intermodal or rail equipment or 

facilities, including track, components of track, bridges, yards, buildings and shops; refinance outstanding debt 

incurred for the purposes listed above; and develop or establish new intermodal or railroad facilities. 

215
 
 

 

 

authorized to provide direct loans and loan guarantees up to $35.0 billion. Up to $7.0 billion is 

reserved for projects benefiting freight railroads other than Class I carriers. However, the 

program has lent less than $650 million to non-passenger rail carriers since 2002, according to 

the FRA/RRIF website. 

The American Association of State Highway Transportation Officials (AASHTO) 

estimates that between $175 billion and $195 billion must be invested over a 20-year period to 

upgrade the rail system to handle the anticipated growth in freight demand, according to the 

report’s base-case scenario.445 The report suggests that railroads should be able to provide up to 

$142 billion from revenue and borrowing, but that the remainder would have to come from other 

sources including, but not limited, to loans, tax credits, sale of assets, and other forms or publicsector participation. Given the reported historical investment in rail infrastructure, it may be 

reasonable to assume that rail carriers would be able to manage the $7.1 billion in annual 

investment from rail carriers that AASHTO projects would be needed to keep pace with the 

projected increase in freight demand. 

The Association of American Railroads (AAR) estimates446 that meeting the increase in 

demand for rail freight transportation will require an investment in infrastructure of $148 billion 

(in 2007 dollars) over the next 28 years and that Class I railroads' share is projected to be $135 

billion, with $13 billion projected for short line and regional freight railroads. 

In testimony before the STB, Class I railroads committed to working with all parties in 

the ethanol logistical chains to provide safe, cost-effective, and reliable ethanol transportation 

services as well as to resolve past freight rail capacity difficulties. Presumably, this commitment 

extends to the projected three-percent increase in overall freight tonnage envisioned herein. 

However, the Government Accounting Office (GAO) found that it is not possible to 

independently confirm statements made by Class I rail carriers regarding future investment 

plans.QQQQ In addition, questions persist regarding allocation of these investments, with the 

Alliance of Automobile Manufacturers, American Chemistry Council, National Industrial 

Transportation League, and others expressing concern that their infrastructural needs may be 

neglected by the Class I railroads in favor of more lucrative intermodal traffic. Moreover, the 

GAO has raised questions regarding the competitive nature and extent of Class I freight rail 

transport. This raises some concern that providing sufficient resources to facilitate the transport 

of increasing volumes of ethanol and biodiesel might not be a first priority for rail carriers. In 

response to GAO concerns, the Surface Transportation Board (STB) agreed to undertake a 

rigorous analysis of competition in the freight railroad industry.RRRR 

QQQQ The railroads interviewed by GAO were generally unwilling to discuss their future investment plans with the 

GAO. Therefore, GAO was unable to comment on how Class I freight rail companies are likely to choose among 

their competing investment priorities for the future, including those of the rail infrastructure, GAO testimony Before 

the Subcommittee on Surface Transportation and Merchant Marine, Senate Committee on Commerce, Science, and 

Transportation, U.S. Senate, Freight Railroads Preliminary Observations on Rates, Competition, and Capacity 

Issues, Statement of JayEtta Z. Hecker, Director, Physical Infrastructure Issues, GAO, GAO-06-898T Washington, 

D.C.: June, 21, 2006). 

RRRR GAO, Freight Railroads: Industry Health Has Improved, but Concerns about Competition and Capacity 

Should Be Addressed, GAO-07-94 (Washington, D.C.: Oct. 6, 2006); GAO, Freight Railroads: Updated 

Information on Rates and Other Industry Trends, GAO-07-291R Freight Railroads (Washington, D.C.: Aug. 15, 

216
 
 

Given the broad importance to the U.S. economy of meeting the anticipated increase in 

freight rail demand, and the substantial resources that seem likely to be focused on this cause, we 

believe that overall freight rail capacity would not be a limiting factor to the successful 

implementation of the biofuel requirements under the RFS2 standards. Evidence from the recent 

ramp up of ethanol use has also shown that rail carriers are enthusiastically pursuing the 

shipment of ethanol, although there is some indication that the Class I freight rail industry will 

expect ethanol to primarily be shipped by unit train from facilities that assemble unit trains 

which are developed and paid for by the ethanol industry. 

Class 2 railroads have been particularly active in gathering sufficient numbers of ethanol 

cars to allow Class 1 railroads to ship ethanol by unit train. Based on this recent experience, we 

believe that ethanol will be able to compete successfully with other commodities in securing its 

share of freight rail service. 

While many changes to the overall freight rail system are expected to occur irrespective 

of today’s proposed rule, a number of ethanol-specific modifications will be needed. For 

instance, a number of additional rail terminals are likely to be configured for receipt of unit trains 

of ethanol for further distribution by tank truck or other means to petroleum terminals. Each 

ethanol rail car holds approximately 29,500 gallons.SSSS Thus, each 100 car unit train would 

deliver 2,950,000 gallons of ethanol. We believe that it would be reasonable for an ethanol unit 

train facility to accept a unit train approximately every 3 days. Thus, we assumed that each unit 

train facility could handle 120 unit trains per year which translates to 354 million gallons per 

year for each unit train facility. Based on the volumes we projected to be transported by unit 

train in Table 1.6-1 of this DRIA, this translates to a total of 68 unit train receipt facilities for all 

ethanol used by 2022 and 42 such facilities to handle the volume attributed to the RFS2 

standards alone (relative to the AEO 2007 based 2022 reference case). As discussed in Section 

1.6.2 of this DRIA, we are assuming that half of the unit train receipt facilities needed to cope 

with the additional volumes of ethanol projected to be used to comply with the RFS2 standards 

would be constructed at petroleum terminals (i.e. 21) and half would be constructed at rail 

terminals. 

As discussed in Section 1.6.2 of this DRIA, the recently completed ORNL study 

estimated that all new ethanol rail receipt capability would be installed at existing rail terminals 

given the limited ability to install such capability at petroleum terminals. We intend to review 

our estimates regarding the location of the additional ethanol rail receipt facilities for the final 

rule in light of the ORNL study. 

The placement of ethanol receipt facilities at rail terminals would be particularly useful in 

situations where petroleum terminals would find it difficult or impossible to install their own 

ethanol rail receipt capability. If the projected number of ethanol rail receipt facilities can not be 

accommodated at petroleum terminals then additional ethanol unit train receipt facilities would 

2007). STB's final report, entitled Report to the U.S. STB on Competition and Related Issues in the U.S. Freight 

Railroad Industry, is expected to be completed November, 1, 2008. SSSS Ethanol cars have a nominal capacity of 30,000 gallons. 

217 
 

 

 

be needed at rail terminals.TTTT We do not have information on the extent to which there is 

available space at rail terminals to accommodate ethanol receipt facilities. However, the 

majority of the required space would be needed to locate the train itself, the facilities for which 

would already be in place at rail terminals. We expect the other space requirements for truck 

loading and storage tanks would be relatively modest and could be accommodated at a sufficient 

number of rail terminals to meet the projected need. The need for long-term demand to be 

established prior the construction of such facilities would likely mean that the needed facilities 

would at best come on line in a just-in-time basis. We anticipate that ethanol storage will 

typically be installed at rail terminal ethanol receipt hubs over the long run. However, the ability 

to rely on transloading while ethanol storage facilities at rail terminal ethanol receipt hub 

facilities are constructed would help to ease the introduction of downstream rail receipt 

capability. 

We anticipate that rail terminals would only install the minimum amount of ethanol 

storage capacity in order to maintain steady deliveries by unit train. This is based on the 

assumption that petroleum terminals would be the ones to maintain an inventory buffer to ensure 

a steady supply of ethanol to blend with gasoline.UUUU Under this model, rail terminals would 

empty their ethanol storage by shipment to petroleum terminals as soon as possible. Therefore, 

we believe that it not appropriate to apply the formula we used to estimate the ethanol storage 

tank requirements at petroleum terminals which is based on the premise of always having ethanol 

on hand even the face of temporary upsets in delivery. Each delivery of an ethanol unit train 

contains 2.95 million gallons. To ensure that a rail terminal is always ready to unload an ethanol 

unit train, we believe that it would be sufficient to size the ethanol storage capacity at 6 times 

unit train capacity (17.7 million gallons). This should allow for a reasonable amount of 

irregularity in both the receipt of ethanol by unit train into rail terminals and the delivery of 

ethanol from rail terminal storage to petroleum terminals. For all of the projected 21 rail 

terminal ethanol unit train receipt facilities, this totals 371.7 million gallons or 8.85 million 

barrels of ethanol storage. All of the ethanol storage at rail terminals would need to be new 

construction, since we do not believe there would be existing tankage at rail terminals that could 

be converted to ethanol service. 

A substantial number of additional rail cars would be needed to transport the volumes of 

ethanol and to a lesser extent biodiesel that are projected to be used in response to the RFS2 

standards. Our estimate of the number of rail cars needed is based on the an assumed cycle time 

of 2 weeks for shipment by unit train and one month for shipment by manifest rail car which we 

believe is conservatively high given current industry experience.VVVV Biodiesel rail cars are 

typically somewhat smaller than those used for ethanol. We assumed a deliverable volume of 

25,600 gallons for biodiesel rail cars and 29,000 for ethanol rail cars. We estimated the number 

of rail cars that would be needed to transport ethanol and biodiesel using the projected volumes 

of ethanol and biodiesel that we expect would be shipped by unit train and manifest rail (see 

TTTT As discussed in Section 1.6.6 of this DRIA, we estimate that 148 additional manifest rail receipt facilities would 

be constructed at petroleum terminals to handle the volumes of ethanol that we project would be shipped by
 

manifest rail. 

UUUU A discussion of the projected demand for ethanol storage is contained in Section 1.6.6 of this DRIA. VVVV Rail car cycle time refers to the time needed to complete one delivery and return to the origin including the 

time to prepare for the next shipment. 

218
 
 

Tables 1.6-1 and 1.6-2) and the assumed rail car volumes and cycle times. As discussed in 

Section 1.6.1.3, we project that renewable diesel fuel would not need to be transported by rail. 

Our estimate of the number of rail cars to transport the volume of renewable fuels projected to be 

used by 2022 to satisfy the RFS2 standards is contained in Table 1.6-4. 

Table 1.6-4. 

Estimated Number of Rail Cars Needed by 2022 for Shipment of Ethanol and Biodiesel 

Number of Rail Cars Needed to Transport Ethanol 

Total Volume Volume Attributed to RFS2 Standards a 

Ethanol Rail Cars 43,398 26,644 

Biodiesel Rail Cars 665 353 

Ethanol & Biodiesel Rail Cars 44,063 26,997 a

 Total – the AEO 2007 based 2022 reference case absent the RFS2 standards 

Our analysis of ethanol and biodiesel rail car production capacity indicates that access to 

these cars should not represent a serious impediment to meeting the requirements under the 

RFS2 standards. Ethanol tank car production has increased approximately 30% per year since 

2003, with over 21,000 tank cars expected to be produced in 2007. To accommodate the 

increased demand for ethanol tank cars, rail car producers converted existing boxcar production 

facilities to tank production facilities and brought on additional work shifts to adjust to rapidly 

changing to market conditions. 

1.6.7 Marine Transportation System Accommodations

 The American Waterway’s Association has expressed concerns about the need to 

upgrade the inland waterway system in order to keep pace with the anticipated increase in overall 

freight demand. The majority of these concerns have been focused on the need to upgrade the 

river lock system on the Mississippi river to accommodate longer barge tows and on dredging 

inland waterways to allow for movement of fully loaded vessels. We do not anticipate that a 

substantial fraction of renewable/alternative fuels will be transported via these arteries. Thus, we 

do not believe that the ability to ship ethanol/biodiesel by inland marine will represent a serious 

barrier to the implementation of implementation of the requirements under RFS2 standards. 

Substantial quantities of the corn ethanol co-product dried distiller grains (DDG) is expected to 

be exported from the Midwest via the Mississippi river as the US demand for DDG becomes 

saturated. We anticipate that the volume of exported DDG would take the place of corn that 

would be shifted from export to domestic use in the production of ethanol. Thus, we do not 

expect the increase in DDG exports to result in a substantial increase in river freight traffic. 

A number of new barges would be needed to transport the volumes of ethanol and to a 

lesser extent biodiesel that are projected to be used in response to the RFS2 standards. We 

assumed the use of tank barges with a carrying capacity of 10,000 barrels (42,000 gallons). We 

understand that the tank barge industry is trending towards the use of tank barges with a carrying 

capacity of 30,000 barrels. Thus, our assumed use of 10,000 barrel barges may overstate the 

number of barges that would be needed. We assumed a 2 week barge cycle time, which we 

219
 
 

 

 

 

 

 

 

understand to be typical given the markets where we expect most barge shipments would 

WWWW occur.

We estimated the number of barges that would be needed to transport ethanol and 

biodiesel using the projected volumes of ethanol and biodiesel that we expect would be shipped 

by barge (see Tables 1.6-1 and 1.6-2), and the assumed barge volume and cycle time. As 

discussed in Section 1.6.1.3, we project that renewable diesel fuel would not need to be 

transported by barge. Our estimate of the number of barges to transport the volume of renewable 

fuels projected to be used by 2022 to satisfy the RFS2 standards is contained in Table 1.6-5. 

Table 1.6-5. 

Estimated Number of Barges Needed by 2022 for Shipment of Ethanol and Biodiesel 

Number of Barges Needed to Transport 

Ethanol and Biodiesel 

Total Volume Volume Attributed to RFS2 Standards a 

Ethanol Barges 213 131 

Biodiesel Barges 20 11 

Ethanol & Biodiesel Barges 233 142 a Total – the AEO 2007 based 2022 reference case absent the RFS2 standards 

The U.S. tank barge fleet currently numbers 3,600.447 In 2004, over 500 barges of all 

types were added to the U.S. barge fleet. Given the gradual ramp up in demand for shipment of 

biofuels by barge over time, we believe that the addition to the fleet of the 142 barges estimated 

to be needed to transport biofuels can be accommodated by the industry. 

As discussed in Section 1.5.2.2 of this DRIA, we project that imports of ethanol will 

ramp up significantly to 3.14 BGY by 2022.XXXX To estimate which ports would receive ethanol 

imports we gave priority to ports that have a history of receiving ethanol imports from Brazil and 

Caribbean Basin Initiative CountiesYYYY according to company-level historical fuel import data 

from the Energy Information Administration (EIA).448 Additional ports were selected from 

those that have a history of receiving finished gasoline imports. Ports were selected in States 

that could not satisfy their internal ethanol demand from in-State production and from those ports 

that were closest to large demand centers. We estimate that a total of 28 ports would receive 

imported ethanol by 2022 (see Figure 1.6-1).ZZZZ We estimate that the 12 ports which did not 

WWWW We believe most barge shipments of biofuels would originate and terminate in the Northeast. Cycle time 

refers to the time needed to complete one delivery and return to the origin including the time to prepare for the next 

shipment. 

XXXX See chapter 1.5.2 of this DRIA for a discussion of our projection of ethanol imports. YYYY Caribbean Basin Initiative countries receive special exemptions from U.S. ethanol import tariffs (See Section 

1.5 of this DRIA regarding the source of ethanol imports and for additional discussion regarding how we estimated 

where ethanol imports would enter the U.S.. 

ZZZZ Paulsboro/Gloucester NJ were treated as separate ports for purposes of our capital cost analysis but were treated 

as a single port for the purposes of our ethanol freight costs analysis due to their close proximity. The same is true 

for Belfast and Searsport ME. 

220
 
receive ethanol in the past would need to install/modify ethanol receipt facilities including 

piping, pumps, vapor handling systems, and ethanol storage tanks while ports that had received 

ethanol in the past would primarily need to install additional ethanol storage tanks. We believe 

that all of these ports also serve as petroleum terminals. Hence, the need for additional ethanol 

storage as well as outgoing ethanol shipping facilities would be covered within the context of our 

estimation of the upgrades needed to petroleum terminal facilities. 

Figure 1.6-1. Projected Ethanol Import Locations and Volumes (MGY) in 2022 

Seattle, WA (73) 

Vancouver, WA (16) 

Portland, OR (13) 

San Francisco (25) 

& Selby, CA (81) 

Los Angeles, CA (539) 

Honolulu, HI (19) 

Port Arthur (24), 

Houston (424), & 

Brownsville, TX (34) 

Tampa, FL (121) 

Port Everglades, FL (179 ) 

Port Canaveral, FL (64) 

Jacksonville, FL (106) 

Savannah, GA (198) 

Charleston, SC (79) 

Wilmington, NC (153) 

Philadelphia, PA (246) 

Newark (56), 

Perth Amboy (102), & 

Paulsboro, NJ (39) 

New York, NY (299) 

New Haven (36) & 

Bridgeport, CT (42) 

Providence, RI (24) 

Boston, MA (143) 

Belfast/Searsport (<1) 

& Portland, ME (1) 

Total U.S. Ethanol Imports in 2022 = 3,140 Million Gallons 

Note: We are considering adding Hampton Roads VA, and Baltimore MD to the list of future ethanol import 

locations and may adjust our analysis for the final rule accordingly. This figure is the same as figure 1.5-13 and is 

repeated here for reference purposes. 

1.6.8 Accommodations to the to the Road Transportation System 

We estimated the number of tank trucks that would be needed to transport ethanol, 

biodiesel, and renewable diesel fuel using the projected volumes of ethanol and biodiesel that we 

expect would be shipped by tank truck (see Table 1.6-1, Table 1.6-2, and Section 1.6.4 of this 

DRIA ), and the assumed tank truck volume and cycle times. In all cases, we assumed a tank 

truck capacity of 8,000 gallons. Larger tank trucks are permitted in some areas, so this 

assumption will tend to overestimate of the number of tank trucks needed. We assumed 312 

truck shipping days per year and two 8 hour shifts. For shipments of ethanol from 

production/import facilities to petroleum terminals we assumed 3.75 shipments per day (4 hours 

for round trip). For secondary ethanol shipments from hub to satellite terminals, we assumed 6 

221
 
 

 

 

shipments per day (2.5 hours per round trip). For shipments of biodiesel and renewable diesel 

fuel from production facilities to terminals, we assumed 6 shipments per day. We believe that 

the shorter shipping distance for tank truck transport from biodiesel production facilities is 

justified based on the greater dispersion of such facilities relative to ethanol facilities and the fact 

that some would be located at petroleum terminals. 

Tables 1.6-6 and 1.6-7 contain our estimates of the number of new tractor trailer tank 

trucks and truck drivers that would be needed by 2022 to transport the additional volumes of 

ethanol, biodiesel, and renewable diesel fuel that are projected to be used in response to the 

proposed RFS2 standards. Our estimate of the number of truck drivers that would be needed is 

based on the assumption that each tank truck would be operated for two shifts with one driver for 

each shift. 

Table 1.6-6. 

Estimated Number of Tank Trucks Needed by 2022 

to Transport Ethanol, Biodiesel, and Renewable Diesel Fuel 

Number of Tank Trucks Needed for the Transport of 

Ethanol, Biodiesel, and Renewable Diesel Fuel 

Total Volume Volume Attributed to RFS2 Standards a 

Ethanol 2,022 1,241 

Biodiesel 74 39 

Renewable Diesel 8 8 

All Biofuels 2,106 1,288 a

 Total – the AEO 2007 based 2022 reference case absent the RFS2 standards 

Table 1.6-7. 

Estimated Number of Tank Truck Drivers needed by 2022 

to Transport Ethanol, Biodiesel, and Renewable Diesel Fuel 

Number of Tank Truck Drivers Needed to Transport 

Ethanol, Biodiesel, and Renewable Diesel Fuel 

Total Volume Volume Attributed to RFS2 

Standards a 

Ethanol 4,044 2,483 

Biodiesel 148 78 

Renewable Diesel 16 16 

All Biofuels 4,208 2,577 a

 Total – the AEO 2007 based 2022 reference case absent the RFS2 standards 

According to a 2005 study commissioned by the American Trucking Association (ATA), 

the motor carrier industry will face a shortage of qualified professional long-haul truck drivers by 

2014.449 In the study, ATA found that the long-haul, heavy-duty truck transportation industry in 

the United States is currently experiencing a national shortage of 20,000 truck drivers and, if the 

222
 
 

 

 

 

current trend continues, that shortage of long-haul truck drivers could increase to 111,000 by 

2014. ATA projected the need for additional 54,000 drivers each year. The trucking industry is 

active in a number of efforts to attract and retrain a sufficient number of new truck drivers 

including ATA’s National Truck Driver Recruiting Campaign and Driver Tuition Finance 

Program. 

As discussed above, we estimate that the growth in the transportation of biofuels by truck 

through 2022 due to the RFS2 standards would result in the need for a total of approximately 

2,600 additional trucks drivers. Given the relatively small number of new truck drivers needed 

to transport the volumes of biofuels projected to be used to comply with the RFS2 standards 

through 2022 compared to the total expected increase in demand for drivers over the same time 

period (>750,000), we do not expect that the implementation of the RFS2 standards would 

substantially exacerbate the potential for an overall shortage of truck drivers. However, 

specially-certified drivers are required to transport biofuels because these fuels are classified as 

hazardous liquids. Thus, there may be a heightened level of concern about the ability to secure a 

sufficient number of such specially-certified drivers to transport biofuels. The trucking industry 

is involved in efforts to streamline the certification of drivers for hazardous liquids transport. 

We do not anticipate that the need for special hazardous liquids certification for biofuels truck 

drivers of would substantially interfere with the ability to transport the projected volumes of 

biofuels by tank truck. We project that tank truck deliveries of biofuels would typically be 

accomplished within an 8 hour shift allowing the driver to return home each evening.AAAAA The 

ATA sponsored study indicated that there was particular difficulty in attracting and retaining 

drivers for long haul routes the keep the driver away from home overnight. Thus, driving a tank 

truck (with typical 8 hour shift) may be relatively more attractive compared to a long haul truck 

driving position. 

Truck transport of biofuel feedstocks to production plants and finished biofuels and coproducts from these plants naturally is concentrated on routes to and from these production 

plants. This may raise concerns about the potential impact on road congestion and road 

maintenance in areas in the proximity of these facilities. We do not expect that such potential 

concerns would represent a barrier to the implementation of the RFS2 standards. The potential 

impact on local road infrastructure and the ability of the road net to be upgraded to handle the 

increased traffic load is an inherent part in the placement of new biofuel production facilities. 

Consequently, we expect that any issues or concerns would be dealt with at the local level. The 

transport of biofuel feedstocks is discussed in Section 1.3.3 of this DRIA. 

1.6.9 Petroleum Terminal Accommodations 

Terminals will need to install additional storage capacity to accommodate the volume of 

ethanol/biodiesel that we anticipate will be used in response to the RFS2 standards. By 2022, an 

additional 20.96 BGY of ethanol would be used as a result of the RFS2 standards.BBBBB We 

AAAAA A small fraction of biofuels deliveries may require a sleep-over on the road of the driver due to limitations on 

the amount of time a driver can spend behind the wheel in a day. 

BBBBB A total of 34.14 BGY of ethanol would be used by 2022 under the RFS2 standards. 13.18 BGY is projected 

to have been used in the absence of the RFS2 standards under the AEO 2007 based 2022 reference case. See 

223
 
 

 

 

 

 

estimate that it would be necessary to maintain an inventory level of 15% of annual ethanol 

consumption at the terminal level in order to provide a sufficient downstream buffer to ensure 

consistent supply. We chose a working inventory level of 15% rather than the 10% that is 

typical for petroleum-based fuels to compensate for the potential increase in temporary 

disruptions in ethanol delivery compared to petroleum-based fuels. We believe that this is 

appropriate due to the reliance on rail, barge, and truck for the transport of biofuels as opposed to 

use of pipelines for the shipment of petroleum-based fuels. Accommodating a 15% working 

inventory equates to 3.14 BG or 74.9 million barrels of additional ethanol storage at terminals 

due to the RFS2 standard. We further estimate that an additional 30% of ethanol storage (22.4 

million barrels) would be needed as working space to accommodate ethanol deliveries.CCCCC 

Thus we project that a total of 97.3 million barrels of additional ethanol storage would be needed 

at petroleum terminals due to the RFS2 standards.DDDDD 

Overall demand for the gasoline motor vehicle fuel is expected to remain relatively 

constant through 2022.EEEEE Thus, much of the demand for new ethanol storage could be 

accommodated by modifying storage tanks that had previously been used for the gasoline that 

would be displaced by ethanol. Due to the lower energy density of ethanol relative to gasoline 

(67%), we project that only 67% of the demand for new ethanol storage (65.2 million barrels) 

could be accommodated by modifying existing gasoline tanks for ethanol service. Therefore, we 

project that 32.1 million barrels of new ethanol storage tanks would be need to be constructed at 

petroleum terminals. 

By 2022, an additional 430 MGY of biodiesel would be used as a result of the RFS2 

standards.FFFFF We used the same terminal tankage sizing factors used above for ethanol to 

estimate the volume of new biodiesel storage volume that would be needed at petroleum 

terminals. This results in an estimated need for an additional 77.4 million gallons or 1.84 million 

barrels of new biodiesel storage space at petroleum terminals as a result of the RFS2 standards. 

Our projections of the growth in diesel fuel demand indicate that there would not be the 

opportunity to switch tanks currently in petroleum-based diesel fuel service to biodiesel service. 

Thus, all of the demand for new biodiesel storage would need to be satisfied through the 

construction of new tanks. Biodiesel storage tanks would need to be insulated/heated in colder 

climes. 

Concerns have been raised by terminal operators in the Eastern U.S. about the ability of 

some terminals to install the needed storage capacity due to space constraints and difficulties in 

securing permits.450 We acknowledge that it may not be possible for some terminals that have 

Section 1.5 of this DRIA for a discussion of projected ethanol volumes that would be used under the RFS2 standards 

and under the reference cases. 

CCCCC Petroleum terminals typically allow an additional 30 percent of storage capacity (in relation to the amount 

provided for working inventory) to accommodate the receipt of petroleum products. DDDDD We also project that 8.8 million barrels of new ethanol storage would be needed at rail terminals that act as 

ethanol unit train receipt facilities as discussed in Section 1.6.4 of this DRIA. EEEEE Our projections of the motor fuel demand can be found in chapter 1.2 of this DRIA. FFFFF A total of 810MGY of biodiesel would be used by 2022 under the RFS2 standards. 380 MGY is projected to 

have been used in the absence of the RFS2 standards under the AEO 2007 based 2022 reference case. See Section 

1.5 of this DRIA for a discussion of projected biodiesel volumes that would be used under the RFS2 standards and 

under the reference cases. 

224
 
 

become surrounded by urban growth over time to install additional storage tanks within the 

boundaries of their existing facilities. However, we believe that there are ways to manage this 

situation. The areas served by existing terminals often overlap. In such cases, one terminal 

might be space constrained while another serving the same area may be able to install the 

additional capacity to meet the increase in demand. Terminals with limited ethanol storage (or 

no access to rail/barge ethanol shipments) could receive truck shipments of ethanol from 

terminals with more substantial ethanol storage (and rail/barge receipt) capacity. The trend 

towards locating ethanol receipt and storage capability at rail terminals located near petroleum 

terminals is likely to be an important factor in reducing the need for large volume ethanol receipt 

and storage facilities at some petroleum terminals. In cases where it is impossible for existing 

terminals to sufficiently expand their storage capacity due to a lack of adjacent available land or 

difficulties in securing the necessary permits or to make arrangements to sufficiently reduce the 

need for such additional storage, new satellite storage or new separate terminal facilities may be 

need for additional ethanol storage. However, we believe that there will be few (if any) such 

situations. 

As discussed below, we project that all terminals that distribute gasoline would install 

ethanol blending capability in response to the RFS2 standards. However, we estimate that only 

44% of terminals that distribute diesel would install biodiesel blending/storage capability under 

the RFS2 standards. Therefore, in the case of biodiesel, those terminals that would experience 

that most difficulty in installing new storage capacity could forgo bringing biodiesel into their 

terminal 

Another question is whether the storage tank construction industry would be able to keep 

pace with the increased demand for new tanks that would result from today’s proposal. The 

storage tank construction industry recently experienced a sharp increase in demand after years of 

relatively slack demand for new tankage. Much of this increase in demand was due to the 

unprecedented increase in the use of ethanol. Storage tank construction companies had been 

increasing their capabilities which had been pared back during lean times. Given the projected 

gradual increase in the need for biofuel storage tanks, it seems reasonable to conclude that the 

storage tank construction industry would be able to keep pace with the projected demand. 

Petroleum terminals would need to install additional equipment to blend ethanol with 

gasoline as well as making other miscellaneous upgrades to piping, pumps, seals, and vapor 

recovery systems to ensure ethanol compatibility. There are currently 1,063 petroleum terminals 

that carry gasoline.451 We project that 899 of these terminals (85% of the total) would install 

E10 blending equipment absent the implementation of today’s proposed requirements in order to 

support the consumption of 13.18 BGY of ethanol by 2022 under the reference case. This is 

based on 85% of the gasoline needing to be blended with ethanol in order to consume 13.18 

BGY of ethanol considering the projected use levels of E10 versus E85 and total motor vehicle 

fuel consumption in 2022.GGGGG We project that essentially all gasoline would be either E10 or 

E85 by 2022 under the RFS2 standards. Thus, we estimate that all terminals would need to have 

ethanol blending capability to support the use of the volume of ethanol we project would be used 

under the RFS2 standards. Based on our projection that 899 terminals would install ethanol 

GGGGG A discussion of the volumes of biofuels we estimate would be used absent the RFS2 standards is located in 

chapter 1.2 of this DRIA. 

225
 
 

 

 

 

blending capability absent the RFS2 standards, we estimate that 164 terminals would need to 

install ethanol blending equipment as a result of the proposed requirements. 

We estimate that E85 would need to be reasonably available in 70% of the nation in order 

to support the use of the projected volume of E85 needed to comply with the proposed 

standards.HHHHH To provide a conservatively high estimate, we are projecting that 90% of all 

gasoline terminals (931) would need to install E85 blending capability by 2022. The remaining 

terminals (132 out of a total of 1,063) would only have E10 blending capability in 2022. We 

estimate that the terminals which would have installed E10 blending capability absent the 

proposed standards would upgrade their E10 blending facilities to accommodate E85 as well as 

E10. This is based on the assumption that those terminals that were the first to blend E10 would 

also be the first to begin blending E85. Input from terminal operators indicates that the 

modification of E10 blending equipment to handle E85 primarily involves an upgrade to the 

blending equipment software.IIIII We estimate that the vapor recovery systems at all terminals 

that had not received ethanol before would need to be upgraded to handle ethanol-blended 

gasoline. 

We considered the following in estimating the number of terminals that would 

store/blend biodiesel in response to the RFS2 standards. We estimate that 853 terminals handle 

diesel fuel.452 We estimate that approximately 62.5 billion gallons of diesel fuel would be used 

in 2022.JJJJJ Thus, the average diesel throughput per terminal would be approximately 73.2 

MGY. We estimate that on a national average basis biodiesel would represent approximately 

2.9% of the diesel fuel pool. For the purposes of our calculation of the number of terminals that 

would carry biodiesel, we assumed that 2.9% of the diesel fuel they dispense would be biodiesel. 

This is likely to result in a conservatively high number of terminals that would need to carry 

biodiesel, since those terminals that do carry biodiesel would be expected too blend at higher 

than the national average concentration. Assuming that 2.9% of a terminal’s diesel fuel 

throughput would be biodiesel, we arrive at an estimate that 377 terminals would need to blend 

biodiesel to support the projected use of 810 MGY of biodiesel by 2022 under the RFS2 

standards. We estimate that 200 terminals would need to store/blend biodiesel in order to 

support the use of volume of biodiesel that we estimate would be used as a result of the RFS2 

standards relative to the AEO 2007 380 MGY 2022 baseline. 

New equipment will be needed at terminals to facilitate the receipt of ethanol by truck, 

manifest rail car, and by unit train. As discussed in Section 1.6.3 of this DRIA, we estimated 

that half of the ethanol unit train receipt facilities (21) needed as a result of the RFS2 standards 

would be placed at petroleum terminals and half would be placed at rail terminals for the purpose 

of this analysis.KKKKK In estimating the number of additional manifest rail car receipt facilities 

HHHHH A discussion of our E85 use projections is contained in chapter 1.7 of this DRIA. IIIII Additional ethanol storage and modifications to terminal piping would also be needed to supply additional 

quantity of ethanol needed to blend E85.

JJJJJ A discussion of our estimate of biodiesel use in relation to the use of petroleum-based diesel is contained in 

Section 1.5.4 of this DRIA. 

KKKKK We intend to review our estimate of the number of ethanol rail receipt facilities in light of the recent ORNL 

report which assumed that all such new rail receipt capability would be placed at rail terminals due to the difficulties 

in accommodating such facilities at petroleum terminals. This applies to manifest rail as well as unit train receipt 

facilities. 

226
 
 

that would be needed at petroleum terminals, we assumed 5 deliveries per month of 8 cars at 

each facility. This would result in the delivery of 1,180,000 gallons of ethanol per month which 

we believe to be reasonable, giving the anticipated motor vehicle gasoline throughput at 

terminals we expect would receive ethanol shipments by manifest rail car. Based on the ethanol 

volumes we projected to be transported by manifest rail car in Table 1.6-1 of this DRIA, this 

translates to a total of 241 manifest rail car receipt facilities for all ethanol used by 2022 and 148 

such facilities to handle the volume attributed to the RFS2 standards alone (relative to the AEO 

2007 based 2022 reference case). Lacking any specific data on the number of terminals that 

currently have rail receipt capability, we estimate that 50% of the terminals that install ethanol 

rail receipt capability would have already had an active rail connection and that 50% would need 

to install a short spur to connect to a nearby rail line. 

As discussed in Section 1.6.3 of this DRIA, we expect that to the extent that the projected 

number of ethanol rail receipt facilities could not be cited at petroleum terminals that they would 

be cited at rail terminals. Petroleum terminals within trucking distance of each other are also 

likely to cooperate so that only one would need to install rail receipt capability. Given the 

timeframe during which the projected volumes of ethanol ramp up, we believe that these means 

can be utilized to ensure that a sufficient number of terminals have access to ethanol shipped by 

rail although some will need to rely on secondary shipment by truck from large ethanol hub 

receipt facilities. 

We project that those terminals that would receive domestic shipments of ethanol by 

barge would have already installed the necessary barge offloading equipment. Terminals that 

also serve as points of entry for imported ethanol which did not previously receive shipments of 

ethanol would need to install facilities to accept marine shipments of ethanol. We estimate that 

there would be a total of 29 terminals that receive imported ethanol by 2022 and that 12 of these 

terminals would not have received ethanol shipments previously.LLLLL We do not project the 

need for additional facilities at terminals to accept receipts of biodiesel and renewable diesel 

fuel. We expect that the facilities projected to be installed for ethanol could be used for biodiesel 

and renewable diesel fuel. In the case of biodiesel, new heated/insulated transfer piping would 

be needed from the receipt facility to the storage tank. 

The Independent Fuel Terminals Operators Association (IFTOA) stated that terminals are 

concerned that the market would not be able to adapt in time to ensure that the necessary 

distribution infrastructure accommodations are in place to support compliance with the timetable 

for the implementation of the RFS2 standards.453 Based on this concern, in a presentation at the 

2008 SAE government-industry conference IFTOA suggested that EPA should consider reducing 

and or slowing the pace of the implementation of the RFS2 standards in order to allow the 

market sufficient time to adjust. 454 We do not believe that there is sufficient reason at this time 

to conclude that the distribution system could not adapt sufficiently within the time frame 

established by statute for the implementation of the RFS2 standards. We will continue to 

monitor the progress made to by the distribution system to make the necessary changes. To the 

extent that the fuel distribution industry experiences difficulty in installing the needed storage 

tanks and blending equipment, the continuation of the interim practices of transloading and 

splash blending would help to bridge the gap. 

LLLLL See Section 6.1.5 of this DRIA for a discussion of ethanol import locations. 

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The RFG and anti-dumping regulations currently require certified gasoline to be blended 

with denatured ethanol to produce E 85. The gasoline must meet all applicable RFG and antidumping standards for the time and place where it is sold. We understand that some parties may 

be blending butanes and or pentanes into gasoline before it is blended with denatured ethanol in 

order to meet ASTM minimum volatility specifications for E85 that were set to ensure proper 

driveability, particularly in the winter. MMMMM If terminal operators add blendstocks to finished 

gasoline for use in manufacturing E85, the terminal operator would need to register as a refiner 

with EPA and meet all applicable standards for refiners. 

Testing has shown that much of in-use E85 does not meet minimum ASTM volatility 

specifications. NNNNN However, it is unclear if noncompliance with these specifications has 

resulted in a commensurate adverse impact on driveability. This has prompted a re-evaluation of 

the fuel volatility requirements for in-use E85 vehicles and whether the ASTM E85 volatility 

specifications might be relaxed or the minimum amount of ethanol in E85 adjusted dowanwards 

to facilitate compliance with the current volatility requirements. OOOOO For the purpose of our 

analysis, we are assuming that certified gasoline currently on hand at terminals can be used to 

make up the non-ethanol portion of E85.PPPPP 

We will continue to evaluate the extent that special blendstocks would be used to 

manufacture E85 at terminals particularly in light of the outcome of the ASTM process and 

adjust our estimates for the final rule as appropriate. Input from industry indicates that it is not 

common for gasoline terminals to have butane/pentane storage capability. This input further 

indicates that the space requirements for citing a pressurized butane storage vessel make 

installation of butane storage at some terminals impractical. If special gasoline blendstocks not 

typically found at terminals are needed for the manufacture of E85, there could be substantial 

additional costs and logistical challenges associated with shipping these blendstocks to terminals. 

1.6.10 Additional E85 Retail Facilities 

As discussed in Section 1.7.1.2 of this DRIA, we estimate that end-users would need to 

have reasonable access to E85 in 70% of the nation by 2022 given our projections regarding the 

population of flexible fuel vehicles (FFVs) and E85 refueling frequencies.QQQQQ We define 

reasonable access as one in four gasoline retail facilities offering E85 in fashion consistent with 

the way they currently offer gasoline. We selected one in four based on a review of the number 

of facilities that have been postulated to be needed to support the introduction of alternative fuels 

vehicles such as hydrogen and natural gas vehicles, the number of facilities that currently offer 

MMMMM “Specification for Fuel Ethanol (Ed75-Ed85) for Spark-Ignition Engines”, American Society for Testing and 

Materials standard ASTM D5798. NNNNN Coordinating Research Council (CRC) report No. E-79-2, Summary of the Study of E85 Fuel in the USA 

Winter 2006-2007, May 2007. http://www.crcao.org/reports/recentstudies2007/E-79-2/E-79­

2%20E85%20Summary%20Report%202007.pdf

OOOOO CRC Cold Start and Warm-up E85 Driveability Program, 

http://www.crcao.com/about/Annual%20Report/2007%20Annual%20Report/Perform/CM-133.htm PPPPP This is different from the approach taken in the refinery modeling which assumed that special blendstocks 

would be used to blend E85. A discussion of the refinery modeling can be found in Section 4 of this DRIA. 

QQQQQ Chapter 1.7 of this DRIA contains a discussion of our projections regarding the prevalence of flexible fuel 

vehicles in the vehicle fleet and the relative volumes of E85 versus E10 that would be used in these vehicles. 

228
 
 

 

 

diesel fuel, and industry estimates regarding the number of E85 facilities that would be needed. 

One in five to one in three retail facilities has been discussed as a reasonable rule of thumb 

regarding the number of retail facilities needed to support the widespread introduction of 

alternative fuel vehicles. 

We estimate that approximately one in three fuel retail facilities (32%) offered diesel fuel 

in 1999 based on our review of fuel retailer survey data.455 The National Association of 

Convenience Stores (NACS) reported that in 2006, 36.6% of the respondents to their survey 

offered diesel fuel.456 We believe that given that NACS members typically do not include truck 

stop operators (who all offer diesel fuel) that that it is most likely that the number of diesel fuel 

retailers has increased since 1999. Since fuel retailers make most of their money from in-store 

sales as opposed to fuel sales, it seems likely that more retailers recognized an opportunity to 

attract additional customers by offering diesel fuel since 1999. In any event, the number of 

diesel fuel refueling facilities available in 1999 or 2006 has not hindered the use of diesel fuel 

vehicles. Unlike diesel fuel vehicles that can refuel only on diesel fuel, flex fuel vehicles can 

refuel on gasoline as well as E85. We project that flex-fuel vehicles would only refuel on E85 

70% of the time in order to meet the ethanol consumption goals necessary to support the RFS2 

standards.RRRRR Thus, we believe that the percentage of total fuel retail facilities that sell diesel 

fuel (32% based on our 1999 estimate) serves as an upper bound regarding the number of E85 

retail facilities that would be needed. 

At the same many time fleet operators were divesting of their in-house fueling facilities 

because of new environmental regulations, most retailers were installing equipment to blend 

mid-grade gasoline at the pump rather than store a separate mid-grade gasoline. This allowed for 

a significant number of retailers to begin offering diesel fuel at relatively low capital cost by 

converting storage tanks that had been dedicated to mid-grade gasoline storage to diesel fuel 

service. A number of retail facilities (40% of the total that installed diesel fuel tanks had low 

annual diesel throughput volumes of less than 60,000 gallons per year in 2000.457 Only 5% of 

total diesel retail sales are estimated to be sold at these low-volume retailers. Given that the 

installation of some diesel retail facilities was not strictly driven on the expectation or realization 

of substantial throughput, it seems reasonable to assume that some fraction of low-volume 

retailers may not be absolutely necessary to ensure adequate diesel availability. Therefore, 

somewhat less than 32% of retail facilities might actually be needed to ensure adequate diesel 

fuel availability. We believe that this comparison to the number of diesel fuel retail facilities 

available supports our estimate that one in four retail facilities would be sufficient to provide 

reasonable access to E85. 

 By multiplying the one-in-four reasonable access assumption by the assumed 70% of the 

retail market that would need to have reasonable access to E85, and the total number of retail 

facilities, we arrived at our estimate that there would need to be a total of 28,750 E85 retail 

locations to facilitate the consumption of the amount of ethanol that we project would be used by 

2022 in response to the requirements under the RFS2 standards. The National Ethanol Vehicle 

Coalition (NEVC) estimates there are currently 1,767 E85 refueling facilities.458 However, the 

NEVC estimate includes E85 refueling facilities that are not open to the general public.459 

“NEAR85” estimates that there are currently 1,247 E85 retail facilities. The Near85 estimate 

RRRRR A discussion of E85 refueling rates is contained in Section 1.7.1.2.4 of this DRIA. 

229
 
 

includes only retail facilities. Based on these data, we are assuming that there are approximately 

1,300 E85 retail facilities currently in service for the purposes of our E85 retail facility cost 

analysis. By growing the number of E85 retail facilities by the same proportion as the growth in 

our projections for the growth in ethanol use under the AEO 2007 based 2022 reference case, we 

estimate that 4,500 E85 refueling facilities would be in place by 2022 absent the RFS2 standards. 

Thus, we estimate that today’s rule would result in the need for an additional 24,250 retail E85 

facilities by 2022. 

We project that a number of E85 facilities would install multiple E85 pump stands. We 

based our estimate on the number of facilities that would install multiple E85 pump stands on an 

evaluation of how the anticipated E85 use levels translate to daily throughput per delivery 

nozzle. We estimate that by 2022 approximately 27.1 BGY of E85 would be used under the 

RFS2 standards.SSSSS We are assuming that all existing E85 refueling facilities and those that 

would be constructed absent the RFS2 standards have one pump stand each. There are two 

delivery nozzles (i.e. refueling positions) per each pump stand. Assuming that 40% of new E85 

retail facilities constructed due to the RFS2 standards install 2 pump stands (4 nozzles) and the 

remainder install a single pump stand results in a total of 76,900 E85 fueling positions (nozzles) 

by 2022. We assumed an average E85 refueling volume of 15 gallons. This translates to an 

annual E85 throughput per refueling position of 353,000 gallons or one refueling event every 22 

minutes. We believe this may be a reasonable, albeit optimistic, assumption regarding the future 

use rates of E85 refueling equipment. To evaluate the validity of this assessment, we reviewed 

historical data regarding the use rates for refueling equipment for other fuels. 

The National Association of Convenience Stores (NACS) reports throughput per 

refueling position.460 For all types of fuel dispensed, NACS reports that from 2001 through 

2006, the annual throughput varied from approximately 142,000 to 164,000 gallons per refueling 

position. These data include reports on the sales of all fuels including premium, mid-grade, and 

regular gasoline, diesel fuel and other fuels. The most appropriate comparison would be made to 

throughput from refueling positions that dispense only regular gasoline since the use of E85 

would primarily displace regular gasoline sales. However, this is not possible given that most 

gasoline is dispensed from blender pumps that can dispense any gasoline grade. Hence, we 

chose to make the comparison to throughput over dispensers that offer all gasoline grades, which 

may tend to underestimate the potential utilization rate of dispenser that dispenses only regular 

grade gasoline. 

 NACS reports that there is an average of 8.6 refueling positions at the retail facilities 

that responded to their survey. NACS reports that 36.6% of stores sold diesel fuel and 15.1% 

sold “other” fuels (i.e. not diesel, regular, mid-grade, or premium gasoline).TTTTT To estimate 

how many refueling positions are dedicated to diesel fuel and “other” fuels, we assumed that 

retailers offer diesel fuel from one pump with two nozzles, and other fuels from one pump with 

one nozzle. By multiplying the percentage of retailers that offer diesel fuel/other fuel by the 

assumed refueling positions for these fuels where they are present, we arrived at an estimate of 

0.9 refueling positions per facility on average dedicated to diesel fuel and other fuel. This 

translates to an average of 7.7 refueling positions per facility that dispenses gasoline. NACS 

SSSSS A discussion of our E85 use projections is contained in Section 1.7.1.2 of this DRIA. TTTTT In many cases, we expect that the “other” fuel is kerosene. 

230
 
 

reports that 92.7% of fuel volumes sold by respondents to their survey is gasoline (of all grades). 

By dividing 92.7% of the total average throughput for all fuels per facility reported by NACS by 

7.7 refueling positions, we arrived at an estimate of annual gasoline throughput per nozzle of 

177,000 gallons for 2003.UUUUU The estimated E85 throughput per nozzle under the assumption 

that 40% of new facilities would install four E85 refueling positions is nearly twice this figure. 

We anticipate that most new E85 refueling facilities would be installed at larger fuel 

retailers because these would be most forward looking with respect to attracting new customers, 

would be most likely to have the needed space, and be would have the best access to capital. A 

higher throughput could be expected at larger fuel retailers compared to that across all retail 

facilities reflected in the NACS survey. Thus, we believe that the projected level of E85 

refueling position throughput of 353,000 gallons per year may be attainable, albeit ambitious. 

We performed a sensitivity analysis to evaluate the effect on E85 refueling position throughput if 

additional E85 pumps were installed. 

If each of the 28,750 E85 refueling facilities that we estimate would be needed by 2022 

installed 2 E85 pumps/4 nozzles, the annual E85 throughput per nozzle would be 236,000 

gallons. If each installed 3 E85 pumps/6 nozzles the annual E85 throughput per nozzle would be 

157,000 which is consistent with current gasoline pump utilization rates. We anticipate that some 

of the additional E85 pumps would take the place of existing gasoline pumps as E10 use is 

displaced by E85 use. It is also possible that pumps could be configured to dispense E10 as well 

as E85. 

We assumed that one new 8,000 gallon E85 underground storage tank would be installed 

at each E85 refueling facility. Based on our estimate of 28,750 E85 refueling facilities and the 

use of 27.125 BGY of E85 by 2022, annual E85 throughput per facility would be approximately 

943,000 gallons. This translates to one 7,000 gallon E85 delivery by tank truck every 2.7 

days.VVVVV We believe that this is a reasonable fuel delivery rate, particularly in light of our 

projection that new E85 facilities would likely be installed at the larger fuel retail facilities. We 

believe that a number of larger retailers have multiple gasoline storage tanks. Although not 

necessary to support E85 retail facility throughput, as E85 throughput ramps up and gasoline 

throughput decreases, some facilities may choose to retrofit one of their gasoline storage tanks to 

E85. However, we understand that it may be difficult or impossible to confirm the compatibility 

of some existing underground storage tanks and other tank-related hardware. In fact, several 

states (e.g. California) will not allow existing underground storage tanks to be upgraded to store 

ethanol blends greater than 10% due to compatibility concerns. 

Approximately 1,960 new E85 facilities would need to be added each year from 2009 

through 2022 in order to satisfy this goal of 28,750 facilities by 2022. The addition of 1,960 new 

E85 retail facilities a year is very ambitious given that there are currently only 1,300 E85 retail 

facilities in service. Nevertheless, we believe the addition of these numbers of new E85 facilities 

may be possible for the industries that manufacture and install E85 retail equipment. 

Underwriters Laboratories recently finalized its certification requirements for E85 retail 

UUUUU The year 2003 had the highest average throughput per refueling position over the years 2001- 2006. VVVVV A 7,000 delivery volume was assumed to provide adequate reserve at the retail facility to ensure consistent 

availability. 

231
 
 

 

 

 

 

 

equipment.461 Equipment manufactures are currently evaluating the changes that will be needed 

to meet these requirements. However, we anticipate the needed changes will not substantially 

increase the difficulty in the manufacture of such equipment compared to equipment which is 

specifically manufactured for dispensing E85 today. 

Petroleum retailers expressed concerns about their ability to bear the cost of installing 

new E85 refueling equipment because of the difficulty of obtaining the necessary capital and to 

achieve adequate capital recovery. We estimated the costs under both our primary scenario 

where only 40% of E85 retailers install 2 pumps and under the sensitivity case where all E85 

retail facilities are assumed to have 3 E85 pumps.WWWWW A full discussion of our estimated of 

E85 facility costs is contained in Section 4.2 of this DRIA. We assumed all new pump stands 

under both scenarios. This will tend to provide a conservatively high estimate of costs since we 

expect that some E10 dispensers would be replaced by E85 dispensers under the 3 pump per 

facility sensitivity case. Under the 3-pump sensitivity case, we also included the cost of 

retrofitting an existing gasoline storage tank to provide additional E85 storage capacity at 50% of 

new E85 facilities. Under our primary case where we assume that 40% of new facilities install 2 

E85 pumps and the remainder would have one pump, we estimate that the cost of installing E85 

refueling equipment will average $122,000 per facility which equates to $3 billion by 2022. 

These costs include the installation of an underground storage tank, piping, dispensers, leak 

detection, and other ancillary equipment that is compatible with E85.XXXXX Under the sensitivity 

case, where all E85 facilities are assumed to have 3 E85 pumps, we estimate the cost for 

facilities that did not offer E85 before would be approximately $166,000 per facility. For those 

facilities that already offered E85, the cost of installing 2 additional pump stands is estimated at 

$46,000 per facility. The total cost of E85 refueling facilities under the 3-pump sensitivity case 

is estimated at 4.2 billion by 2022. 

Today’s proposal does not contain a requirement for retailers to carry E85. We 

understand that retailers will only install E85 facilities if it is economically advantageous for 

them to do so and that they will price their E85 and E10 in a manner to recover these costs. As 

discussed earlier we expect that larger fuel retailers would be most likely to install new E85 

refueling facilities. While the $3 billion total cost for E85 refueling facilities is a substantial sum 

under our primary E85 facility scenario, it equates to just 1.2 cents per gallon of E85 throughput. 

Under the 3-pump sensitivity case, the total E85 facility cost of $4.2 billion equates to 1.7 cents 

per gallons of E85 throughput.YYYYY Therefore, we do not believe that the cost of installing E85 

refueling equipment will be unmanageable to retailers given the very large projected consumer 

demand for E85. Government incentives are also available to help defer the cost of installing 

E85 retail equipment and expansions of these incentives are under consideration.ZZZZZ 

WWWWW Section 4.2 of this DRIA contains a discussion of estimated E85 retail facility costs. XXXXX 40 CFR 280.32 states that underground storage tank systems must be made of or lined with materials that are 

compatible with the substance stored in the system. 

YYYYY Our estimates of the cost of the E85 retail facilities that would be needed to support the use of the volume of
 

ethanol that we project would be used under the RFS2 standards is contained in Section 4.2 of this DRIA. 

ZZZZZ See Section 1.7.1.2.3 of this DRIA for a discussion of government incentives to install E85 retail refueling 

equipment.
 

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Petroleum retailers also expressed concern regarding their ability to discount the price of 

E85 sufficiently to persuade flexible fuel vehicle owners to choose E85 given the lower energy 

density of ethanol. This issue is discussed in Section 1.7.1.2.5 of this DRIA. 

1.6.11 Potential Impact on the Fuel Distribution System if a Waiver is Granted for MidLevel Ethanol Blends and Ancillery Issues that would need to be Resolved to 

Facilitate the Introduction of Mid-Level Ethanol Blends 

As discussed in Section 1.7.1.3.1 of this DRIA, there is interest in evaluating the 

suitability of midlevel ethanol blends (e.g. E15) for use in non-flex fuel vehicles to facilitate the 

consumption of the large volumes of ethanol that would be needed to satisfy the RFS2 standards. 

While a waiver may legalize the use of mid-level ethanol blends under the CAA, there are a 

number of other actions that would have to occur to bring mid-level blends to retail. The time 

needed to take these actions could delay the penetration of mid-level ethanol blends into the 

market. The CAA only provides a 1 pound RVP waiver for ethanol blends of 10 volume percent 

or less. Lacking such an RVP waiver, a special low-RVP gasoline blendstock would be needed 

at terminals to all the formulation of mid-level ethanol blends that are complaint with EPA RVP 

requirements. Providing such a separate gasoline blendstock could present significant logistical 

challenges and costs to the fuel distribution system.AAAAAA In addition, a number of changes 

would be needed to EPA regulations including those pertaining to reformulated and conventional 

gasoline, and deposit control additives to accommodate and mid-level ethanol blends. Such 

changes would need to be made through the notice and comment process similar to today’s 

action. Independent of EPA’s regulations, most states require that fuel comply with the 

applicable ASTM International (formally known as the American Standards for Testing and 

Materials) specification. The development of an ASTM International specification for mid-level 

ethanol blends through an industry consensus process is currently being initiated. 

There are a number of requirements regarding the fire and leak protection safety of retail 

fuel dispensing and storage equipment. EPA’s Office of Underground Storage Tanks (OUST) 

requires that UST systems must be compatible with the fuel stored in the system. These 

requirements pertain to all components of the system including the storage tank, connecting 

piping, pumps, seals and leak detection equipment. The Occupational Safety and Health 

Administration (OSHA) requires that retail fuel handling equipment be listed with an 

independent standards body such as Underwriters Laboratories (UL). No independent standards 

body has listed fuel handling equipment for mid-level ethanol blends. Furthermore, UL has 

stated that it would not expand listings for in-use fuel retail equipment originally listed for E10 

blends to cover greater than E10 blends.BBBBBB 

AAAAAA It may be possible for refiners to formulate a gasoline blendstock that would be suitable for manufacturing 

mid-level ethanol blends and E10 at the terminal. While this would avoid the logistical problems associated with 

maintaining separate blendstocks, there could be significant additional refining costs. BBBBBB UL stated that they have data which indicates that the use of fuel dispensers certified for up to E10 blends to 

dispense blends up to a maximum ethanol content of 15 volume percent would not result in critical safety concerns 

(http://www.ul.com/newsroom/newsrel/nr021909.html). Based on this, UL stated that it would support 

authorities having jurisdiction who decide to permit legacy equipment originally certified for up to E10 blends to be 

used to dispense up to 15 volume percent ethanol. The UL announcement did address the compatibility of 

underground storage tank systems with greater than E10 blends. 

233
 
 

 

 

 

States typically adopt fire safety codes from either the National Fire Protection 

Association (NFPA) or the International Code Council (ICC). These organizations currently do 

not have provisions that would allow the mid-level ethanol blends to be stored/dispensed from 

existing equipment at retail. Local safety officials (e.g. fire marshals) referred to as “Authorities 

Having Jurisdiction” (AHJ’s) often require a UL certification for fuel retail storage/dispensing 

equipment although some will accept other substantiation of equipment safety such as a 

manufacture certification. Fuel retailers must also satisfy the requirements of the insurance 

company that they are insured through which may be more stringent than the legal requirements. 

The Department of Energy and EPA are currently working with industry to evaluate what 

changes may be necessary to underground storage tank systems, fuel dispensers, and refueling 

vapor recovery equipment at fuel retail facilities to handle a mid-level ethanol blend. If existing 

equipment proves tolerant to a mid-level ethanol blend, this could substantially facilitate its 

introduction at retail. If the data supports the suitability of legacy retail equipment to 

store/dispense a mid-level blend, then the process of seeking acceptance by the standard bodies 

discussed above could commence. The normal processes used by these standards bodies can be 

lengthy. For example, the NFPA has a 3 year cycle for evaluating changes to its codes with 

proposals for the current cycle due this June.CCCCCC Thus, apart from the need to technically 

evaluate the suitability of legacy retail equipment to handle a mid-level ethanol blend, the need 

to secure recognition from standards bodies could delay the introduction of a mid-level ethanol 

blend at retail should a waiver be granted by EPA. 

If some components of the above ground existing retail hardware are found to be 

incompatible with a mid-level ethanol blend, it may be possible for them to be replaced through 

normal attrition. For example the “hanging hardware” which includes the nozzle and hose from 

the dispenser is typically replaced every 3 to 5 years. It is also possible that only minor changes 

might be needed to equipment that has a longer service life which might be accomplished 

without too much difficulty/cost. However, if extensive new equipment is needed and 

particularly if this involves the breaking of concrete, we believe that it is unlikely that fuel 

retailer would opt to install equipment specifically for a mid-level ethanol blend given the 

projected future need for retail equipment capable of handling E85.DDDDDD The deployment of 

mid-level ethanol blends would still not get us all the way to meeting the RFS2 volumes 

requirements. Once the nation hit the mid-level blend wall, refiners and marketers would still 

need to invest another $2-3 billion in E85 infrastructure (depending on the scenario) or find other 

non-ethanol alternatives to meet the RFS2 volume requirements.EEEEEE 

Fuel retail operators are concerned about the potential liability from the misfueling of 

vehicles/equipment that might not be covered if a partial waiver is granted for mid-level ethanol 

blends. We anticipated that additional fuel pump labeling requirements would be needed. It is 

CCCCCC It is unclear whether sufficient material could be assembled by industry in time for the consideration of
 

dispensing E15 from legacy retail equipment be entered into the currently NFPA 3 year cycle. DDDDDD A discussed previously, significant penetration of E85 is projected to be needed to facilitate the use of the 

volumes of ethanol we project would be needed to satisfy the requirements of the EISA. 

EEEEEE For more information on retail and ethanol consumption impacts of mid-level ethanol blend assessment, refer 

to Sections 1.6.11 and 1.7.1.3 of the DRIA, respectively. 

234
 
 

 

 

unclear what other measures might be needed to adequately prevent misfueling if a partial waiver 

is granted. 

Finally, auto manufactures would need to extend the warranty coverage for vehicles 

covered under a waiver in order to give consumers adequate confidence to use mid-level ethanol 

blends. Owner manuals for non-FFV vehicles in the existing fleet are written to void vehicle 

warranties if the vehicle is operated on ethanol levels greater than 10%. 

Given our assumption that no ethanol would be transported by pipeline, we expect that 

there would be no impact on the ethanol distribution system through the terminal level. If 

shipment of ethanol by pipeline does become practicable, there would obviously be implications 

regarding which ethanol blend ratio would be most desirable to ship. At the terminal level, the 

amount of ethanol blended into gasoline as it is delivered into tanks would be adjusted to the 

desired mid-level blend ratio. We expect that only minimal changes to the software for the 

blending equipment would be needed to accommodate the delivery of mid-level blends up to the 

point of delivery to retail facilities. 

1.7 Biofuel Consumption Feasibility 

1.7.1 Ethanol Consumption 

1.7.1.1 Historical/Current Ethanol Consumption 

Ethanol and ethanol-gasoline blends have a long history as automotive fuels. However, 

cheap gasoline/blendstocks kept ethanol from making a significant presence in the transportation 

sector until the end of the 20th century when environmental regulations and tax incentives helped 

to stimulate growth. 

In 1978, the U.S. passed the Energy Tax Act which provided an excise tax exemption for 

ethanol blended into gasoline that would later be modified through subsequent regulations.FFFFFF 

In the 1980s, EPA initiated a phase-out of leaded gasoline which created some interest in ethanol 

as a gasoline oxygenate. Upon passage of the 1990 CAA amendments, states implemented 

winter oxygenated fuel (“oxyfuel”) programs to monitor carbon monoxide emissions. EPA also 

established the reformulated gasoline (RFG) program to help reduce emissions of smog-forming 

and toxic pollutants. Both the oxyfuel and RFG programs called for oxygenated gasoline. 

However, petroleum-derived ethers, namely methyl tertiary butyl ether (MTBE), dominated 

oxygenate use until drinking water contamination concerns prompted a switch to ethanol. 

Additional support came in 2004 with the passage of the Volumetric Ethanol Excise Tax Credit 

(VEETC). The VEETC provided domestic ethanol blenders with a $0.51/gal tax credit, 

replacing the patchwork of existing subsidies.GGGGGG The phase-out of MTBE and the 

FFFFFF Gasohol, a fuel containing at least 10 percent biomass-derived ethanol, received a partial exemption from the 

federal gasoline excise tax. This exemption was implemented in 1979 and a blender’s tax credit and a pure alcohol 

fuel credit were added to the mix in 1980. 

GGGGGG The recently enacted Food, Conservation, and Energy Act of 2008 (“2008 Farm Bill”) replaces the $0.51/gal 

ethanol blender credit with a $0.45/gal corn ethanol blender credit and also introduces a $1.01/gal cellulosic biofuel 

235
 
 

 

introduction of the VEETC along with state mandates and tax incentives created a growing 

demand for ethanol that surpassed the traditional oxyfuel and RFG markets. By the end of 2004, 

not only was ethanol the lead oxygenate, it was found to be blended into a growing number of 

states’ conventional gasoline. According to our RFS1 baseline oxygenate assessment, in 2004, 

ethanol was found to be blended into 15 states’ conventional gasoline, 10 states’ winter oxyfuel, 

and 15 states’ RFG as shown in Table 1.7-1.462 

producer credit. Both credits are effective January 1, 2009. The 2008 Farm Bill is discussed in more detail in later 

parts of this subsection. 

236 
Table 1.7-1. 

2004 U.S. Ethanol Usage by State (Million Gallons) 

State CG Oxy RFG Total 

California 0.0 0.0 853.0 853.0 

Illinois 110.8 0.0 310.7 421.5 

New York 0.0 0.0 301.2 301.2 

Minnesota 268.4 0.0 0.0 268.4 

Ohio 191.6 0.0 0.0 191.6 

New Jersey 0.0 0.0 187.6 187.6 

Connecticut 0.0 0.0 152.2 152.2 

Indiana 105.3 0.0 42.7 148.0 

Missouri 42.9 0.0 79.1 122.0 

Iowa 116.7 0.0 0.0 116.7 

Wisconsin 47.3 0.0 61.3 108.6 

Arizona 0.0 13.5 74.8 88.3 

Colorado 0.0 80.2 0.0 80.2 

Michigan 76.9 0.0 0.0 76.9 

Kentucky 0.0 0.0 49.9 49.9 

Hawaii 45.2 0.0 0.0 45.2 

Kansas 40.8 0.0 0.0 40.8 

Texas 0.0 13.1 26.3 39.5 

Nebraska 37.2 0.0 0.0 37.2 

Alabama 31.4 0.0 0.0 31.4 

Oregon 0.0 30.8 0.0 30.8 

South Dakota 23.9 0.0 0.0 23.9 

Nevada 0.0 23.1 0.0 23.1 

Massachusetts 0.0 0.0 18.4 18.4 

Washington 0.0 17.9 0.0 17.9 

North Dakota 10.5 0.0 0.0 10.5 

New Mexico 0.0 8.0 0.0 8.0 

Alaska 0.0 3.4 0.0 3.4 

Utah 0.0 1.9 0.0 1.9 

Montana 0.0 1.1 0.0 1.1 

Rhode Island 0.0 0.0 0.3 0.3 

Maryland 0.0 0.0 0.3 0.3 

Florida 0.1 0.0 0.0 0.1 

Virginiaa 0.0 0.0 0.0 0.0 

Total 1,149.0 193.0 2,158.0 3,500.0 

a

Approximately 3,200 gallons of ethanol use according to FHWA. 

237
 
In the years that followed, rising crude oil prices and other favorable market conditions 

continued to drive ethanol usage. In May 2007, EPA promulgated a Renewable Fuel Standard 

(“RFS1”) in response to the Energy Policy Act of 2005.463 The RFS1 program set a floor for 

renewable fuel use reaching 7.5 billion gallons by 2012, the majority of which was ethanol. The 

country is currently on track for exceeding the RFS1 requirements and meeting the introductory 

years of today’s proposed RFS2 program. For a summary of the growth in U.S. ethanol usage 

over the past decade, refer to Table 1.7-2. 

Table 1.7-2. 

U.S. Ethanol Consumption (Including Imports) 

Year 

Total Ethanol Usea 

Trillion BTU Bgal 

1999 

2000 

2001 

2002 

2003 

2004 

2005 

2006 

2007 

2008 

120 

138 

144 

171 

233 

292 

334 

451 

566 

792 

1.4 

1.6 

1.7 

2.0 

2.8 

3.5 

4.0 

5.3 

6.7 

9.4 

a

EIA Monthly Energy Review March 2009 

(Table 10.2) 

According to EIA’s March 2009 Monthly Energy Review, the U.S. consumed 

approximately 9.4 billion gallons of ethanol in the transportation sector in 2008.464 If ethanol 

consumption continues to grow (as it did from 2005-2008), the nation should be on track for 

meeting the 2009 volume requirements set forth by EISA (10.3 billion gallons of ethanol, based 

on our volume interpretations explained in Section 1.2). For a graphical representation of 

monthly ethanol usage over the past few years, refer to Figure 1.7-1. 

238
 
 

 Monthly Ethanol Usage (Bgal) 

Figure 1.7-1. 

2005-2008 Monthly Ethanol Consumption (Including Imports)465
 

1.0 

0.9 

0.8 

0.7 

0.6 

0.5 

0.4 

0.3 

0.2 2008 

2007 

0.1 2006 

2005 

0.0 

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

Month 

Not only is ethanol usage projected to grow in future years under the proposed RFS2 

program, it is expected to come from more diversified sources. The Food, Conservation, and 

Energy Act of 2008 (also known as the “2008 Farm Bill”) is expected to spur cellulosic ethanol 

production and use.466 The recently-enacted Farm Bill modifies the existing $0.51 per gallon 

alcohol blender credit to give preference to ethanol and other biofuels produced from cellulosic 

feedstocks. As of January 1, 2009, corn ethanol receives a reduced credit of $0.45/gal and 

cellulosic biofuel earns a credit of $1.01/gal.HHHHHH 

Through the years, there have also been several policy initiatives to increase the number 

of flexible fuel vehicles (FFVs) capable of consuming up to 85 volume percent ethanol blends 

(E85). The Alternative Motor Vehicle Fuels Act of 1988 provided automakers with Corporate 

Average Fuel Economy (CAFE) credits for producing alternative-fuel vehicles, including FFVs 

as well as CNG and propane vehicles. Furthermore, the Energy Policy Act of 1992 required 

government fleets to begin purchasing alternative-fuel vehicles, and the majority of fleets chose 

FFVs.467 As a result of these two policy measures, there are over 7 million FFVs on the road 

today.468 These vehicles increase our nation’s ethanol consumption potential beyond what is 

capable with conventional vehicles. However, most FFVs are currently refueling on 

conventional gasoline (E0 or E10) due to limited E85 availability and the fact that E85 is 

HHHHHH Refer to Part II, Subparts A and B, Sections 15321 and 15331. 

239
 
 

 

typically priced 20-30 cents per gallon higher than gasoline on an energy equivalent basis. As 

such, we are not currently tapping into the full ethanol consumption potential of our FFV fleet. 

However, we expect refueling patterns to change in the future under the proposed RFS2 

program. 

1.7.1.2 Increased Ethanol Use under RFS2 

To meet the RFS2 standards, ethanol consumption will need to be much higher than both 

today’s levels and those projected to occur absent RFS2. The Energy Information 

Administration (EIA) projected that under business-as-usual conditions, ethanol usage would 

grow to just over 13 billion gallons by 2022.469 This represents significant growth from today’s 

usage; however, this volume of ethanol is capable of being consumed by today’s vehicle fleet 

albeit with some fuel infrastructure improvements.IIIIII Although EIA projected a small 

percentage of ethanol to be blended as E85 in 2022, 13 billion gallons of ethanol could also be 

consumed by displacing about 90% of our country’s forecasted gasoline energy demand with 

E10. The maximum amount of ethanol our country is capable of consuming as E10 compared to 

the projected RFS2 ethanol volumes is shown below in Figure 1.7-2. 

IIIIII For more on distribution accommodations, refer to Section 1.6. 

240
 
 

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 20 22 

Figure 1.7-2.JJJJJJ
 

Max E10 Ethanol Consumption Compared to RFS2 Requirements 

0 

5 

10 

15 

20 

25 

30 

35 

40 

Billion Gallons of Ethanol 

Ce l l u l o s i c E t h a n o l 

I m p or t ed E t ha no l 

Co r n E t h a n o l 

E1 0 Bl e n d W a l l 

Year 

As shown in Figure 1.7-2, under the proposed RFS2 program, we are projected to hit the 

E10 “blend wall” of about 14-15 billion gallons by 2013. This volume corresponds to 100% E10 

nationwide. However, if gasoline demand falls, or if E10 cannot get distributed nationwide, the 

nation could hit the blend wall sooner. Regardless, to get beyond the blend wall and consume 

more than 14-15 billion gallons of ethanol, we are going to need to see significant increases in 

the number FFVs on the road, the number of E85 retailers, and the FFV E85 refueling frequency. 

In the subsections that follow, we will highlight the variables that impact our nation’s ethanol 

consumption potential and, more specifically, what measures the market may need to take in 

order to consume 34 billion gallons of ethanol by 2022 (assuming the cellulosic biofuel standard 

and the majority of the advanced biofuel standard are met with ethanol). 

As explained in Section 1.2, our primary RFS2 analysis focuses on ethanol as the main 

biofuel in the future. In addition, from an ethanol consumption standpoint, we have focused on 

an E10/E85 world. While E0 is capable of co-existing with E10 and E85 for a while, we 

assumed that E10 would replace E0 as expeditiously as possible and that all subsequent ethanol 

growth would come from E85. Furthermore, for our primary analysis, we assumed that no 

ethanol consumption would come from the mid-level ethanol blends (i.e., E15 or E20) as they 

are not currently approved for use in non-FFVs. However, based on public interest and a recent 

JJJJJJ Based on AEO 2009 gasoline energy projections and the assumption that the cellulosic biofuel standard and the 

majority of the advanced biofuel standard would be met with ethanol. 

241
 
 

 

 

 

 

 

 

 

waiver application submitted by Growth Energy, we will discuss the potential volume 

implications of mid-level ethanol blends in the subsections that follow. 

We acknowledge that, if approved, mid-level ethanol blends could help the nation meet 

the proposed RFS2 volume requirements. First, non-FFVs could consume more ethanol per 

gallon of “gasoline”. This could result in greater ethanol consumption nationwide. In addition, 

mid-level blends could allow refiners to continue to price ethanol relative to gasoline (as it 

currently is for E10). For these reasons, it is possible that mid-level ethanol blends could help 

the nation get beyond the E10 blend wall. However, as explained in Section 1.6,11 there are 

numerous actions that would need to be taken to bring mid-level ethanol blends to market. In 

addition, mid-level ethanol blends alone (even if made available nationwide) are not capable of 

fulfilling the RFS2 requirements in later years. As explained in Section 1.7.1.3, we would 

essentially hit another blend wall 1-6 years later depending on the intermediate blend (i.e., E15 

vs. E20), how quickly it could be brought to market, and how widely mid-level ethanol blends 

were distributed. Nevertheless, this time could be very valuable when it comes to expanding 

E85/FFV infrastructure and/or commercializing other non-ethanol cellulosic biofuels. 

In summary, our primary analysis focuses on an E10/E85 world because mid-level 

ethanol blends are not currently approved for use in conventional gasoline vehicles and nonroad 

equipment.KKKKKK As a sensitivity analysis, we have analyzed what might need to be done to 

bring mid-level ethanol blends to market (should a sub-sim waiver be granted) and the extent to 

which such blends could help our nation get beyond the E10 blend wall meet the RFS2 ethanol 

standards. 

1.7.1.2.1 Projected Gasoline Energy Demand 

The maximum amount of ethanol our country is capable of consuming in any given year 

is a function of the total gasoline energy demanded by the transportation sector. Our nation’s 

gasoline energy demand is dependent on the number of gasoline-powered vehicles on the road, 

their average fuel economy, vehicle miles traveled (VMT), and driving patterns. For analysis 

purposes, we relied on the gasoline energy projections reported by EIA in AEO 2008.LLLLLL 

Unlike AEO 2007, AEO 2008 takes the fuel economy improvements set by EISA into 

consideration and also assumes a slight dieselization of the vehicle fleet. The result is a 15% 

reduction in the projected 2022 gasoline energy demand from AEO 2007 to AEO 2008.470,471 

As shown in Figure 1.7-3, EIA basically has gasoline energy demand (petroleum-based gasoline 

plus ethanol) flattening out, and even slightly decreasing, as we move into the future and 

implement the EISA vehicle standards. The recently-published AEO 2009 shows a similar trend, 

but with a slightly lower overall energy demand. 

KKKKKK For more on the potential approval pathways for mid-level ethanol blends, refer to Section V.D.3.b of the 

Preamble. 

LLLLLL For subsequent blend wall discussions/graphs, we relied on the most recent AEO 2009 projections. However 

for our detailed ethanol consumption analysis presented in this section, we relied on AEO 2008. We adjusted the 

gasoline energy demand reported in AEO Table 2 to reflect lower heating values for ethanol. In AEO 2007, EIA 

used a higher heating value of 83,333 BTU/gal for ethanol and in AEO 2008, EIA used a higher heating value of 

84,262 for ethanol. Our analyses were based on applying a lower heating value of 77,930 BTU/gal to represent 

denatured fuel-grade ethanol. 

242
 
 

2004 

2005 

2006 

2007 

2008 

2009 

2010 

2011 

2012 

2013 

2014 

2015 

2016 

Figure 1.7-3. 

Forecasted Gasoline Energy Demand 

0 

5 

10 

15 

20 

25 

Quadrillion BTUs 

AEO 2007 

AEO 2008 

AEO 2009 

Year 

1.7.1.2.2 Projected Growth in Flexible Fuel Vehicles 

According to DOE’s Department of Energy Efficiency and Renewable Energy, there are 

currently over 7 million FFVs on the road today capable of consuming E85.MMMMMM And that 

number is growing steadily. Automakers are incorporating more and more FFVs into their lightduty production plans. While the FFV system (i.e., fuel tank, sensor, delivery system, etc.) used 

to be an option on some vehicles, most FFV producers are moving in the direction of converting 

entire product lines over to E85-capable systems. Still, the number of FFVs that will be 

manufactured and purchased in future years is uncertain. To reflect this uncertainty, we have 

analyzed multiple FFV production scenarios.NNNNNN However, for our primary ethanol usage 

and cost analyses we have focused on the “Optimistic FFV Production Scenario” (described in 

more detail below). The other FFV production scenarios we considered are presented at the end 

of this subsection. 

In response to the President Bush’s “20-in-10” plan of reducing American gasoline usage 

by 20% in 10 years, domestic automakers responded with aggressive FFV production goals. 

MMMMMM DOE Energy Efficiency and Renewable Energy August 2008 estimate (worksheet available at 

www.eere.energy.gov/afdc/data/index.html) 

NNNNNN We also analyzed multiple E85 access scenarios. For more information, refer to Section 1.7.1.2.3. 

243
 
 

 

 

General Motors, Ford and Chrysler (referred to hereafter as “The Detroit 3”) announced plans to 

produce 50% FFVs by 2012.472 Assuming that The Detroit 3 continue to maintain 50% 

marketshare and that total vehicle sales remain around 16 million per year, at least 4 million 

FFVs will be produced by the 2012 model year. Based on 2008 offerings, we assumed that 

approximately 80% of The Detroit 3’s FFV commitment would be met by light-duty trucks and 

the remaining 20% would be cars.473,OOOOOO For analysis purposes, we also assumed that all the 

FFVs in existence today were produced by The Detroit 3 (and therefore share the same 

aforementioned FFV car/truck ratio) and that production would ramp up linearly beginning in 

2008 to reach the 2012 commitment.PPPPPP 

Although non-domestic automakers have not made any official FFV production 

commitments, Nissan, Mercedes, Izuzu, and Mazda all included at least one flexible fuel vehicle 

in their 2008 model year offerings.474 And we anticipate that additional FFVs (or FFV options) 

will be added in the future. Ultimately, we predict that non-domestic FFV production could be 

as high as 25%, or about 2 million FFVs per year. While we are not forecasting an official FFV 

production commitment from the non-domestic automakers, we believe that this represents an 

aggressive, yet reasonable FFV production estimate for analysis purposes. Furthermore, based 

on current offerings, we assumed that the majority of non-domestic FFVs would be trucks, i.e., 

100%. With respect to timing, we expect that the non-domestic automakers would ramp up FFV 

production later than The Detroit 3. For analysis purposes, we assumed that non-domestic 

automakers would ramp up FFV production beginning in 2013, and like The Detroit 3, it would 

take about five years for them to reach their FFV production goals (or in this case, the assumed 

25% production level). For a summary of the year-by-year FFV production assumptions we 

made under the Optimistic FFV Production Scenario, refer to Table 1.7-3. 

OOOOOO Several of the FFV production assumptions may need to be revised for the FRM in light of recent events. PPPPPP As a simplifying assumption, we assumed that all FFVs in today’s fleet were produced by The Detroit 3 

beginning in 2002. 

244
 
 

 

Table 1.7-3. 

Optimistic FFV Production Scenario – FFV Production Assumptions 

Year 

GM, Chrysler & Ford Non-Domestic Automakers 

Tot FFVs FFV-Cars FFV-Trucks Tot FFVs FFV-Cars FFV-Trucks 

2002 1,000,000 200,000 800,000 0 0 0 

2003 1,000,000 200,000 800,000 0 0 0 

2004 1,000,000 200,000 800,000 0 0 0 

2005 1,000,000 200,000 800,000 0 0 0 

2006 1,000,000 200,000 800,000 0 0 0 

2007 1,000,000 200,000 800,000 0 0 0 

2008 1,600,000 320,000 1,280,000 80,000 0 80,000 

2009 2,200,000 440,000 1,760,000 160,000 0 160,000 

2010 2,800,000 560,000 2,240,000 240,000 0 240,000 

2011 3,400,000 680,000 2,720,000 320,000 0 320,000 

2012 4,000,000 800,000 3,200,000 400,000 0 400,000 

2013 4,000,000 800,000 3,200,000 720,000 0 720,000 

2014 4,000,000 800,000 3,200,000 1,040,000 0 1,040,000 

2015 4,000,000 800,000 3,200,000 1,360,000 0 1,360,000 

2016 4,000,000 800,000 3,200,000 1,680,000 0 1,680,000 

2017 4,000,000 800,000 3,200,000 2,000,000 0 2,000,000 

2018 4,000,000 800,000 3,200,000 2,000,000 0 2,000,000 

2019 4,000,000 800,000 3,200,000 2,000,000 0 2,000,000 

2020 4,000,000 800,000 3,200,000 2,000,000 0 2,000,000 

2021 4,000,000 800,000 3,200,000 2,000,000 0 2,000,000 

2022 4,000,000 800,000 3,200,000 2,000,000 0 2,000,000 

Based on these FFV production assumptions and forecasted vehicle phase-out, VMT, and 

fuel economy estimates provided by EPA’s MOVES Model, we calculate that the maximum 

percentage of fuel (gasoline/ethanol mix) that could feasibly be consumed by FFVs in 2022 

would be about 30%.QQQQQQ The resulting gasoline energy consumption by vehicle type under 

the Optimistic FFV Production Scenario is shown below in Figure 1.7-4. For all analyses, we 

assumed that the percentage of gasoline energy consumed by nonroad, heavy-duty gasoline 

vehicles (HDGVs), and motorcycles would be about 8% based on historical information 

provided by DOE.475 

QQQQQQ For more on the EPA MOVES Model, refer to Chapter 3 of this DRIA. 

245
 
 

 

2010 

2011 

2012 

2013 

2014 

2015 

2016 

2017 

2018 

2019 

2020 

2021 

2022 

Figure 1.7-4. 

Optimistic FFV Production Scenario - Gasoline Consumption by Vehicle Type 

0% 

10% 

20% 

30% 

40% 

50% 

60% 

70% 

80% 

90% 

100% 

% of Gasoline Consumption 

FFVs 

Tier 2 Vehicles (Non-FFVs) 

Pre-Tier 2 Vehicles 

Nonroad, HDGVs & Motorcycles 

As mentioned above, the number of FFVs that will be produced in the future under the 

RFS2 rule is relatively unknown. However, to bracket the uncertainly, we have analyzed a less 

optimistic FFV production scenario as well as what FFV production might look like under a 

congressional mandate. Although EPA does not have the authority to require automakers to 

produce FFVs, there are a number of bills in Congress that are set out to do just that, e.g., The 

Open Fuel Standard Act of 2008.RRRRRR 

For the less optimistic production scenario (referred to hereafter as the “Committed FFV 

Production Scenario”), we considered what production might look like if only The Detroit 3 

followed through with their 50% by 2012 FFV commitment, Under this scenario, we assumed 

the same Detroit 3 FFV production assumptions as in the Optimistic FFV Production scenario. 

However, we assumed that the non-domestic automakers would only produce the FFVs they are 

currently forecasting in their existing production plans. Based on 2008 MY offerings, we 

assumed that the non-domestic automakers would produce approximately 5% FFVs by 2012.476 

For analysis purposes, we assumed that production would creep up beginning in 2008, and like 

the Optimistic FFV Production Scenario, and all non-domestic FFVs would be light-duty trucks. 

RRRRRR Refer to Senate Bill 3303 and House Rule 6559 discussed in more detail below. 

246
 
For a summary of the year-by-year vehicle production assumptions we made under the 

Committed FFV Production Scenario, refer to Table 1.7-4. 

Table 1.7-4. 

Committed FFV Production Scenario – FFV Production Assumptions 

Year 

GM, Chrysler & Ford Non-Domestic Automakers 

Tot FFVs FFV-Cars FFV-Trucks Tot FFVs FFV-Cars FFV-Trucks 

2002 1,000,000 200,000 800,000 0 0 0 

2003 1,000,000 200,000 800,000 0 0 0 

2004 1,000,000 200,000 800,000 0 0 0 

2005 1,000,000 200,000 800,000 0 0 0 

2006 1,000,000 200,000 800,000 0 0 0 

2007 1,000,000 200,000 800,000 0 0 0 

2008 1,600,000 320,000 1,280,000 80,000 0 80,000 

2009 2,200,000 440,000 1,760,000 160,000 0 160,000 

2010 2,800,000 560,000 2,240,000 240,000 0 240,000 

2011 3,400,000 680,000 2,720,000 320,000 0 320,000 

2012 4,000,000 800,000 3,200,000 400,000 0 400,000 

2013 4,000,000 800,000 3,200,000 400,000 0 400,000 

2014 4,000,000 800,000 3,200,000 400,000 0 400,000 

2015 4,000,000 800,000 3,200,000 400,000 0 400,000 

2016 4,000,000 800,000 3,200,000 400,000 0 400,000 

2017 4,000,000 800,000 3,200,000 400,000 0 400,000 

2018 4,000,000 800,000 3,200,000 400,000 0 400,000 

2019 4,000,000 800,000 3,200,000 400,000 0 400,000 

2020 4,000,000 800,000 3,200,000 400,000 0 400,000 

2021 4,000,000 800,000 3,200,000 400,000 0 400,000 

2022 4,000,000 800,000 3,200,000 400,000 0 400,000 

As expected, having fewer FFVs in the fleet translates to this group of vehicles having a 

lower gasoline/ethanol consumption potential. Based on the less optimistic FFV production 

assumptions (summarized above in Table 1.7-4) and forecasted vehicle phase-out, VMT, and 

fuel economy estimates provided by EPA’s MOVES Model, we calculate that the maximum 

percentage of fuel (gasoline/ethanol mix) that could feasibly be consumed by FFVs in 2022 

would be about 24%. The resulting gasoline energy consumption by vehicle type under the 

Committed FFV Production Scenario is shown below in Figure 1.7-5. 

247
 
Figure 1.7-5. 

Committed FFV Production Scenario - Gasoline Consumption by Vehicle Type 

0% 

10% 

20% 

30% 

40% 

50% 

60% 

70% 

80% 

90% 

100% 

% of Gasoline Consumption 

FFVs 

Tier 2 Vehicles (Non-FFVs) 

Pre-Tier 2 Vehicles 

Nonroad, HDGVs & Motorcycles 

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 

For our third and final FFV production scenario, we considered what FFV production 

might look like under some sort of Congressional mandate. At the time of our analysis, we were 

unaware of any formal legislation being considered by Congress. However, since that time there 

have been multiple bills introduced by Congress. On July 22, 2008 Senator Sam Brownback (RKS) on behalf of himself and Senators Susan Collins (R-ME), Joseph Lieberman (I-CT), Ken 

Salazar (D-CO), and John Thune (R-SD) introduced the Open Fuel Standard Act of 2008, a bill 

that calls for 50% of the U.S. vehicle fleet to be FFVs capable of using high blends of ethanol or 

methanol (in addition to gasoline) by 2012. This number would grow to 80% by 2015.477 A 

similar FFV bill was introduced by Eliot Engel (D-NY) in the House on July 22, 2008.478 

However, because our analysis was conducted before these bills were introduced, we had 

to come up with our own set of assumptions with respect to the number of FFVs and the 

implementation timeline under a theoretical mandate. Under our “Mandated FFV Production 

Scenario,” we considered the possibility that Congress could require all light-duty vehicles to be 

equipped with E85-capable fuel systems in the future. While we realize this is more aggressive 

than the mandates currently being considered by Congress, we believe this is a good upper bound 

for our ethanol usage analysis. Furthermore, we believe that such a mandate is feasible based on 

the lead-time required to engineer and implement the necessary vehicle fuel system changes. 

248
 
Under our Mandated FFV Production Scenario, we assumed that the first phase of the 

FFV mandate could require all automakers to meet the production goals set by The Detroit 3 – 

50% FFVs by 2012. From there, we assumed the mandated percentage could grow to 100% 

FFVs by 2015. This implementation timeline is consistent with Senate Bill 3303 and House 

Rule 6559 – the mandates currently being considered by Congress. For a summary of the yearby-year vehicle production assumptions we made under the Mandated FFV Production Scenario, 

refer to Table 1.7-5. 

Table 1.7-5. 

Mandated FFV Production Scenario – FFV Production Assumptions 

Year 

GM, Chrysler & Ford Non-Domestic Automakers 

Tot FFVs FFV-Cars FFV-Trucks Tot FFVs FFV-Cars FFV-Trucks 

2002 1,000,000 200,000 800,000 0 0 0 

2003 1,000,000 200,000 800,000 0 0 0 

2004 1,000,000 200,000 800,000 0 0 0 

2005 1,000,000 200,000 800,000 0 0 0 

2006 1,000,000 200,000 800,000 0 0 0 

2007 1,000,000 200,000 800,000 0 0 0 

2008 1,600,000 560,000 1,040,000 800,000 520,000 280,000 

2009 2,200,000 770,000 1,430,000 1,600,000 1,040,000 560,000 

2010 2,800,000 980,000 1,820,000 2,400,000 1,560,000 840,000 

2011 3,400,000 1,190,000 2,210,000 3,200,000 2,080,000 1,120,000 

2012 4,000,000 1,400,000 2,600,000 4,000,000 2,600,000 1,400,000 

2013 5,333,333 1,866,667 3,466,667 5,333,333 3,466,667 1,866,667 

2014 6,666,667 2,333,333 4,333,333 6,666,667 4,333,333 2,333,333 

2015 8,000,000 2,800,000 5,200,000 8,000,000 5,200,000 2,800,000 

2016 8,000,000 2,800,000 5,200,000 8,000,000 5,200,000 2,800,000 

2017 8,000,000 2,800,000 5,200,000 8,000,000 5,200,000 2,800,000 

2018 8,000,000 2,800,000 5,200,000 8,000,000 5,200,000 2,800,000 

2019 8,000,000 2,800,000 5,200,000 8,000,000 5,200,000 2,800,000 

2020 8,000,000 2,800,000 5,200,000 8,000,000 5,200,000 2,800,000 

2021 8,000,000 2,800,000 5,200,000 8,000,000 5,200,000 2,800,000 

2022 8,000,000 2,800,000 5,200,000 8,000,000 5,200,000 2,800,000 

As expected, having more FFVs in the fleet results in these vehicles having a higher 

gasoline/ethanol consumption potential. Based on the mandated FFV production assumptions 

(summarized above in Table 1.7-5) and forecasted vehicle phase-out, VMT, and fuel economy 

estimates provided by EPA’s MOVES Model, we calculate that the maximum percentage of fuel 

(gasoline/ethanol mix) that could feasibly be consumed by FFVs in 2022 would be 

approximately 68%. The resulting gasoline energy consumption by vehicle type under the 

Mandated FFV Production Scenario is shown below in Figure 1.7-6. 

249
 
Figure 1.7-6. 

Mandated FFV Production Scenario - Gasoline Consumption by Vehicle Type 

0% 

10% 

20% 

30% 

40% 

50% 

60% 

70% 

80% 

90% 

100% 

% of Gasoline Consumption 

FFVs 

Tier 2 Vehicles (Non-FFVs) 

Pre-Tier 2 Vehicles 

Nonroad, HDGVs & Motorcycles 

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 

For analysis purposes, we assumed that all FFVs would be distributed homogeneously 

throughout the nation in future years. However, the reality is, FFVs may be more concentrated 

in certain areas of the country based on variation in regional product demand (and corresponding 

FFV offerings) and state-level FFV incentives. We plan to revisit this for the final rule and also 

consider the theoretical cost and refueling frequency impacts of co-locating FFVs with E85 

stations. In the meantime, we acknowledge that there are a number of states offering incentives 

to get consumers to purchase alternative fuel vehicles (AFVs). The AFV incentives range from 

purchasing rebates to discounted registration fees and even free parking in certain metropolitan 

areas. According to a July 2008 assessment of DOE’s Energy Efficiency and Renewable Energy 

(EERE) website, 13 states currently offer some form of AFV incentive.479 A summary of these 

states is provided in Table 1.7-6 below. There are also a number of federal vehicle fleets (e.g., 

the U.S. Postal Service) and state government fleets (e.g., police departments) that require the 

purchase AFVs. 

250
 
 

 

 

 

 

Table 1.7-6. 

Alternative Fuel Vehicle Incentives 

Region States 

PADD 1 GA, NC, SC, VT 

PADD 2 IL, IN, KS, NE 

PADD 3 LA, NM 

PADD 4 MT 

PADD 5 CA, OR 

1.7.1.2.3 Projected Growth in E85 Access 

According to the National Ethanol Vehicle Coalition (NEVC), there are currently over 

1,900 retailers offering E85 in 45 states plus the District of Columbia.480 While this represents 

significant industry growth, it still only translates to about 1% of U.S. retail stations nationwide 

carrying the fuel.SSSSSS,481 As a result, most FFV owners clearly do not have reasonable access 

to E85. For our FFV/E85 analysis, we have defined “reasonable access” as one-in-four pumps 

offering E85 in a given area.TTTTTT Accordingly, just over 4% of the nation currently has 

reasonable access to E85, up from 3% in 2007 (based on a mid-year NEVC E85 pump 

estimate).UUUUUU,482 

There are a number of states promoting E85 usage by offering FFV/E85 awareness 

programs and/or retail pump incentives. There are also a growing number of states offering 

infrastructure grants to help expand E85 availability. According to a July 2008 assessment of 

DOE’s Energy Efficiency and Renewable Energy (EERE) website, 26 states currently offer some 

form infrastructure grant for facilities that bring biofuels, including E85 to market.483 A 

summary of these state programs is provided in Table 1.7-7 below. 

SSSSSS Based on the assumption that there were 1,733 E85 stations (number reported by NEVC on August 25, 2008)
 

and 164,292 total gas stations (number reported by National Petroleum News in October 2007). TTTTTT For a more detailed discussion on how we derived our one-in-four reasonable access assumption, refer to
 

Section 1.6. For the distribution cost implications as well as the cost impacts of assuming reasonable access is 

greater than one-in-four pumps, refer to Section 4.2. 

UUUUUU Computed as percent of stations with E85 (1,733/164,292 as of Aug 25, 2008 or 1251/164292 as of July 

2007) divided by 25 % (one-in-four stations).
 

251
 
 

Table 1.7-7. 

States Offering E85 Infrastructure Support 

Region States 

PADD 1 FL, ME, NY, NC, PA, SC 

PADD 2 IL, IN, IA, KS, KY, MI, MN, 

NE, ND, OH, OK, SD, TN 

PADD 3 AR, NM 

PADD 4 CO, ID 

PADD 5 CA, OR, WA 

In addition, nine Midwest states have adopted a progressive Energy Security and Climate 

Stewardship Platform.484 As of June 2008, Indiana, Iowa, Kansas, Michigan, Minnesota, North 

Dakota, Ohio, South Dakota, and Wisconsin had all committed to program which emphasizes 

energy independence through the growth of E85 availability (as well as cellulosic ethanol 

production). The platform includes a Regional Biofuels Promotion Plan with a goal of making 

E85 available at one third of all stations by 2025. In addition, on July 31, 2008, Congresswoman 

Stephanie Herseth Sandlin (D-SD) and John Shimkus (R-IL) introduced a legislative proposal 

that would increase the existing federal income tax credit from $30,000 or 30% of the total cost 

of improvements to $100,000 or 50% of the total cost of needed alternative fuel equipment and 

dispensing improvements.485 This legislation was recently reintroduced on March 26, 2009. 

While not signed into law, such a tax credit could provide a significant retail incentive to expand 

E85 infrastructure. 

Given the growing number of state infrastructure incentives and the proposed Federal 

alternative fuel infrastructure subsidy, it is clear that E85 infrastructure will continue to expand 

in the future under the RFS2 program However, the extent to which nationwide E85 access will 

grow is difficult to predict, let alone quantify. To represent practical yet aggressive station 

growth, we considered the possibility that 70% of the nation could have reasonable access to E85 

by 2022. This is roughly equivalent to all urban areas in the United States offering reasonable 

(one-in-four-station) access to E85. For this analysis, we have defined “urban” areas as: 

• The top 150 metropolitan statistical areas according to the U.S. Census Bureau and/or 

counties with the highest 150 VMT projections according the EPA MOVES model. 

•	 Federal RFG areas 

•	 Winter oxy-fuel areas 

•	 Summertime low-RVP areas 

•	 Other relatively populated cities in the Midwest. Cities with populations greater than 

100,000 people in states with a projected ethanol surplus in 2022. [For more information 

on ethanol production, refer to Sections 1.5.1 through 1.5.3 of the DRIA.] 

For an illustration of the urban areas representing about 70% of the nation’s VMT, refer to 

Figure 1.7-7. 

252
 
 

 

 

Figure 1.7-7. 

A Look at 70% E85 Access - Concentrating Pumps in Urban Areas 

We are not concluding that E85 would only be offered in urban areas in the future. In 

fact, most E85 stations are currently located in the Midwest. However, we believe that this 

would be one possible way to provide 70% of the population with reasonable access to E85. 

From a fuel price standpoint, it makes sense that E85 might be offered in areas of the country 

with relatively high gasoline prices (e.g., RFG and low-RVP areas). Additionally, from an 

infrastructure cost standpoint, it makes sense that E85 might be offered in more populated 

metropolitan areas with high gasoline throughput.VVVVVV For more on retail distribution costs, 

refer to Section 4.2 of this DRIA. 

VVVVVV We acknowledge that land costs, spatial limitations, and air quality/regulations could potentially restrict E85 

growth in densely populated metropolitan areas. However, for analysis purposes, we assumed that it would be 

possible for one-in-four stations to offer E85 to provide FFV owners with reasonable access to the fuel. 

253
 
 

2010 

2011 

2012 

2013 

2014 

2015 

2016 

2017 

2018 

2019 

2020 

2021 

2022 

Accordingly, for our primary analysis, we assumed that the percentage of the country 

with reasonable access to E85 could grow to 70% by 2022. This translates to about 29,000 

retailers offering E85, or about 1:6 stations nationwide.WWWWWW According to our distribution 

assessment, we believe it’s possible to bring this many stations to market by 2022. And 

furthermore, our analysis indicates that 29,000 stations are capable of dispensing 29 billion 

gallons of E85 – the volume required to meet the RFS2 standard in 2022 in an E10/E85 world. 

For more information on E85 retail accommodations and fuel volumes required under RFS2, 

refer to Sections 1.6.10 and 1.7.1.4, respectively. 

If we assume that reasonable E85 access grows to 70% by 2022, we can iteratively 

compute the corresponding nationwide E0 and E10 access assuming that a.) each fuel retailer 

only carries one type of conventional gasoline (E0 or E10) and b.) the nation does not exceed the 

RFS2 ethanol volume requirements presented in Section 1.2. Under the most aggressive FFV 

production scenario, we estimate that E0 could theoretically remain in existence until 2016 as 

shown below in Figure 1.7-8. However, we anticipate that E10 will likely replace E0 sooner 

based on current market trends. 

Figure 1.7-8. 

Assumed Phase-Out of E0 and Phase-In of E10 & E85 

0% 

20 % 

40 % 

60 % 

80 % 

10 0% 

Nationwide Access to Fuel 

E0 

E10 

E85 

Year 

WWWWWW Computed as the number of U.S. gas stations (164,292) times the percent of stations with reasonable 

access to E85 by 2022 (70%) times the definition of reasonable access (1-in-4 stations or 25%) 

254
 
 

 

 

2007 

2008 

2009 

2010 

2011 

2012 

2013 

2014 

2015 

2016 

2017 

2018 

2019 

2020 

2021 

2022 

As an upper bound, we considered the possibility that reasonable one-in-four E85 access 

could theoretically grow to 100% by 2022. While we do not believe this is very likely (after all, 

diesel fuel - a required fuel for compression engines is only offered at about one-third of stations 

nationwide), this is a meaningful sensitivity analysis because it corresponds to the maximum E85 

retail costs under the RFS2 program (for more on E85 infrastructure costs, refer to Section 4.2 of 

the DRIA). For both E85 access scenarios, we assumed a linear phase-in from today’s estimated 

4% access level as shown in Figure 1.7-9. 

Figure 1.7-9. 

Estimated Growth in E85 Access under RFS2 

100% 

80% 

60% 

40% 

20% 

0% 

Maximum Growth in E85 Access 

Practical Yet Aggressive Growth in E85 Access 

% of country with reasonable 1-in-4 access to E85

Year 

1.7.1.2.4 Required Increase in E85 Refueling Rates 

As mentioned above, there were approximately 7 million FFVs on the road in 2008. If all 

FFVs refueled on E85 100% of the time, this would translate to about 6.5 billion gallons of E85 

use. This estimate is based on the assumption that FFV owners travel approximately 12,000 

miles per year and get about 18 miles per gallon during actual in-use driving conditions.XXXXXX 

This estimate also assumes that it takes about 1.3 gallons of E85 for an FFV to travel the same 

distance as a gallon of gasoline due to the difference in energy density of the fuels.YYYYYY 

XXXXXX Based on the assumption that 20% of FFVs are cars (27 MPG) and 80% are trucks (20.7 MPG) and the 

assumption that all vehicles/FFVs achieve about 80% of the rated fuel economy under real driving conditions. 

YYYYYY Based on our assumption that denatured ethanol has an average lower heating value of 77,930 BTU/gal and 

conventional gasoline (E0) has average lower heating value of 115,000 BTU/gal. And based on EIA’s AEO 2008 

255
 
 

 

 

Although we computed the theoretical E85 usage potential to be around 6.5 billion 

gallons in 2007, actual E85 usage was only reported to be around 12 million gallons in 

2008.ZZZZZZ This means that, on average, FFV owners were only tapping into about 0.2% of 

their vehicles’ E85/ethanol usage potential last year. Assuming that only 4% of the nation had 

reasonable one-in-four access to E85 in 2008 (as discussed above in Section 1.7.1.2.3), this 

equates to an estimated 5% E85 refueling frequency for those FFVs that had reasonable access. 

There are several reasons for today’s low E85 refueling frequency in areas of the country 

with reasonable access to the fuel. For starters, many FFV owners may not know they are 

driving a vehicle that is capable of handling E85. As mentioned above, more and more 

automakers are starting to produce FFVs by engine/product line, e.g., all 2008 Chevy Impalas are 

FFVs.AAAAAAA486 Consequently, consumers (especially brand loyal consumers) may 

inadvertently buy a flexible fuel vehicle without making a conscious decision to do so. And 

without effective consumer awareness programs in place, these FFV owners may never think to 

refuel on E85. In addition, FFV owners with reasonable access to E85 and knowledge of their 

vehicle’s E85 capabilities may still not choose to refuel on E85. They may feel inconvenienced 

by the increased E85 refueling requirements. Based on its lower energy density, FFV owners 

will need to stop to refuel 21% more often when filling up on E85 over E10 (and likewise, 24% 

more often when refueling on E85 over conventional gasoline).BBBBBBB In addition, some FFV 

owners may be deterred from refueling on E85 out of fear of reduced vehicle performance or just 

plain unfamiliarity with the new motor vehicle fuel. However, as we move into the future, we 

believe the biggest determinant will be price – whether E85 is priced competitively with gasoline 

based on its reduced energy density and the fact that you need to stop more often, drive a little 

further to find an E85 station, and depending on the retail configuration, wait in longer lines to 

fill up on E85. 

To comply with the proposed RFS2 program and consume 34 billion gallons of ethanol 

by 2022, not only would we need more FFVs and more E85 retailers, we would need to see a 

significant increase in the current FFV E85 refueling frequency. Under the Optimistic FFV 

Production Scenario (assuming practical growth in E85 access), our analysis suggests that FFV 

owners with reasonable one-in-four access to E85 would need to fill up on it 74% of the time in 

2022 - a significant increase from today’s estimated 11% refueling frequency. As shown below 

in Figure 1.7-10, with fewer FFVs in the fleet, the E85 refueling frequency would need to be 

even higher. Similarly, with more FFVs in the fleet, the E85 refueling frequency could be lower 

and still meet the proposed RFS2 requirements. However, even with an FFV mandate, our 

analysis suggests that we would need to see an increase from today’s FFV E85 refueling 

frequency. As expected, if the E85 access were to grow beyond 70% to 100% by 2022 (refer to 

dashed lines in Figure 1.7-10) the required refueling rates would be lower. However, based on 

report, E85 was assumed to contain 74 vol% ethanol and 26 vol% gasoline on average. Our analysis ignores the 

potential that there could be a thermal efficiency improvement when vehicles burn ethanol.

ZZZZZZ EIA Annual Energy Outlook 2008, Table 17. AAAAAAA Refers to all mass produced 3.5 and 3.9L Chevy Impalas. However, it is our understanding that consumers 

may still place special orders for non-FFVs. BBBBBBB Based on our assumption that denatured ethanol has an average lower heating value of 77,930 BTU/gal and 

conventional gasoline (E0) has average lower heating value of 115,000 BTU/gal. For analysis purposes, E10 was 

assumed to contain 10 vol% ethanol and 90 vol% gasoline. Based on EIA’s AEO 2008 report, E85 was assumed to 

contain 74 vol% ethanol and 26 vol% gasoline on average. 

256
 
 

 

2010 

2011 

2012 

2013 

2014 

2015 

2016 

2017 

2018 

2019 

2020 

2021 

2022 

the cost to bring E85 to market, it is unlikely that retailers would invest in more E85 stations than 

what is necessary to meet the RFS2 program. For more information on E85 infrastructure costs, 

refer to Section 4.2 of this DRIA. 

Figure 1.7-10.CCCCCCC
 

FFV E85 Refueling Rates Needed to Meet the RFS2 Requirements 

0% 

20% 

40% 

60% 

80% 

100% 

FFV E85 Refueling Frequency (Given Access) 

Committed FFV Production (Up to 70% E85 Access) 

Optimistic FFV Production (Up to 70% E85 Access) 

Mandated FFV Production (Up to 70% E85 Access) 

Committed FFV Production (Up to 100% E85 Access 

Optimistic FFV Production (Up to 100% E85 Access) 

Mandated FFV Production (Up to 100% E85 Access) 

Year 

As shown in Figure 1.7-10, all analyzed FFV production and E85 access scenarios would 

require an increase from today’s 5% E85 refueling frequency. In order for this to be possible, we 

believe there will need to be an improvement in the current E85/gasoline price relationship. 

1.7.1.2.5 Market Pricing of E85 Versus Gasoline 

According to an online fuel price survey, E85 is currently priced almost 30 cents per 

gallon higher than conventional gasoline on an energy-equivalent basis.487 To increase our 

nation’s E85 refueling frequency to the levels described above, E85 needs to be priced 

competitively with (if not lower than) conventional gasoline based on its reduced energy content, 

increased time spent at the pump, and its limited availability. To quantify the required price 

differential, we started by examining 2006 gasoline price data. According to EIA’s 2006 

Petroleum Marketing Annual, gasoline was priced at $2.12 per gallon (average of all grades) at 

retail before taxes.488 Applying the American Petroleum Institute’s estimated gasoline tax of 

CCCCCCC Based on AEO 2008 projected gasoline energy demand. 

257
 
 

 

 

45.5 cents per gallon (average state plus federal taxes), this put retail gasoline around $2.58 per 

gallon in 2006.489 This is slightly higher than today’s gasoline prices, but a reasonable indicator 

of what prices could look like in the future based on AEO 2008 forecasted crude oil prices (refer 

to Table 1.7-8). 

Table 1.7-8. 

EIA Forecasted Imported Crude Oil Prices 

Year 

Projected Crude Oil 

Price ($/bbl) 

Change Relative to 

2006 Price (%) 

2006 66.02 

2007 67.05 1.6% 

2008 83.59 26.6% 

2009 76.96 16.6% 

2010 74.03 12.1% 

2011 71.20 7.9% 

2012 68.38 3.6% 

2013 65.61 -0.6% 

2014 62.72 -5.0% 

2015 59.85 -9.3% 

2016 56.96 -13.7% 

2017 57.11 -13.5% 

2018 57.99 -12.2% 

2019 58.91 -10.8% 

2020 59.70 -9.6% 

2021 60.56 -8.3% 

2022 61.47 -6.9% 

Source: AEO 2008, Table 12. Imported Low-Sulfur Light 

Crude Oil Price. 

In order for E85 to be priced competitively with conventional gasoline (assumed to be 

E10 by 2022), first it would need to be priced lower based on its reduced energy density.DDDDDDD 

As shown below, E85 is 79 percent as energy dense as E10. 

E85EnergyDensity 0.74 ∗ 77,930BTU / gal + 0.26 ∗115,000BTU / gal = = 0.79

E10EnergyDensity 0.10 ∗ 77,930BTU / gal + 0.90 ∗115,000BTU / gal 

Accordingly, E85 should be priced at least 21% lower at retail to compensate. This means that 

E85 would need to be priced at least 54 cents less than $2.58 per gallon gasoline. However, we 

also need to take the value of FFV owners’ time into consideration because they could be 

spending 21% more time at the pump if they are refueling exclusively on E85. In the U.S., a 

person’s time is currently valued at around $30 per hour. This value of time (VOT) estimate was 

DDDDDDD Denatured ethanol was assumed to have a lower heating value of 77,930 BTU/gal and conventional 

gasoline (E0) was assumed to have an average lower heating value of 115,000 BTU/gal. E10 was assumed to 

contain 10 vol% denatured ethanol and 90 vol% gasoline and E85 was assumed to contain 74 vol% denatured 

ethanol and 26 vol% gasoline on average (based on EIA’s AEO 2008 report). 

258
 
Refueling frequency given 

“reasonable access”

Percent of stations offering E85 in areas of the 

country with “reasonable access”, i.e., 25%

X $0.21/gal Price Advantage (1997$)

 

 

 

 

based on an average of values identified in a review of economics literature and is consistent 

with 2005 Brownstone and Small VOT estimates.490 Assuming it takes about six minutes for a 

15-gallon refill, E85 needs to be priced an additional $0.04 per gallon less than E10. 

Finally, we accounted for the fact that, as an alternative fuel, it is unlikely that E85 will 

ever be available nationwide. As mentioned above in Section 1.7.1.2.3, we project that E85 will 

only be available at one-in-four stations in 70% of the country by 2022 (under our primary, 

practical maximum scenario). And unlike diesel fuel, FFV owners are not required to fill up on 

it. So in order to get consumers to want to refuel on E85 over gasoline, there needs to be an 

additional price incentive at the pump according to a 1997 Oakridge National Lab 

report.EEEEEEE,491 As shown below in Figure 1.7-11, if an alternative fuel is only available at 

25% of stations and you want people to refuel on it about 74% of the time (refer to Section 

1.7.1.2.4), it needs to be given a 21 cent per gallon price advantage (1997$). Inflating the 1997 

David Greene estimate to 2006 dollars, E85 would need to be priced an additional 26 cents per 

gallon lower than E10. For a breakdown of the required E85 price advantage by program year 

(after the E10 blend wall), refer to Table 1.7-9. 

Figure 1.7-11. 

Required Price Incentive for Alternative Fuels with Limited Availability 

Refueling frequency given 

“reasonable access” 

Percent of stations offering E85 in areas of the 

country with “reasonable access”, i.e., 25% 

X $0.21/gal Price Advantage (1997$) 

EEEEEEE Although the 1997 David Greene study was based on asking consumers about a hypothetical fuel that 

“works just as well as gasoline”, we assumed that Figure 6 from the report (pictured above) could also be used to 

determine the retail price incentive given to E85 to account for its limited availability . As explained in the 

preceding text, this was in addition to the incentives assigned to E85 to account for its reduced energy density and 

additional time spent at the pump. 

259
 
Table 1.7-9. 

E85 Limited Availability Price Advantage by Program Year 

Year 

Required E85 

Refueling Freq 

Required Price Advantage 

1997$ 2006$* 

2013 

2014 

2015 

2016 

2017 

2018 

2019 

2020 

2021 

2022 

41% 

45% 

51% 

55% 

58% 

61% 

63% 

65% 

70% 

74% 

$0.05 

$0.06 

$0.09 

$0.11 

$0.13 

$0.14 

$0.15 

$0.17 

$0.19 

$0.21 

$0.06 

$0.08 

$0.11 

$0.14 

$0.16 

$0.18 

$0.19 

$0.21 

$0.24 

$0.26 

*Computed using U.S. Department of Labor Inflation Calculator

 http://www.bls.gov/data/inflation_calculator.htm 

To conclude, our price analysis suggests that E85 would need to be priced around $1.74 

per gallon at retail, or about a third lower than $2.58/gal gasoline in order for consumers to refuel 

on it 74% of the time in 2022. As expected, higher crude oil prices could make E85 look slightly 

more attractive. However, there would still need to be a strong E85 price incentive at the pump 

in order for consumers to want to choose it. Similarly, there would need to be a marked price 

advantage at the terminal level in order for refiners to want to blend E85 (given transportation 

costs, taxes, and marketing/other costs at retail). The ethanol and respective corn break-even 

prices for varying crude oil prices are shown below. Figure 1.7-12 shows the projected breakeven prices in 2013 (at the E10 blend wall) while Figure 1.7-13 shows the projected break-even 

prices in 2022. As shown below, the more ethanol that needs to be blended as E85 under RFS2, 

the less valuable it is to refiners. 

260
 
 

 

 

 

 

 

9 

Ethanol Breakeven Price (c/gal) 

Corn Breakeven Price ($/bshl) 

Figure 1.7-12. 

2013 Ethanol & Corn Break-Even Prices for Selling Ethanol as E85 

250
 10
 

200
 

50 85 130 

Crude Oil Price ($/bbl) 

Ethanol Breakeven Price 

Corn Breakeven Price 

This is what ethanol would 

need to be priced at in order 

for refiners to want to buy it 

and blend it as E85 

This is what corn would 

need to be priced at in 

order for ethanol to be 

marketed at the 

breakeven price after 

the $0.45/gal subsidy. 

8
 

150
 6
 

5
 

100
 4
 

3
 

50
 2
 

1
 

0
 0 

261
 

7 
 

 

 

Figure 1.7-13. 

2022 Ethanol & Corn Break-Even Prices for Selling Ethanol as E85 

250 10 

200 

50 85 130 

Crude Oil Price ($/bbl) 

Ethanol Breakeven Price 

Corn Breakeven Price 

This is what ethanol would 

need to be priced at in order 

for refiners to want to buy it 

and blend it as E85 

This is what corn would need 

to be priced at in order for 

ethanol to be marketed at the 

breakeven price after the 

$0.45/gal subsidy. 

The breakeven feedstock 

pricing for cellulosic ethanol is 

TBD; however, a more 

generous $1.01/gal subsidy 

would apply 

8 

9 

Ethanol Breakeven Price (c/gal) 

Corn Breakeven Price ($/bshl) 

7 

6 

5 

4 

150 

100 

3 

2 

1 

50 

0 0 

It is worth noting that these are the theoretical ethanol and corn breakeven prices based 

on what consumers should theoretically be willing to pay for E85 at retail. However, it is 

possible that the average consumer might be willing to pay more for E85. According to earlier 

discussions with petroleum retailers, E85 has to be priced at least 20% lower than gasoline today 

in order for consumers to refuel on it.492 This is smaller than the 33% price differential we 

computed above. However, as mentioned earlier in Section 1.7.1.2.4, we expect also expect 

consumers motivations for filling up on E85 to shift more towards price in the future when large 

volumes of ethanol need to be consumed under RFS2. For more information on gasoline/ethanol 

costs, refer to Section 4.4. 

We are aware of the challenges and coordinated efforts that would be required on the part 

of automakers, gasoline retailers, and FFV owners to get beyond the E10 blend wall. We also 

acknowledge that achievement of the proposed RFS2 standards is not necessarily limited to 

actions taken by regulated parties. However, automakers have already begun investing in FFVs 

and there are more and more E85-capable vehicles being announced each year. Furthermore, 

more than half of U.S. gasoline retail outlets are “branded” stations that are either owned by or 

affiliated with refining companies.493 As such, many retailers will have a vested interest in 

bringing E85 to market and pricing the fuel so that it is attractive to consumers. Although the 

potential compliance strategies outlined in this DRIA are aggressive, we believe they are feasible 

262
 
 

if the right market incentives are put in place. In addition, we have also considered how midlevel ethanol blends might help the nation breach the blend wall. 

1.7.1.3 The Impact of Mid-Level Ethanol Blends (E15/E20) 

For our primary ethanol usage analysis, we considered that there would only be two fuels 

in the future, E10 and E85. And as demonstrated above, we show that it is feasible to consume 

34 billion gallons of ethanol by 2022 given growth in FFV production and E85 availability and 

projected improvements in the current E10/E85 price relationship. 

However, as explained in Section V.D.3.b of the Preamble, several organizations and 

government entities are interested in pursuing mid-level ethanol blends for use in the increasing 

the concentration of ethanol beyond the current 10% limit in the commercial gasoline pool. On 

March 6, 2009, Growth Energy and 54 ethanol manufacturers submitted an application for a 

waiver of the prohibition of the introduction into commerce of certain fuels and fuel additives set 

forth in section 211(f) of the Act. This application seeks a waiver for ethanol-gasoline blends of 

up to 15% by volume ethanol. The statute directs the Administrator of EPA to grant or deny this 

application within 270 days of receipt by EPA, in this instance December 1, 2009. EPA recently 

issued a federal register notice announcing receipt of the Growth Energy waiver application and 

soliciting comment on all aspects of it. Refer to 74 FR 18228 (April 21, 2009). 

Although EPA has not yet made a waiver determination, as a sensitivity analysis, we 

considered the implications that adding E15 or E20 to the marketplace could have on ethanol 

usage and supporting fuel infrastructure should such blends be permitted. For each case, we 

assumed that E10 would need to continue to remain in existence to meet the demand of legacy 

vehicle and non-road engine owners. We assumed that Tier 2 vehicles could handle up to 20 

percent ethanol blends (i.e., E15 or E20) and flex fuel vehicles could handle up to E85 (if 

available) as shown in Table 1.7-10. 

Table 1.7-10. 

Mid-Level Ethanol Blends Vehicle/Engine Assumptions 

Gasoline Vehicle/Engine 

Classification 

Maximum ETOH 

Threshold 

Nonroad, HDGVs & Motorcycles Up to 10% 

Pre-Tier 2 "Legacy" Vehicles Up to 10% 

Tier 2 Vehicles Up to 20%* 

Flex Fuel Vehicles (FFVs) Up to 85% 

a

Contingent upon vehicle test program and waiver approval 

Although Tier 2 and flex-fuel vehicles would not be reliant on E10 in a mid-level ethanol 

blends world, we believe that maintaining E10 (for all vehicles/engines) would be beneficial in 

providing consumer choice. Experience in past fuel programs suggests that many consumers 

will not be comfortable refueling on higher ethanol blends and will blame any problems that may 

occur on the new fuel (regardless of the actual cause of the vehicle problems) causing a backlash 

263 
against the new fuel requirements. Therefore, we believe that the marketplace will continue to 

allow consumers the choice between mid-level ethanol blends and conventional gasoline (E10) 

even if a waiver were to be granted for all vehicles and engines. 

For our optimistic mid-level ethanol blends scenario, we assumed that mid-level ethanol 

blends (E15 or E20) could be made available nationwide by 2013 (or the time the nation hits the 

E10 blend wall) by utilizing existing retail storage tanks. We realize that this is a fairly 

aggressive phase-in plan given all the actions that would need to be taken to bring mid-level 

ethanol blends to market. As such, we have also considered a more gradual 10-year phase in 

(discussed in more detail below). For each scenario, we assumed that E10 would be marketed as 

premium-grade gasoline, the mid-level ethanol blend (E15 or E20) would serve as regular and, 

like today, midgrade would be blended from the two fuels as shown in Figure 1.7-14. 

Figure 1.7-14. 

Potential Mid-Level Ethanol Blends Retail Configuration 

We considered multiple retail tank configurations, but decided the fuel configuration in 

Figure 1.7-14 would be the most likely for several reasons. For starters, marketing E15 or E20 

as regular grade gasoline would allow retailers to continue to maintain the existing gasoline price 

relationship, i.e., regular is the cheapest followed by midgrade then premium. While we 

acknowledge that this is not the gasoline price relationship in all areas of the country (e.g., in 

certain Midwest cities, midgrade is priced lower than regular), we believe it represents the 

predominant retail trend. Marketing the mid-level ethanol blend as regular would also result in 

the highest possible ethanol throughput since, as shown below in Table 1.7-11, regular gasoline 

accounts for 85% of gasoline sales. Finally, we believe this configuration is advantageous 

because it allows premium gasoline to continue to be the universal fuel for all gasoline vehicles 

264
 
 

and engines. The downside to this approach is that if mid-level ethanol blends were only 

approved for flex-fuel, Tier 2 or newer vehicles then legacy vehicles and small engines would be 

forced to refuel on premium gasoline. Nonetheless, the aforementioned retail configuration is 

consistent with how SIGMA/NACS believed mid-level ethanol blends would be brought to 

market (pending approval) during our discussions with them.494 We seek comment on this 

approach and alternate ways that mid-level ethanol blends could be brought to market without 

investing in new tanks or displacing diesel fuel. 

For each mid-level ethanol blend scenario, we assumed that consumers filling up on 

conventional gasoline would choose fuel grade based on 2006 purchasing trends. A summary of 

historical gasoline purchasing data as well as our ethanol content assumptions for each fuel grade 

is found below in Table 1.7-11.495 

Table 1.7-11. 

Mid-level Ethanol Blends Vehicle/Engine Assumptions 

Grade of 

Gasoline 

% of CG 

Sales* 

Ethanol Content (vol%) 

In E15 Case In E20 Case 

Regular 85% 15% 20% 

Midgrade 6% 13% 15% 

Premium 9% 10% 10% 

*Source: EIA Petroleum Marketing Annual 2006 

Based on the vehicle capability assumptions outlined in Table 1.7-10, AEO 2009 gasoline 

energy projections, and the above refueling assumptions, we conclude that absent E85, mid-level 

ethanol blends could help increase ethanol usage to over 19 billion gallons (with E15) and 25 

billion gallons (with E20). 

As shown below in Figures 1.7-15 and 1.7-16, under an optimistic phase-in scenario 

where mid-level ethanol blends were made available nationwide by 2013, E15 could postpone 

the blend wall by up to three years to 2016 and adding E20 could postpone it another three years 

to 2019. However, if mid-level ethanol blends were phased in more gradually over ten years 

(refer to Table 1.7-12) as might occur if retailers must invest to replace existing equipment to 

distribute mid-level blends, E15 might only postpone the blend wall by one year to 2014. It 

appears E20 would continue to extend the blend wall to 2019. In both cases, we assumed that 

mid-level ethanol blends would eventually replace regular gasoline and be available nationwide. 

However if E15 and E20 only became niche fuels (like E85 is today), their ability to postpone 

the blend wall would be significantly reduced. 

265
 
2010 

2011 

2012 

2013 

2014 

2015 

2016 

2017 

2018 

2019 

2020 

2021 

2022 

Figure 1.7-15. 

Max ETOH Consumption under 2013 Mid-Level Ethanol Blends Phase-In Scenario 

0 

5 

10 

15 

20 

25 

30 

35 

40 

Billion Gallons of Ethanol 

Cellulosic Ethanol 

Imported Ethanol 

Corn Ethanol 

E20 Blend Wall 

E15 Blend Wall 

E10 Blend Wall 

Year 

266
 
2010 

2011 

2012 

2013 

2014 

2015 

2016 

2017 

2018 

2019 

2020 

2021 

2022 

Figure 1.7-16 

Max ETOH Consumption Under Gradual Mid-Level Ethanol Blends Phase-In Scenario 

0 

5 

10 

15 

20 

25 

30 

35 

40 

Year 

Billion Gallons of Ethanol 

Cellulosic Ethanol 

Imported Ethanol 

Corn Ethanol 

E20 Blend Wall 

E15 Blend Wall 

E10 Blend Wall 

Table 1.7-12 

Access to Mid-Level Ethanol Blends Under Gradual Phase-In 

% of 

Retailers 

Carrying E15 

Year or E20 

2009 0% 

2010 0% 

2011 0% 

2012 14% 

2013 29% 

2014 43% 

2015 57% 

2016 72% 

2017 86% 

2018 100% 

267
 
 

2007 

2008 

2009 

2010 

2011 

2012 

2013 

2014 

2015 

2016 

2017 

2018 

2019 

2020 

2021 

2022 

As demonstrated above, without E85, mid-level ethanol blends will fall short of meeting 

the 34 billion gallon ethanol standard. It is possible that other non-ethanol biofuels could come 

online and help the nation meet the RFS2 standard without more ethanol. However, for analysis 

purposes, we considered how the nation might meet RFS2 with a combination of mid-level 

ethanol blends and E85. For this part of the sensitivity analysis, we maintained our assumption 

that mid-level ethanol blends could be available nationwide by 2013. However, we also assumed 

that retailers would invest in E85 infrastructure in parallel. But we do not expect that retailers 

would invest as much in E85 infrastructure as in the primary E10/E85 scenario (refer to Figure 

1.7-9). For analysis purposes, we assumed that reasonable 1-in-4 access to E85 might only 

growth to 50% by 2022. Our logic behind this assumption is that gasoline retailers who have 

already made a capital investment to bring mid-level ethanol blends to market would not turn 

around and invest more than what was necessary in E85 infrastructure. The more conservative 

50% E85 access growth curve we assumed compared to our business as usual growth estimate 

(discussed more in Section 1.6) is shown below in Figure 1.7-17. For more on the retail impacts 

of bringing mid-level ethanol blends to market, refer to Section 1.6.11. 

Figure 1.7-17. 

Projected Growth in E85 Access in a Mid-Level Ethanol Blends World 

100% 

80% 

60% 

40% 

20% 

0% 

Conservative Growth in E85 Access 

Business as Usual E85 Access 

% of country with reasonable 1-in-4 access to E85

Year 

It is worth noting, that this graph assumes a gradual, linear phase in of E85 infrastructure 

reaching 50% by 2022. In reality, retailers might wait until after the E15 or E20 blend wall to 

really invest in E85 infrastructure. The result would be negligible E85 station growth until the 

2014-2019 timeframe (depending on the mid-level ethanol blend and phase-in scenario) and then 

268 
 

 

2010 

2011 

2012 

2013 

2014 

2015 

2016 

2017 

2018 

2019 

2020 

2021 

2022 

steep growth in E85 infrastructure. While this would arguably provide retailers with the most 

lead-time to postpone their E85 investments, it could result in unrealistic E85 station growth. As 

a result, for analysis purposes, we analyzed the gradual phase-in on E85 infrastructure shown 

above in Figure 1.7-17 

In the hypothetical mid-level ethanol blends and E85 world, we assumed that automakers 

would only produce the “committed” number of FFVs detailed in Table 1.7-4. To re-summarize, 

this involves The Detroit 3 following through with their 50% FFV commitment and no 

significant growth in non-domestic FFV production (beyond what was forecasted in 2009 MY 

offerings). To meet the RFS2 requirements with mid-level ethanol blends and this lessaggressive E85/FFV scenario, would require the following FFV E85 refueling rates. 

Figure 1.7-18. 

FFV E85 Refueling Rates Needed to Meet the RFS2 Requirements 

0% 

20% 

40% 

60% 

80% 

100% 

FFV E85 Refueling Frequency (Given Access) 

E10/E85, 70% E85 Access 

E10/E15/E85, 50% E85 Access 

E10/E20/E85, 50% E85 Access 

Year 

As shown above in Figure 1.7-18, in an E10/E15/E85 world (with committed FFV 

production and E85 access reaching 50% by 2022), the required FFV E85 refueling rate would 

be just as high in 2022 as that in the E10/E85 world (with optimistic FFV production and E85 

access reaching 70% by 2022). This scenario would essentially demand the same changes to the 

E10/E85 price relationship as described in Section 1.7.1.2.5 but could result in higher capital 

costs (depending o the retail cost assumptions). For this reason, E20 might make more sense 

than E15 if they were to both require the same retail upgrades. For more on retail 

269
 
 

accommodations and costs of mid-level ethanol blends, refer to Sections 1.6.11 and 4.2 of this 

DRIA. 

1.7.1.4 Impacts on 2022 Fuel Volumes 

As explained in Section 1.7.1.2.1, fixing gasoline energy demand according to AEO 2008 

essentially dictates how much ethanol can be consumed as conventional gasoline. As a result, 

making different assumptions regarding the ethanol content of conventional gasoline (i.e., E10, 

E15, or E20), impacts the nation’s ethanol usage potential and the timing of the respective blend 

walls under the proposed RFS2 program (refer to Figures 1.7-15 and 1.7-16). Adding in 

E85/FFVs to meet the RFS2 volume requirements shifts ethanol usage out of conventional 

gasoline and into E85. As shown below in Tables 1.7-13 and 1.7-14, although holding total 

gasoline energy demand and the ethanol volume constant under RFS2 fixes the overall fuel 

volumes in 2022, it changes the distribution of ethanol. 

270
 
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271
 
272 

Table 1.7-13. 

Comparison of Total Fuel Volumes Under Various Scenarios 

Fuel Scenario 

Projected 2022 Fuel Volumes 

E10 E12.5 E15 E20 E85 

Blend Wall Blend Wall 

Blend Wall 

E10 Nationwide (No E15, E20 or E85) 

E10 & E15 Nationwide (No E85)a 

E10 & E20 Nationwide (No E85)b 

147.61 

31.27 31.27 

0.00 

7.39 0.00 

0.00 

110.85 

7.45 

0.00 

0.00 

112.76 

0.00 

0.00 0.00 

RFS2 Control Case RFS2 Control Case RFS2 Control Case 

E10/E85 Scenario (No E15 or E20) 

Combination E10/E15/E85 Scenarioa 

Combination E10/E20/E85 Scenariob 

124.55 

29.67 30.34 

0.00 

6.41 0.00 

0.00 

96.24 

6.88 

0.00 

0.00 

104.14 

29.30 

21.54 

12.50 

aAssumes E12.5 (midgrade) is blended from E10 (premium) and E15 (regular). bAssumes E15 (midgrade) is blended from E10 (premium) and E20 (regular). 

Table 1.7-14. 

Comparison of Ethanol Volumes Under Various Scenarios 

Fuel Scenario 

Projected 2022 Ethanol Usage 

E10 E12.5 E15 E20 E85 

Blend Wall Blend Wall Blend Wall 

E10 Nationwide (No E15, E20 or E85) 

E10 & E15 Nationwide (No E85) 

E10 & E20 Nationwide (No E85) 

14.76 

3.13 3.13 

0.00 

0.92 0.00 

0.00 

16.63 

1.12 

0.00 

0.00 

22.55 

0.00 

0.00 0.00 

RFS2 Control Case RFS2 Control Case RFS2 Control Case 

E10/E85 Scenario (No E15 or E20) 

Combination E10/E15/E85 Scenario 

Combination E10/E20/E85 Scenario 

12.45 

2.97 

3.03 

0.00 

0.80 

0.00 

0.00 

14.44 

1.03 

0.00 

0.00 

20.83 

21.69 

15.94 

9.25 

aAssumes E12.5 (midgrade) is blended from E10 (premium) and E15 (regular). bAssumes E15 (midgrade) is blended from E10 (premium) and E20 (regular). 
This page intentionally left blank. 
274 

 

 

 

 

 

1.7.1.5 Projected Ethanol Consumption by County in 2022 

To understand the impacts of increased ethanol use on emissions and air quality (to be 

modeled under the final rule), we estimated where the ethanol might be used under the RFS2 

program. We started by assuming that E10 would be available nationwide in 2022 (no E0), and 

for this county-level analysis, we focused on our primary E85/FFV scenario. We assumed 

practical, yet aggressive growth in E85 access (one-in-four station access reaching 70% by 

2022). With respect to FFVs, we assumed optimistic production (outlined in Table 1.7-4) and 

made the simplifying assumption that all FFVs would be distributed homogeneously.FFFFFFF As 

explained in Section 1.7.1.2, this determined the manner in which E85 would be consumed (i.e., 

the number of FFVs required, the number of E85 stations, and the average FFV E85 refueling 

frequency). However, it does not tell us where E85 would be consumed. 

To estimate where E85 might be consumed under the proposed RFS2 program in 2022, 

we conducted a cost effectiveness study. For each area of the county, we began by looking at 

gasoline delivered prices. We started with state-level gasoline prices (excluding taxes) provided 

by EIA’s Petroleum Marketing Annual 2006.496 We relied on Table 31 for average gasoline 

prices, looked to Table 34 for RFG prices and back-calculated CG prices by applying the 

respective gasoline fuel volumes provided in Table 48. For states requiring 7 or 7.8-lb gasoline 

in the summertime, we applied PADD-average low-RVP gasoline production costs derived from 

the Mobile Source Air Toxics (MSAT) rule497 to come up with the respective low-RVP and 9-lb 

conventional gasoline prices in these states. From there, we added in the corresponding gasoline 

taxes (state plus federal) according to the American Petroleum Institute (API).498 This gave us 

the average retail cost of gasoline by state and fuel type. 

Next we converted the gasoline prices into competitive retail E85 prices by adjusting for 

the reduced energy density of E85, the increased refueling time, and E85’s presumed limited 

availability in 2022. For a more detailed assessment, refer to Section 1.7.1.2.5. From there, we 

deducted fuel taxes (assumed to be the same as gasoline), backed out marketing costs and retail 

profits (assumed to be $0.10 per gallon) and subtracted the terminal-to-retail transportation costs 

(assumed to be $0.03) to arrive at the estimated retail value of E85, and ultimately, the retail 

value of ethanol.GGGGGGG Once we computed the retail value of ethanol, we compared it to the 

estimated ethanol delivered price (based on transportation costs presented in Section 4.2) to 

come up with the respective E85 profit margin. 

To conclude, we assigned E85 to the areas of the county with the highest E85 profit 

margins, or in some cases, the least negative E85 profit margins until we arrived at 

approximately 34 billion gallons of ethanol in 2022. For a graphical representation of the areas 

of the country we assumed would receive/consume E85, refer to Figure 1.7-19. 

FFFFFFF We plan on looking into purchasing FFV registration data or relying on the DOE FFV study required under 

EISA for the final rule. 

GGGGGGG For analysis purposes we assumed that E85 was taxed at the same rate as gasoline. We acknowledge that a 

number of states currently have reduced excise taxes or excise tax exemptions for E85. However, the extent of the 

tax breaks is somewhat unknown and the potential that these tax breaks will exist in the future is uncertain. We plan 

on revisiting state-level E85 excise tax exemptions for the Final Rule. For more on marketing and transportation 

costs, refer to Section 4.4 of the DRIA. 
 

 

Figure 1.7-19. 

Projected E85 Usage in 2022 Under RFS2 

1.7.2 Biodiesel & Renewable Diesel Consumption 

Biodiesel, like ethanol, is generally blended at the end of the distribution chain, just 

before delivery to retail outlets. Because of its chemical properties, it is not currently considered 

fungible with diesel fuel, and thus its blend level in fuels offered for sale is typically deliberate 

and explicit. Renewable diesel, on the other hand, is a fuel or hydrocarbon blendstock which can 

be blended into fungible fuel at any point in the distribution system, such that the blend level at 

the final point of use is not typically of concern and, in fact, would probably be difficult to 

determine. Because of its nature, and the relatively small volumes we are projecting (less than 

0.5 billion gallons per year), we have not analyzed distribution or use impacts for renewable 

diesel. The remainder of this section addresses biodiesel use. 

Vehicle and engine manufacturers recognize biodiesel as a lubricity improver at low 

levels, something that is useful with ultra-low sulfur diesel fuel now phasing in across the 

country. Therefore, most state that their products are compatible with blends up to 5%, and a 

few suggest blends up to 20% can be used without problems. Therefore, our analysis assumes 

blends up to 5% can find widespread use. 
In order to conduct our distribution and emissions analyses, we needed to forecast 

approximate volumes of biodiesel to be used in each state. We considered transportation diesel 

fuel and home heating oil as the primary uses for biodiesel. For transportation fuel estimates, we 

assumed that biodiesel would be preferentially used in states that have blend mandates or 

significant per-gallon incentives. Table 1.7-14 shows the states with such mandates and 

incentives on record as of summer 2008, as well as the associated potential biodiesel volumes 

based on 2005 diesel fuel use.499 State-level forecasts were not available for transportation fuel 

use, thus the reliance on historical data for this estimate. 

Table 1.7-14. 

State biodiesel incentives as of summer 2008 and potential volumes based on 2005 data.500 

Diesel fuel use 2% biodiesel 5% biodiesel 

(million gal/yr) (million gal/yr) (million gal/yr) 

IL per-gallon tax incentive(s) for B11+, 

state fleet requirement 

1,660 33.2 

State Incentive or mandate 

KS per-gallon tax incentive(s) for B2+ 816 16.3 

LA B2 mandate with some conditions 1,734 34.7 

MA B2 mandate, increasing to B15 with 491 24.5 

some conditions 

MI per-gallon tax incentive(s) for B5+ 1,071 53.5 

MN B2 mandate; state fleet requirement 999 20.0 

NC per-gallon tax incentive(s), B2 school 1,234 24.7 

bus requirement 

ND per-gallon tax incentive(s) 358 7.2 

NE per-gallon tax incentive(s) 547 10.9 

NM B5 mandate with some conditions 475 23.7 

OH per-gallon tax incentive(s) 1,556 31.1 

OR B2 mandate, increasing to B5 with 738 36.9 

some conditions 

SC per-gallon tax incentive(s) 764 15.3 

SD per-gallon tax incentive(s) 263 5.3 

TX per-gallon tax incentive(s) 5,339 106.8 

WA B2 mandate, increasing to B5 with 1,230 24.6 

some conditions 

Total biodiesel 468.7 

Table 1.7-15 shows home heating oil use in 2005. We estimate potential biodiesel use in 

heating oil at 89 million gallons per year based on a 2% blend in all heating oil north of the 

Washington, DC, area (i.e., PADD 1A and 1B). This area was chosen because it is where the 

majority of heating oil is used, and should have adequate biodiesel access from New Jersey, 

Pennsylvania, and Connecticut in our forecasted production scenarios (see Section 1.5.4). To the 

extent that heating oil use declines over time, the blend levels may increase in some areas or in 

the shoulder seasons, such that the total biodiesel volume used in this market would not decline 

drastically. 

276
 
 

Table 1.7-15. 

Potential biodiesel use in heating oil based on 2005 data.501 

Heating oil 2% biodiesel Volume Used 

(million gal/yr) (million gal/yr) (million gal/yr) 

U.S. 5,565,489 111.3 

Area 

PADD 1 4,759,198 95.2 

PADD 1A 1,923,405 38.5 38.5 

CT 545,910 10.9 

ME 308,464 6.2 

MA 674,324 13.5 

NH 175,484 3.5 

RI 136,618 2.7 

VT 82,604 1.7 

PADD 1B 2,529,106 50.6 50.6 

DE 33,221 0.7 

DC 12,832 0.3 

MD 149,919 3.0 

NJ 322,088 6.4 

NY 1,282,899 25.7 

PA 728,147 14.6 

PADD 1C 306,687 6.1 

FL 3,608 0.1 

GA 1,520 0.0 

NC 81,528 1.6 

SC 8,810 0.2 

VA 197,255 3.9 

WV 13,966 0.3 

Total used for biodiesel in heating oil 89.1 

Combining these volumes gives 558 million gallons per year potential biodiesel 

consumption, leaving approximately 250 million gallons to be sold in blends above the projected 

levels shown here, or in states not included here. Further use and distribution of biodiesel is 

discussed in more detail in Section 4.2.2.2. 
Chapter 2: Lifecycle GHG Analysis 

2.1 Lifecycle Introduction and Summary 

As part of proposed revisions to the National Renewable Fuel Standard program 

(commonly known as the RFS program), EPA is estimating lifecycle greenhouse gas (GHG) 

emissions from increased renewable fuels use. The Energy Independence and Security Act of 

2007 (EISA) establishes new renewable fuel categories and eligibility requirements, including 

setting the first-ever mandatory lifecycle GHG reduction thresholds for renewable fuel 

categories, as compared to those of average petroleum fuels used in 2005 (base year established 

by EISA). This chapter describes the methodology developed by EPA to determine the lifecycle 

GHG emissions of renewable fuels as required by EISA. This methodology was utilized to 

determine which renewable fuels qualify for the four different GHG reduction thresholds 

specified in EISA. The overall GHG benefits of the RFS program, which are based on the same 

methodology presented here, are also provided. 

The GHG provisions in EISA are notable for the GHG thresholds mandated for each 

category of renewable fuel and also the mandated lifecycle approach to those thresholds. 

Renewable fuel must achieve a 20% reduction in lifecycle greenhouse gas emissions compared 

to the average for gasoline or diesel sold or distributed as transportation fuel in 2005. Similarly, 

biomass-based diesel and advanced biofuels must achieve a 50% reduction, and cellulosic 

biofuels a 60% reduction. To EPA’s knowledge, the GHG reduction thresholds in EISA are the 

first lifecycle GHG performance requirements included in federal law. While these thresholds 

do not directly constitute a greenhouse gas control program for renewable fuels, in combination 

with the volume mandates, they are designed to ensure significant GHG emission reductions 

from the use of renewable fuels and to encourage the use of GHG-reducing renewable fuels. 

The definition of lifecycle greenhouse gas emissions established by Congress states that: 

The term ‘lifecycle greenhouse gas emissions’ means the aggregate quantity of 

greenhouse gas emissions (including direct emissions and significant indirect 

emissions such as significant emissions from land use changes), as determined by 

the Administrator, related to the full fuel lifecycle, including all stages of fuel and 

feedstock production and distribution, from feedstock generation or extraction 

through the distribution and delivery and use of the finished fuel to the ultimate 

consumer, where the mass values for all greenhouse gases are adjusted to 

account for their relative global warming potential.502 

This definition requires the Agency to look broadly at lifecycle analyses and to develop a 

methodology that accounts for all of the important factors that may significantly influence this 

assessment, including the secondary or indirect impacts of expanded biofuels use. EPA’s 

analysis suggests that the assessment of lifecycle GHG emissions for biofuels is significantly 

affected by the secondary agricultural sector GHG impacts from increased biofuel feedstock 

production (e.g., changes in livestock emissions due to changes in agricultural commodity 

prices) and the international impact of land use change from increased biofuel feedstock 

278 
 

production. Thus, these factors must be appropriately incorporated into EPA’s lifecycle 

methodology to properly assess the full lifecycle GHG performance of biofuels in accordance 

with the EISA definition of lifecycle GHG emissions. As discussed below, there are many other 

potential impacts (e.g., hypoxia in the Gulf of Mexico) that do not have a meaningful impact on 

the lifecycle GHG analysis and therefore fall outside the scope of this analysis. 

Currently, no single model captures all of the interactions associated with estimating 

lifecycle GHG emissions for renewable fuels, taking into account the "significant indirect 

emissions” required by EISA. EPA’s approach has been to use the best tools available for each 

specific component of the lifecycle to create a comprehensive estimate of GHG emissions (See 

Figure 2.1-1). As required by EISA, the broad system boundaries of our analysis encompass all 

significant secondary agricultural sector GHG impacts, not just impacts from land use change. 

Figure 2.1-1. System Boundaries and Models and Data Sources Used 

To quantify the lifecycle GHG emissions associated with the increase in renewable fuels 

mandated by EISA, we compared the differences in total GHG emissions between two future 

scenarios. The first assumed a “business as usual” volume, or reference case, of a particular 

renewable fuel based on what would likely be in the fuel pool from now until 2022 without 

EISA. The reference case includes technological advances, such as crop yield improvements, 

that are likely to occur irrespective of EISA. The second scenario assumed higher volumes of 

renewable fuels as mandated by EISA. Rather than focus on the impacts associated with a 

specific gallon of fuel and tracking inputs and outputs across different lifecycle stages, we 

279 
 

 

 

determined the overall aggregate impacts across sections of the economy in response to a given 

volume change in the amount of biofuel produced.HHHHHHH Table 2.1-1 provides an overview of 

the volumes of renewable fuels modeled for this analysis. More details about the fuel volumes 

modeled, including sensitivity analysis volume runs, are provided in Section 2.6 of this Chapter. 

Table 2.1-1. Renewable Fuel Volumes Modeled 

Fuel 

Volume (Billions of Gallons) 

Reference Case 

Control 

Case 

Net 

Change 

Corn Ethanol 12.4 15 2.6 

Corn Stover Ethanol 0 7.6 7.6 

Biodiesel 0.4 0.7 0.3 

Sugarcane Ethanol 0.6 3.1 2.5 

Switchgrass Ethanol 0 3.2 3.2 

2.1.1 Results 

EPA’s results suggest that biofuel induced land use change can produce significant nearterm emissions, but that biofuels have GHG emissions benefits by displacing the use of 

petroleum-based fuels in subsequent years that can “payback” earlier land conversion GHG 

releases. Therefore, choosing an appropriate time horizon for analysis is essential when 

comparing biofuels with petroleum-based fuels. Whether or not to discount future emissions is 

also critical because it determines the relative importance of near-term versus longer-term 

emissions. The type of land (e.g., forest or grassland) that is converted to cropland as a result of 

biofuel production is another factor that strongly influences overall lifecycle GHG reduction 

estimates. 

Figures 2.1-2 and 2.1-3 show how EPA’s lifecycle GHG emission estimates vary by 

lifecycle stage for each biofuel analyzed. We calculated a net present value of emissions because 

it provides a common metric for direct comparison of lifecycle emissions from biofuels and 

petroleum fuels. Figure 2.1-2 includes results using a 100-year time horizon and a 2% discount 

rate. The results in Figure 2.1-2 use a 30-year time horizon and a 0% discount rate. Our primary 

estimates include GHG emissions from forest, shrub, savanna and grassland clearing 

(proportionally estimated based on MODIS satellite data) resulting from biofuel production.IIIIIII 

The tables also show how total net lifecycle GHG emissions estimates would vary if we assumed 

that all new cropland would come from forest, or all from grasslands. The choice of time 

horizon, discount rate, and land use change estimates are discussed in detail in the preamble to 

the proposed rule. 

HHHHHHH We then normalize those impacts for each gallon of fuel (or Btu) by dividing total impacts over the given 

volume change. Net lifecycle GHG emissions are reported as grams of carbon dioxide equivalent per million Btu 

(gCO2eq/mmBtu). 

IIIIIII Per acre land use change emissions factors were estimated by Winrock International Inc., following 2006 

Intergovernmental Panel on Climate Change guidelines 

280 
Our results indicate that emissions produced during the fuel production stage can vary 

significantly for corn ethanol depending on the type of facility used to convert corn into ethanol. 

A typical dry mill corn ethanol production facility fired with natural gas produces 32,579 grams 

of carbon-dioxide equivalent emissions per million British Thermal Units (gCO2-eq./mmBtu) of 

ethanol produced per year. For corn ethanol, emissions at the fuel production stage can range 

from 60,209 gCO2-eq./mmBtu for a coal-fired dry mill in the higher emitting case; to 9,688 

gCO2eq/mmBtu for a biomass-fired dry mill in the lower emitting case. Clearly, the choice of 

fuel production technology can be used as a measure to reduce the climate impact of corn ethanol 

production. 

Conversion of cellulosic feedstocks (e.g., corn stover or switchgrass) to ethanol creates a 

net sequestration of carbon during the fuel production stage. Ethanol is fermented with the 

cellulosic portion of the biomass, while process energy is generated through the unfermentable 

portion (mainly lignin) of incoming biomass. Based on NREL estimates, the process is assumed 

to generate more than 8,000 Btu of excess electricity per gallon of ethanol produced. Biomassfired electricity generation reduces GHG emissions by offsetting other forms of electricity 

production. 

Figure 2.1-2. Lifecycle GHG Results 

Using 100-Year Net Present Value with 2% Discount Rate 160% Fuel Production 

140% 

ions) 

Tailpipe 

miss

International Land Use Change 

E

120% 

HG 

International Farm Inputs and G

Fert N2O 100% 

ycle 

Other (fuel and feedstock 

ifec

transport) 

80% 

ine L

Domestic Soil Carbon 

Basel

60% International Livestock 

leum 

International Rice Methane 

tro

40% 

f Pe

Domestic Rice Methane 

20% 

(% o

Domestic Farm Inputs and 

ons 

Fert N2O 

0% Domestic Livestock 

-20% 

GHG Emissi

Cellulosic Threshold 

Advanced and Biodiesel 

-40% Threshold 

Conventional Threshold 

Net Emissions * 

*Range shows net emissions if we assume all land conversion from forest (upper bound) or all from grassland 

(lower bound). 

-128% 

-115% 

-16% 

13% 

-39% -44% 

-22% 

-80% 

Dry Mill 

Natural Gas 

Dry Mill Coal Dry Mill 

Biomass 

Switchgrass Corn Stover Sugarcane Soy-Based Waste 

Grease 

GASOLINE 

BASELINE 

CORN ETHANOL CELLULOSIC ETHANOL ADVANCED 

ETHANOL 

DIESEL 

BASELINE 

BIODIESEL 

281 
Figure 2.1-3. Lifecycle GHG Results 

Using 30-Year Net Present Value with 0% Discount Rate
 

180% 

-124% 

-26% -26% 

-18% 

+34% 

-18% 

+5% 

-116% 

-26% 

+4% 

-80% 

Dry Mill Natural Gas

2022 Best Case Dry

Mill NG

Dry Mill Coal

Dry Mill Biomass

2022 Dry Mill

Biomass w/ CHP

Wet Mill Biomass

Switchgrass

Corn Stover

SugarcaneSoy-Based

Waste Grease 

GASOLINE 

BASELINE 

CORN ETHANOL CELLULOSIC 

ETHANOL 

ADVANCED 

ETHANOL 

DIESEL 

BASELINE 

BIODIESEL 

Fuel Production 

160% Tailpipe 

140% 

GHG Emissions (% of Petroleum Baseline Lifecycle GHG Emissions) 

International Land Use Change 

120% 

International Farm Inputs and 

Fert N2O 100% 

Other (fuel and feedstock 

80% transport) 

Domestic Soil Carbon 

60% 

International Livestock 40% 

International Rice Methane 20% 

0% Domestic Rice Methane 

-20% Domestic Farm Inputs and 

Fert N2O 

-40% Domestic Livestock 

-60% Cellulosic Threshold 

Advanced and Biodiesel 

Threshold 

Conventional Threshold 

Net Emissions * 

* Range shows net emissions if we assume all land conversion from forest (upper bound) or all from grassland 

(lower bound). 

Figures 2.1-2 and 2.1-3 also include indirect emissions impacts that result from fuel 

production or use, such as changes in livestock inventories, or shifts in acreage between different 

types of crops. For example, the FASOM model projects that increasing the production of soybased biodiesel will reduce domestic livestock and rice production, which reduces methane 

emissions from those sectors. To compensate for this decrease in domestic rice and livestock 

production, the FAPRI models project that foreign countries will expand their rice and livestock 

production. There are similar indirect effects on farming practices, which impact soil carbon 

emissions and emissions from agricultural energy use. 

The benefit of using renewable fuels that displace petroleum fuel consumption is seen 

primarily at the end use, or tailpipe, stage of the fuel lifecycle. Combustion CO2 emissions for 

ethanol, biomass-based diesel, petroleum diesel and gasoline were based on the carbon content 

of the fuel. However, over the full lifecycle of the fuel, the CO2 emitted from 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. Unlike CO2 emissions, the combustion of biomass-based fuels does result in 

net additions of methane and N2O to the atmosphere. Therefore, combustion methane and N2O 

emissions are included in the lifecycle GHG emissions results for biomass-based fuels. Net 

carbon fluxes from changes in biogenic carbon reservoirs in wooded or crop lands are accounted 

for separately in the land use change analysis as outlined in the agricultural sector modeling 

above. 

282 
2.1.2 Greenhouse Gas Emissions from Land Use Changes 

We estimated GHG emissions associated with land use changes that occur domestically 

and internationally as a result of increasing renewable fuels demand in the U.S. Key questions 

we addressed included the area of land converted to crop production, where those acreage 

changes would occur, the types of land converted to crop production, and the GHG emissions 

associated with different types of land conversion. In general, we found that land use change 

impacts are larger when food crops (such as corn or soybeans) are used as biofuel feedstocks 

than when non-food crops (such as corn stover or switchgrass) are converted to biofuel. EPA 

recognizes that estimating the international impacts of land use change can introduce additional 

uncertainty to the lifecycle GHG emissions estimates, and we present a range of results. 

We used the FAPRI model to estimate international crop expansion, and the FASOM 

model to estimate domestic crop expansion. The results are summarized in Figure 2.1-4. 

Overall, soy-based biodiesel induces the most crop expansion per gallon of production. One 

reason for this is that soybeans are a relatively low-yield crop compared to corn and sugarcane in 

terms of how many gallons of biofuel can be produced per acre of crop production. Crop 

expansion caused by corn ethanol production is also offset to some degree by the production of 

distillers grains (DGs), a major co-product of dry mill ethanol production that is also used as 

animal feed. 

Figure 2.1-4. Regional Crop Expansion by Renewable Fuel, 2022 

(acres per thousand ethanol equivalent gallons of biofuel production) 

Soy-Based Biodiesel Corn Ethanol Sugarcane Ethanol Switchgrass Ethanol 

0.0 

0.5 

1.0 

1.5 

2.0 

2.5 

Argentina Brazil India China EU & Nigeria Other Paraguay Other Rest of S.E. Asia U.S. World 

Russia Africa Latin World Total 

America 

283 
 

 

The percentage of each land type converted to cropland was estimated according to 

MODIS satellite-based data (See Table 2.1-2).JJJJJJJ We extrapolated the recent land use trends, 

as determined with the satellite data, into the future to estimate the most likely places for crop 

expansion on a sub-regional basis, and the types of land that would most likely be converted to 

crop production. For the proposed rule, land use trends and emissions factors were estimated for 

ten countries including Argentina, Brazil, China, India, Indonesia, Malaysia, Mexico, 

Philippines, EU and South Africa.KKKKKKK 

Table 2.1-2. Types of Land Converted to Cropland by Country, 2001-2004 

Country Forest Grassland Savanna Shrub 

Argentina 8% 40% 45% 8% 

Brazil 4% 18% 74% 4% 

China 17% 38% 23% 21% 

E.U. 27% 16% 36% 21% 

India 7% 7% 33% 53% 

Indonesia 34% 5% 58% 4% 

Malaysia 74% 3% 19% 3% 

Nigeria 4% 56% 36% 4% 

Philippines 49% 5% 44% 3% 

South Africa 10% 22% 53% 15% 

To estimate the GHG impacts of projected land use changes, emissions factors were 

calculated by Winrock following 2006 Intergovernmental Panel on Climate Change (IPCC) 

Agriculture, Forest and Other Land Use (AFOLU) guidelines.503 Emissions factors were based 

on the initial changes in above and below ground biomass carbon stocks as well as changes in 

soil carbon stocks, non-CO2 emissions from clearing with fire, and forgone forest sequestration. 

In general, for the countries analyzed, emission factors for all land use types were highest in the 

South East Asian countries of Malaysia, Indonesia and Philippines and lowest in Argentina and 

Nigeria. 

The GHG emissions associated with converting land into crop production accumulate 

over time, with the largest releases occurring in the first few years due to clearing with fire and 

biomass decay. After land is converted to crop production, moderate amounts of soil carbon 

would continue to be released for approximately 20 years. Furthermore, when forest is cleared 

there would be foregone sequestration for approximately 80 years associated with the fact that 

the forest would have continued to grow had it not been cleared. Section 2.6.5 provides details 

about our estimates of GHG emissions from land use changes. 

2.1.3 Treatment of Future Greenhouse Gas Emissions 

When comparing the lifecycle GHG emissions associated with biofuels to those 

associated with gasoline or diesel emissions, it is critical to consider the timing of GHG releases 

from the lifecycle of each fuel type. With gasoline, a majority of the GHG emissions associated 

with extraction, conversion, and combustion are likely to be released over a short period of time 

JJJJJJJ The 17 MODIS imagery land cover classes were reclassified using the International Geosphere Biosphere 

Programme land cover dataset into five general classes: cropland, forest, grassland, savanna and shrubland. 

KKKKKKK We are in the process of acquiring data for more countries to be used for the final rule. 

284 
(i.e., annually) as crude oil is converted into gasoline or diesel fuel which quickly pass to market. 

In contrast, the land use change GHG emissions associated with the use of a typical biofuel (e.g., 

corn-based ethanol) may occur over a longer period of time. While biomass feedstocks grown 

each year on new cropland can be converted to biofuels that offer an annual GHG benefit relative 

to the petroleum product they replace, these benefits may be small compared to the upfront GHG 

emissions from land clearing. Depending on the specific biofuel in question, it can take many 

years for the benefits of the biofuel to “payback” the initial GHG releases resulting from land use 

change. 

As shown in Figure 2.1-5, the payback period for corn ethanol produced in a natural gasfired dry mill is approximately 33 years; soy-based biodiesel has a payback period of about 32 

years; sugarcane ethanol’s payback period is approximately 18 years; and it takes about 3 years 

for switchgrass ethanol use to offset initial land clearing emissions. Corn stover and waste 

grease biodiesel are not shown in Figure 2.1-5, because both biofuels produce GHG reductions in 

the first year. In our analysis, the annual gasoline and diesel baseline emissions do not vary over 

time; instead, their lifecycle impacts are replicated every year to match the lifecycle emissions 

from average 2005 petroleum fuel. The cumulative net emissions for corn ethanol and soy-based 

biodiesel cross after approximately 27 years, because soy-based biodiesel has larger initial land 

use change emissions but lower subsequent annual emissions from the non-land use impacts of 

the lifecycle. 

EISA requires EPA to determine which biofuel production pathways reduce GHG 

emissions by the required threshold amounts relative to the 2005 petroleum baseline. A payback 

period alone cannot answer that question. Since the payback period is not sufficient for our 

analysis, we must account for the variable time profiles of lifecycle GHG emissions and provide 

a common metric that allows for a direct comparison of lifecycle emissions from biofuels and 

petroleum fuels. When considering the time profile of GHG emissions, two assumptions that 

have a significant impact on the determination of whether a biofuel meets the emissions 

reduction threshold are: 1) the time horizon of emissions considered in the analysis and 2) the 

discount rate applied to future emissions. 

The importance of the time horizon for analysis is clearly illustrated by the payback 

periods of various biofuels. If we select a time horizon that is shorter than the payback period 

for a given biofuel, then we will determine that the biofuel in question increases GHG emissions. 

On the other hand, if we choose a very long time horizon, all of the biofuels we analyzed will 

eventually reach the GHG reduction thresholds specified by EISA. 

285 
Gasoline

Diesel

Soy Based Biodiesel

Corn Ethanol

Sugarcane Ethanol

Switchgrass Ethanol

Corn Ethanol Cumulative Net Emissions

Soy Based Diesel Cumulative Net Emissions

Sugarcane Ethanol Cumulative Net Emissions

Switchgrass Ethanol Cumulative Net Emissions

Year 0 Land Use 

Emissions:

-Clearing with Fire

-Biomass Decay

-Soil Carbon

-Foregone Sequestration

Years 1-19 Land Use 

Emissions:

Soil Carbon

Foregone Sequestration

Years 20 79 Land Use 

Emissions:

-Foregone Sequestration

 

Figure 2.1-5. Annual Lifecycle GHG Emissions Over Time and Payback Periods 

-100,000

100,000

300,000

500,000

700,000

900,000

1,100,000

1,300,000

GHG Emissions (gCO2eq / mmBtu)

-

-

-

-

-

-100,000 

100,000 

300,000 

500,000 

700,000 

900,000 

1,100,000 

1,300,000 

GHG Emissions (gCO2eq / mmBtu) 

Gasoline 

Diesel 

Soy-Based Biodiesel 

Corn Ethanol 

Sugarcane Ethanol 

Switchgrass Ethanol 

Corn Ethanol Cumulative Net Emissions 

Soy-Based Diesel Cumulative Net Emissions 

Sugarcane Ethanol Cumulative Net Emissions 

Switchgrass Ethanol Cumulative Net Emissions 

Year 0 Land Use 

Emissions: 

-Clearing with Fire 

-Biomass Decay 

-Soil Carbon 

-Foregone Sequestration 

Years 1-19 Land Use 

Emissions: 

-Soil Carbon 

-Foregone Sequestration 

Years 20-79 Land Use 

Emissions: 

-Foregone Sequestration 

202220302040 2050 2060 

In the proposed rule we highlight results for time horizons of 100 years and 30 years, and 

discuss the merits of both approaches. With lifecycle GHG emissions projected to occur many 

years into the future, the choice of whether and by how much to discount future emissions is also 

important. 

In our highlighted results, we used a 2% discount rate when analyzing GHG emissions 

over a 100-year time horizon (See Figure 2.1-2), and we apply a 0% discount rate to estimate the 

GHG emissions reductions associated with biofuel production over a 30-year time horizon (See 

Figure 2.1-3).LLLLLLL The choice of discount rate is discussed in detail in the preamble to the 

proposed rule. 

While EPA believes the methodology presented here represents a robust and 

scientifically credible approach, we recognize that some calculations of GHG emissions are 

relatively straight-forward, while others are not. The direct, domestic emissions from biofuel 

production are relatively well known. The indirect, international emissions are the component of 

our analysis with the highest level of uncertainty. Despite uncertainties associated with 

international land use change, we would expect at least some international land use response as 

demand for crop land increases as a result of this rule. Although there are uncertainties 

associated with these estimates, it would be far less scientifically credible to ignore the effects of 

land use changes altogether than it is to use the best approach available to assess these known 

emissions sources. 

Since lifecycle analysis is a new part of the RFS program, in addition to the formal 

comment period on the proposed rule, EPA is making multiple efforts to solicit public and expert 

feedback on our proposed approach. We are organizing a public workshop focused specifically 

on lifecycle analysis, and we plan to conduct formal external peer-reviews of key components of 

LLLLLLL Note that with a 0% discount rate over 30 years, emissions after year 30 are effectively discounted 100%. 

286 
 

 

our analysis, such as the international land use change assessment. Even after the final rule is 

issued, we recognize that the status of the science and availability of data will continue to evolve. 

Therefore, we plan to establish formal update procedures that include further peer review of the 

life cycle analysis framework and methodology. 

2.1.4 Overall Climate Benefits, Temperature and Sea-Level Impacts 

Our analysis of the overall GHG emission impacts of this proposed rulemaking was 

performed in parallel with the lifecycle analysis performed to develop the individual fuel 

thresholds described in previous sections. Consistent with the fuel volume feasibility analysis 

and criteria pollutant emissions evaluation, our analysis of the GHG impacts of this proposed 

rulemaking was conducted by comparing the difference between a 2022 reference case and a 

2022 control case with volumes of renewable fuels meeting the RFS2 mandate. Based on the 

volume scenarios considered, with 36 billion gallons of biofuel in 2022, the one-time land use 

change impact results in 448 million metric tons of CO2-eq. emissions. For this analysis we 

convert the NPV results for the 100 year 2% discount rate into an annualized stream such that the 

NPV of the annualized emissions will equal the NPV of the emission stream over 100 years with 

a 2% discount rate. This results in an annualized emission reduction of 160 million metric tons 

of CO2-eq. emissions. Using a 30 year time horizon and 0% discount rate the annualized 

emission reduction is 150 million metric tons CO2-eq emissions. EPA also estimated the 

temperature and sea-level impacts of RFS2, which are explained below in Section 2.10. We also 

calculated the monetized GHG benefits of the RFS2 program, which are explained in DRIA 

Chapter 5. 

2.1.5 Chapter Overview 

What follows in this Chapter is a detailed discussion of each component of EPA’s 

lifecycle analysis. Section 2.2 provides background about lifecycle analysis in general, and 

EPA’s current approach. Section 2.3 lays out the goals and scope of our analysis. Section 2.4 

explains EPA’s estimate of petroleum baseline lifecycle GHG emissions which renewable fuels 

are compared with. Section 2.5 discusses potential indirect impacts in the energy sector that may 

be caused by biofuel production. Section 2.6 provides a detailed explanation of EPA’s estimates 

of direct and indirect agricultural sector impacts. Starting at Section 2.6.5, details are provided 

about EPA’s estimate of emissions from land use change. Emissions produced during the 

conversion of renewable biomass to transportation fuel are discussed in Section 2.6.7. Section 

2.7 explains our estimates of tailpipe emissions. Fuel-specific lifecycle GHG results are 

presented in Section 2.8, including a range of selective sensitivity analyses. Section 2.9 includes 

estimates of the overall climate benefits from EISA’s revisions of the RFS program. Finally, 

Section 2.10 translates GHG emissions mitigation from the revised RFS program into global 

temperature and sea-level change projections. 

2.2 Background for Estimating Fuel Lifecycle Greenhouse Gas Emissions 

2.2.1 Lifecycle Analysis for the Original RFS Program 

287 
 

 

 

Lifecycle modeling, often referred to as fuel cycle or well-to-wheel analysis, assesses the 

net impacts of a fuel throughout each stage of its production and use including production / 

extraction of the feedstock, feedstock transportation, fuel production, fuel transportation and 

distribution, and tailpipe emissions. Use of a lifecycle approach to analyze different 

transportation fuels requires modeling and evaluation of many different input factors. The 

starting point for EPA’s lifecycle work was the analysis conducted as part of the Renewable Fuel 

Standard rulemaking in response to the Energy Policy Act of 2005 (RFS1). For the RFS1 rule, 

we estimated GHG benefits based on lifecycle GHG modeling of the different renewable fuels 

mandated as part of the rule. EPA’s approach for the RFS1 was to rely heavily on the 

“Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation” (GREET) model, 

developed by the Department of Energy’s Argonne National Laboratory (ANL). 

However, it has become increasingly apparent that this type of first order lifecycle 

modeling has notable shortcomings, especially when evaluating the implications of biofuel 

policies.MMMMMMM Recently, lifecycle assessments have been divided into two major 

methodological categories: attributional and consequential.504 

Attributional lifecycle assessment focuses on describing the environmentally relevant 

physical flows to and from a lifecycle and its subsystems.505 Attributional analyses are based on 

the direct suppliers of the necessary inputs to production, and co-products are handled by 

allocation. This means that the environmental impacts from biofuels production are simply split 

between the fuel and its co-products, using average data to determine the allocation shares.506 

Therefore, an attributional lifecycle analysis of corn ethanol would account for the direct impacts 

of increased corn production, such as fertilizer and pesticide use, but it would ignore the 

indirect/marginal impacts of shifting crop patterns, such as decreased soybean production, that 

would also result. Attributional analysis also requires a choice about the basis for allocation 

among co-products (e.g., mass, energy content, market value, displacement), which can lead to 

significantly different results. 

Consequential lifecycle assessment captures indirect/marginal impacts that are not 

explicitly included in attributional analyses. Consequential analyses account for activities within 

and outside the lifecycle that are affected by an incremental change within the lifecycle of the 

product under investigation. In other words, consequential lifecycle analyses study the 

consequences of changes in production or consumption from a market-based perspective, 

utilizing economic modeling to identify the ultimate impacts of a decision, such as a policy or a 

single project.507 This often implies the use of marginal data, and co-product allocation is 

typically avoided through system expansion. In other words, consequential analyses include 

alternative uses of constrained production factors, and marginal supply and demand on affected 

markets.508 Some researchers have concluded that the consequential approach provides more 

complete and accurate, but less precise results, while the attributional approach provides more 

precise results but with inherent blind spots that lead to less accurate results.509 

MMMMMMMSee also, Conceptual and Methodological Issues in Lifecycle Analysis of Transportation Fuels, Mark A. 

Delucchi, Institute of Transportation Studies, University of California, Davis, 2004, UCD-ITS-RR-04-45 for a 

description of issues with traditional lifecycle analysis used to model GHG impacts of biofuels and biofuel policies. 

288 
 

In fact, the main criticism EPA received in reaction to our previous RFS1 lifecycle 

analysis, which resembled a traditional attributional lifecycle analysis, was that we did not 

include important secondary, indirect, or consequential impacts of biofuel use, specifically: 

−	 Biomass production focused on the feedstock used (e.g., corn) and did not capture 

other secondary market driven agricultural sector impacts, such as changes in 

other crop patterns and livestock production as a response to changing prices in 

biofuel feedstocks. 

−	 Production of co-products from ethanol production required some type of 

allocation, either splitting emissions of fuel production between fuel and coproducts or examining the use of co-products in other markets. For example in 

the case of corn ethanol, the co-product of ethanol production is a feed product 

that is assumed to replace the use of corn and soybean meal. Therefore, the 

emissions of producing an equivalent amount of these products are subtracted 

from the lifecycle assessment. This required modeling of the co-product 

economic market that is typically done outside of the lifecycle modeling. 

−	 To the extent that they are included, land use impacts are typically confined to 

direct impacts, e.g., land converted to produce corn directly used for ethanol 

production. This does not capture effects of land use converted to produce crops 

that are indirectly impacted by increased biofuel production. One specific 

example of this is increased corn ethanol production in the U.S. could lead to 

decreased crop exports resulting in increased crop production and land use 

impacts internationally. Another example is corn acre increase resulting in less 

rice production acres and lower CH4 emissions. 

−	 The attributional modeling approach is not necessarily linked to a specific policy 

case, but is rather a general representation of biofuel production. Consideration of 

specific policies and interaction between different fuel volumes could have very 

distinct impacts especially in the agricultural sector. 

−	 The replacement of petroleum fuel was represented by an average gallon of fuel. 

However, we recognize that an additional gallon of renewable fuel replaces the 

marginal gallon of petroleum fuel. To the extent that the marginal gallon of 

renewable fuel is from feedstocks grown on highly productive land and displaces 

petroleum fuel derived from oil sands or other types of crude oil that are 

associated with higher than average GHG emissions, replacing these fuels could 

have a larger GHG benefit. Conversely to the extent the marginal gallon of 

renewable fuel is from feedstocks grown on marginal land and displaces imported 

gasoline produced from light crude, replacing these fuels would have a smaller 

GHG benefit. 

−	 The attributional modeling approach assumes that one Btu of renewable energy 

produced displaces one Btu of petroleum energy. In reality, the production of 

renewable fuels is expected to lower world energy prices (as discussed in Chapter 

289 
 

5.2), which in turn could lead to a marginal increase in world energy consumption 

and less than a one-for-one Btu replacement. 

A key aspect of the issues described above is that the attributional lifecycle approach 

typically does not include economic modeling and the significant indirect impacts from price 

changes in the analysis. Therefore, to address some of these issues, we have updated our 

lifecycle methodology to include the use of economic models to perform a consequential type of 

lifecycle analysis. 

The consequential approach of incorporating economic models into a lifecycle 

assessment is not a new concept. Most notably the Economic Input-Output Lifecycle 

Assessment (EIO-LCA) method has been employed in the past. The EIO-LCA method estimates 

the materials and energy resources required for, and the environmental emissions resulting from, 

activities in the overall economy. The EIO-LCA method was theorized and developed by 

economist Wassily Leontief in the 1970s based on his earlier input-output work from the 1930s 

for which he received the Nobel Prize in Economics. Researchers at the Green Design Institute 

of Carnegie Mellon University operationalized this method in the mid-1990s, once sufficient 

computing power was widely available to perform the large-scale matrix manipulations required 

in real-time. This work relies on static input-output tables of the U.S. economy to determine the 

full economy wide impacts of producing a product or service. 

Mark Delucchi at the Institute of Transportation Studies of the University of California 

Davis has developed the Lifecycle Emissions Model (LEM) that looks at transportation fuels. 

He has also highlighted the need to look at market impacts when considering biofuel production 

and specifically to consider land use changes.510 There have also been several studies examining 

the consequential or economic based life cycle assessment including several focusing on the 

agricultural sector. 

Several studies and analyses conducted since the completion of the RFS1 rulemaking 

have also contributed to our understanding of the lifecycle environmental impacts of biofuel 

production. These studies, and others, have highlighted the potential impacts of biofuel 

production on the agricultural sector and specifically identified land use change impacts as an 

important consideration when determining GHG impacts of biofuels.511,512 In the meantime, the 

dramatic increase in U.S. production of biofuels has heightened the concern about the impacts 

biofuels might have on land use and has increased the importance of considering these and other 

indirect impacts in lifecycle analysis. 

In order to improve our lifecycle modeling for this proposed rulemaking, EPA held a 

series of discussions with interested stakeholders during July and early August 2007 and again in 

early 2008. Stakeholder outreach included discussions with academics and other researchers, the 

California Air Resources Board (CARB), the U.S. Departments of Agriculture and Energy, and 

the following stakeholders who provided comments on RFS lifecycle analysis: 

− American Petroleum Institute 

− National Petroleum Refiners Association 

− Renewable Fuels Association 

290 
− National Biodiesel Board 

− DuPont 

− Union of Concerned Scientists 

− Natural Resources Defense Council 

− Environmental Defense 

Through dozens of meetings with this wide range of experts and stakeholders, EPA has 

shared and sought input on this methodology. We also have relied on the expertise of the U.S. 

Department of Agriculture (USDA) and the Department of Energy (DOE) to help inform many 

of the key assumptions and modeling inputs for this analysis and have gained their support for 

their use. Dialogue with the State of California and the European Union on their parallel, ongoing efforts in GHG lifecycle analysis has also helped inform EPA’s methodology. While there 

is no consensus, the input we received through these interactions is reflected in the approach 

described here. 

2.2.2 Updates for this Proposed Rulemaking 

Based on discussions with these numerous stakeholders and review of literature, we have 

developed an approach for this proposed rulemaking that enhances the RFS1 modeling by 

including additional information and models to address concerns with our existing work by 

significantly strengthening and expanding our coverage of agricultural sector impacts. 

Currently, no single model can capture all of the complex interactions associated with 

estimating lifecycle GHG emissions for biofuels, taking into account the "significant indirect 

emissions such as significant emissions from land use change" required by EISA. For example, 

some lifecycle analysis tools typically used in the past focus on process modeling—the energy 

and resultant emissions associated with the direct production of a fuel at a petroleum refinery or 

biofuel production facility. But this is only one component in the production of the fuel. Clearly 

in the case of biofuels, impacts from and on the agricultural sector are important, because this 

sector produces feedstock for biofuel production. Commercial agricultural operations make 

many of their decisions based on an economic assessment of profit maximization. Assessment 

of the interactions throughout the agricultural sector requires an analysis of the commodity 

markets using economic models. However, existing economy wide general equilibrium 

economic models are not detailed enough, on their own, to capture the specific agricultural sector 

interactions critical to our analysis (e.g., changes in acres by crop type) and would not provide 

the types of outputs needed for a thorough GHG analysis. As a result, EPA has used a set of 

tools that are best suited for each specific component of the analysis to create a more 

comprehensive estimate of GHG emissions. Where no direct links between the different models 

exist, specific components and outputs of each are used and combined to provide an analytical 

framework and the composite lifecycle assessment results. 

To quantify the emissions factors associated with different steps of the production and 

use of various fuels (e.g., extraction of petroleum products, transport of feedstocks), we used the 

spreadsheet analysis tool developed by Argonne National Laboratories, the Greenhouse gases, 

Regulated Emissions, and Energy use in Transportation (GREET) model. This analysis tool 

includes the GHG emissions associated with the production and combustion of fossil fuels 

291 
(diesel fuel, gasoline, natural gas, coal, etc.). These fossil fuels are used both in the production 

of biofuels, (e.g., diesel fuel used in farm tractors and natural gas used at ethanol plants) and 

could also be displaced by renewable fuel use in the transportation sector. GREET also 

estimates the GHG emissions associated with electricity production required for biofuel and 

petroleum fuel production. For the agricultural sector, we also relied upon GREET to provide 

GHG emissions associated with the production and transport of agricultural inputs such as 

fertilizer, herbicides, pesticides, etc. While GREET provides direct GHG emissions estimates 

associated with the extraction-through-combustion phases of fuel use, it does not capture some of 

the secondary impacts associated with the fuel, such as changes in the composition of feed used 

for animal production which would be expected due to changes in cost. EPA addresses these 

secondary impacts through other models described later in this section. GREET has been under 

development for several years and has undergone extensive peer review through multiple 

updates. Of the available sources of information on lifecycle GHG emissions of fossil energy 

consumed, we believe that GREET offers the most comprehensive treatment of emissions from 

the covered sources. 

For some steps in the production of biofuels, we use more detailed models to capture 

some of the dynamic market interactions that result from various policies. Here, we briefly 

describe the different models incorporated into our analysis to provide specific details for various 

lifecycle components. 

To estimate the changes in the domestic agricultural sector (e.g., changes in crop acres 

resulting from increased demand for biofuel feedstock or changes in the number of livestock due 

to higher corn prices) and their associated emissions, we used the Forestry and Agricultural 

Sector Optimization Model (FASOM), developed by Texas A&M University and others. 

FASOM is a partial equilibrium economic model of the U.S. forest and agricultural sectors. EPA 

selected the FASOM model for this analysis for several reasons. FASOM is a comprehensive 

forestry and agricultural sector model that tracks over 2,000 production possibilities for field 

crops, livestock, and biofuels for private lands in the contiguous United States. It accounts for 

changes in CO2, methane, and N2O from most agricultural activities and tracks carbon 

sequestration and carbon losses over time. Another advantage of FASOM is that it captures the 

impacts of all crop production, not just biofuel feedstock. Thus, as compared to some earlier 

assessments of lifecycle emission, using FASOM allows us to determine secondary agricultural 

sector impacts, such as crop shifting and reduced demand due to higher prices. It also captures 

changes in the livestock market (e.g., smaller herd sizes that result from higher feed costs) and 

U.S. export changes. FASOM also has been used by EPA to consider U.S. forest and 

agricultural sector GHG mitigation options.513 

To estimate the impacts of biofuels feedstock production on international agricultural and 

livestock production, we used the integrated Food and Agricultural Policy and Research Institute 

(FAPRI) international models, developed by Iowa State University and the University of 

Missouri. These models capture the biological, technical, and economic relationships among key 

variables within a particular commodity and across commodities. FAPRI is a worldwide 

agricultural sector economic model that was run by the Center for Agricultural and Rural 

Development (CARD) at Iowa State University on behalf of EPA. The FAPRI models have 

been previously employed to examine the impacts of World Trade Organization proposals, 

changes in the European Union’s Common Agricultural Policy, analyze farm bill proposals since 

292 
1984, and evaluate the impact of biofuel development in the United States. In addition, the 

FAPRI models have been used by the USDA Office of Chief Economist, Congress, and the 

World Bank to examine agricultural impacts from government policy changes, market 

developments, and land use shifts. 

Although FASOM predicts land use and export changes in the U.S. due to greater 

demand for domestic biofuel feedstock, it does not assess how international agricultural 

production might respond to these changes in commodity prices and U.S. exports. The FAPRI 

model does predict how much crop land will change in other countries but does not predict what 

type of land such as forest or pasture will be affected. We used data analyses provided by 

Winrock International to estimate what land types will be converted into crop land in each 

country and the GHG emissions associated with the land conversions. Winrock has used 2001­

2004 satellite data to analyze recent land use changes around the world that have resulted from 

the social, economic, and political forces that drive land use. Winrock has then combined the 

recent land use change patterns with various estimates of carbon stocks associated with different 

types of land at the state level. This international land use assessment is an important 

consideration in our lifecycle GHG assessment and is explained in more detail later in this 

chapter. 

To test the robustness of the FASOM, FAPRI and Winrock results, we are also evaluating 

the Global Trade Analysis Project (GTAP) model, a multi-region, multi-sector, computable 

general equilibrium model that estimates changes in world agricultural production. Maintained 

through Purdue University, GTAP projects international land use change based on the economics 

of land conversion, rather than using the historical data approach applied by FAPRI/Winrock. 

GTAP is designed to project changes in international land use as a result of the change in U.S. 

biofuel policies, based on the relative land use values of cropland, forest, and pastureland. The 

GTAP design has the advantage of explicitly modeling the competition between different land 

types due to a change in policy. As further discussed in Section 2.6.5.3.3, GTAP has several 

disadvantages, some of which prevented its use for the proposal. We hope to correct several of 

these shortcomings between the proposed and final rule; therefore we continue to evaluate the 

use of the GTAP model as part of the final rule. 

The assessments provided in this proposal use the values provided by the 

Intergovernmental Panel on Climate Change (IPCC) to estimate the impacts of N2O emissions 

from fertilizer application. However, due to concern that this may underestimate N2O emissions 

from fertilizer application514, we are working with the CENTURY and DAYCENT models, 

developed by Colorado State University to update our assessments. The DAYCENT model 

simulates plant-soil systems and is capable of simulating detailed daily soil water and 

temperature dynamics and trace gas fluxes (CH4, N2O, NOx and N2). The CENTURY model is a 

generalized plant-soil ecosystem model that simulates plant production, soil carbon dynamics, 

soil nutrient dynamics, and soil water and temperature. We anticipate the results of this new 

modeling work will be reflected in our assessments for the final rule. More description of this 

ongoing work is included in the Section 2.6.2.2. 

To estimate the GHG emissions associated with renewable fuel production, we used 

detailed ASPEN-based process models developed by USDA and DOE’s National Renewable 

293 
Energy Laboratory (NREL). While GREET contains estimates for renewable fuel production, 

these estimates are based on existing technology. We expect biofuel production technology to 

improve over time, and we projected improvements in process technology over time based on 

available information. These projections are discussed in DRIA Chapter 4. We then utilized the 

ASPEN-based process models to assess the impacts of these improvements. We also crosschecked the ASPEN-based process model predictions by comparing them to a number of 

industry sources and other modeling efforts that estimate potential improvements in ethanol 

production over time, including the Biofuel Energy Systems Simulator (BESS) model. BESS is 

a software tool developed by the University of Nebraska that calculates the energy efficiency, 

greenhouse gas (GHG) emissions, and natural resource requirements of corn–to-ethanol biofuel 

production systems. We used the GREET model to estimate the GHG emissions associated with 

current technology as used by petroleum refineries, because we do not expect significant changes 

in petroleum refinery technology. 

We used the EPA-developed Motor Vehicle Emission Simulator (MOVES) to estimate 

vehicle tailpipe GHG emissions. The MOVES modeling system estimates emissions for on-road 

and nonroad sources, covers a broad range of pollutants, and allows multiple scale analysis, from 

fine-scale analysis to national inventory estimation. 

Finally, for the FRM we intend to use the Energy Information Administration's National 

Energy Modeling System (NEMS) to estimate the secondary impacts on the energy market 

associated with increased renewable fuel production. NEMS is a modeling system that simulates 

the behavior of energy markets and their interactions with the U.S. economy by explicitly 

representing the economic decision-making involved in the production, conversion, and 

consumption of energy products. NEMS should model the secondary impacts that greater 

renewable fuel use may have on the prices and quantities of other sources of energy, and the 

greenhouse gas emissions associated with these changes in the energy sector. It was not possible 

to complete this analysis in time for the NPRM. 

While EPA is using the most state-of-the-art tools available today for each of the 

lifecycle components considered, we understand the concern that using multiple models 

necessitates integrating these models and, where possible, applying a common set of 

assumptions. As discussed later in this chapter, this is particularly important for the two 

agricultural sector models, FASOM and FAPRI, which are being used in combination to describe 

the agricultural sector impacts domestically and internationally. As described in more detail in 

the DRIA Chapter 5, we have worked with the FAPRI and FASOM models to align several key 

assumptions. As a result, the projected agricultural impacts described in Section 2.6 are 

relatively consistent across both models. One outstanding issue is the differences between the 

modeling results associated with increased soybean based biodiesel production. We intend to 

further refine the soybean biodiesel scenarios for the final rule. 

Figure 2.2-1 graphically shows the different models used and what parts of the lifecycle 

they are used to represent. 

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Figure 2.2-1. System Boundaries and Models Used 

2.3 Goal and Scope of This Analysis 

Lifecycle analysis is used in several ways for this proposed rulemaking. Fuel-specific 

GHG reductions are used to develop threshold determinations for specific fuels. Lifecycle 

analysis is also used to determine the overall impact of the rulemaking on GHG emissions 

worldwide. 

The analysis conducted to assess the fuel-specific GHG performance relative to the 

thresholds in the standards is described in Sections 2.3 through 2.8. The analysis conducted to 

determine the overall GHG emission impact of the rulemaking is provided in Section 2.9. 

2.3.1 Goal 

The proposed rulemaking involves determining lifecycle GHG impacts of specific fuels 

and fuel pathways for comparison with thresholds as defined in the legislation. Obligated parties 

will be required to use mandated quantities of renewable fuels, but only fuels that meet the GHG 

thresholds can qualify under the program. The lifecycle GHG reductions represent the GHG 

differences between renewable fuels relative to the petroleum-based gasoline and diesel that they 

displace. The lifecycle methodology described here is used to determine the GHG displacement 

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values for different renewable fuels to be compared to the thresholds. Therefore this analysis 

will provide: 

− Amount of GHG emissions (in grams, lb., tons, etc.) per amount of fuel produced (per 

btu) for both conventional petroleum based fuels and renewable fuels. 

− Results are combined to quantify the emission change per btu of renewable fuel 

compared to that for the conventional fuel replaced. 

2.3.2 Scope 

2.3.2.1 Scenario Analysis 

To quantify the lifecycle GHG emissions associated with the increase in renewable fuel 

mandated by EISA, we needed to compare the impacts of renewable fuels with EISA to a 

reference case without EISA. Since it is not practical or workable to conduct such an analysis 

and come up with factors for every year, to carry out this analysis we chose to look at the final 

year of the RFS2 standards when they are fully phased in. For our reference case we assumed a 

“business as usual” volume of a particular renewable fuel based on what would likely be in the 

fuel pool in 2022 without EISA as predicted by the Energy Information Agency’s Annual Energy 

Outlook (AEO) for 2007 (which took into account the economic and policy factors in existence 

in 2007 before EISA). For our control case we assumed the higher volumes of renewable fuels 

as mandated by EISA for 2022. For each individual biofuel, we analyzed the incremental impact 

of increasing the volume of that fuel to the total mix of biofuels needed to meet the EISA 

requirements while holding volumes of other fuels constant. Any changes between now and 

2022 in factors such as crop yields, energy costs, or production plant efficiencies, both 

domestically and internationally, are reflected in both scenarios. Rather than focus on the 

impacts associated with a specific gallon of fuel and tracking inputs and outputs across different 

lifecycle stages, we determined the overall aggregate impacts across sections of the economy in 

response to a given volume change in the amount of biofuel produced. We then normalize those 

impacts to a gallon of fuel by dividing total impacts over the given volume change. In the case 

of overall rule impacts, we analyze the change in reference vs. control case volumes for all fuels 

together and take the absolute GHG results (e.g., do not normalize the overall rule impacts). 

We did not calculate the emission impacts for each gallon of fuel based upon its unique 

production characteristics which could vary widely across the nation (e.g., a gallon of ethanol 

produced using corn grown in Iowa may have different direct lifecycle emissions impacts than a 

gallon of ethanol produced at an identical facility in Nebraska using corn grown in Nebraska due 

to regional differences in agricultural practices. However, on a lifecycle basis, considering the 

indirect impacts in the context of the entire corn market they are not different). Rather, we 

determined the overall aggregate impacts across sections of the economy in response to a given 

volume change in the amount of biofuel produced. In the case of agricultural impacts, we 

assessed the impact on the entire U.S. agricultural system that would result from expanded 

demand for biofuel feedstock. We then normalized those impacts to a gallon of fuel by dividing 

total impacts over the renewable fuel volume change between our business as usual case and the 

EISA volumes. Similarly, we estimated the typical emissions impact of a type of biofuel 

production facility (e.g., a plant that uses the dry mill process to turn corn starch into ethanol). 

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The emissions assessment from a typical facility was then ascribed to all biofuel produced across 

facilities using that same basic technology. 

There are several important implications associated with this methodology. First, this 

analysis focuses on the average impact of an increase in fuel produced using a technology 

pathway and does not distinguish the emission performance between biofuel production plants 

using the same basic production technology and type of feedstock. Thus it does not account for 

relatively small differences in facility design or operation which may affect the lifecycle GHG 

performance at that facility. 

Second, the results presented here are based on the GHG impacts of the volumes 

analyzed. For corn ethanol the impact represents the change in GHG emissions when national 

corn ethanol production increases from 12.4 to 15 Bgal which are the estimated volumes in corn 

ethanol production that would occur in 2022 without and then with EISA mandates in place. The 

GHG impact is then normalized to a per gallon or Btu basis in relation to gasoline. These values 

are used to represent every gallon of corn ethanol produced throughout the program. The per 

gallon impact based on different volume changes could be different than the incremental impact 

studied. For example, modeling a change from 0 to 15 Bgal would allow an assessment of the 

average GHG impact for all 15 Bgal of corn ethanol. As discussed in Section 2.8, we examine 

this issue through a sensitivity analysis where we consider a change in corn ethanol volumes 

from 8.7 to 12.4 Bgal and plan to provide a broader set of assessments for the final rule. We 

described corn ethanol here, but the other renewable fuels were assessed in the same manner. 

Third, by focusing on 2022, this analysis does not track how biofuel GHG emission 

performance may change over time between now and 2022. While our estimates are based on 

the GHG emissions for each biofuel for a specific volume change in 2022, we recognize that an 

alternative approach would be to create incremental GHG emission curves for different volumes 

and different years. Section 2.8 provides a sensitivity analysis of the year of analysis, which 

includes corn ethanol lifecycle GHG results for 2012 and 2017. As discussed above, we believe 

modeling the results in 2022 provides a representative assessment of the GHG impact of the 

additional biofuel mandated by EISA. 

Finally, several of the lifecycle emission impacts for one fuel are interrelated with those 

of another fuel, in particular the land-use changes. For our analysis of the overall GHG impacts 

of the program (discussed in section 2.9), we modeled all of the fuel changes simultaneously to 

determine the land-use impact. However, from that analysis it is not possible to differentiate the 

contribution of the land-use change to one fuel vs. another. As a result, for this analysis we had 

to model the impacts of just one fuel change at a time. In doing this we have held the other fuel 

volumes constant at their mandated levels in order to best approximate the impacts a single fuel 

change would have in the context of the full RFS2 standard volumes. 

We used the same approach to determine the lifecycle GHG emissions for corn ethanol, 

cellulosic ethanol, biodiesel produced from soybean (and other vegetable) oils, and biodiesel 

produced using waste oils as feedstock. For waste oils, we note that no land use changes are 

included in the FASOM assessment, because any land use impacts are attributed to the original 

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purpose of the feedstock (e.g.., the use of the vegetable oil for cooking or the production of 

animals for their meat), rather than the biofuel produced from the recovered waste material. 

FASOM does not model feedstocks for fuels produced outside the U.S. We addressed 

imported ethanol by analyzing the difference in total GHG emissions based on two 2022 

scenarios using only the results from FAPRI modeling runs: (1) the business as usual reference 

case volume of 0.6 Bgal and (2) an RFS2 projected volume of 3.1 Bgal of imported sugarcane 

ethanol. 

Current models present some challenges in estimating GHG lifecycle emissions for 

cellulosic biofuels. The version of FASOM we used for this proposal did not include the forestry 

module, and therefore, we did not model forest products or forest waste as a renewable fuel 

feedstock. FASOM does have a module for the forest sector that EPA used in the past to assess 

forest impacts of changes in U.S. policies. The forestry module works much like the agricultural 

sector module in assessing likely outcomes; however, the data populating the forestry module is 

currently being updated to reflect the most recent information, and was not available in time to 

use in analyses for this proposal. EPA anticipates that the FASOM forestry module will be 

available for the final rule and intends to use it in the final rule assessments. We also note that 

inclusion of the forestry module will potentially allow the FASOM model to use some currently 

forested lands for crop production or pasture. To the extent this occurs, our assessment of the 

lifecycle impacts of farm crop changes may also be impacted. In addition, FAPRI does not 

include switchgrass or similar energy crops, and can only use corn stover or other food crop 

residues as feedstock in predicting cellulosic biofuel impacts. To overcome this limitation, we 

assumed that increased domestic switchgrass production would result in a decrease in U.S. crop 

exports, because switchgrass competes with other crops for acreage. We allowed the FAPRI 

model to draw on additional CRP acres to represent increased demand for acreage for energy 

crops. 

For biofuels made from wastes and byproducts (e.g., MSW, rendered fats and waste oils 

and corn stover feedstock), we assumed no land use changes, because these biofuel feedstocks do 

not compete for domestic crop acreage. For corn stover, we analyzed only the change in 

domestic GHG emission resulting from an increase in fertilizer replacement application rates to 

compensate for the removal of stover from the land. 

Table 2.3-1 shows the different fuel scenarios considered under the different models 

used. 

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Table 2.3-1. Fuel Volume Scenarios Considered in This Analysis 

Fuel Model Volume (Billions of Gallons) 

Low Volume High Volume Net Change 

Corn Ethanol FASOM & FAPRI 

12.4 15 2.6 

8.7 12.4 3.7 

Switchgrass Ethanol 

FASOM 1.1 5.7 4.6 

FAPRI 0 3.2 3.2 

Biodiesel FASOM & FAPRI 0.4 0.7 0.3 

Corn Stover Ethanol FASOM 0 7.6 7.6 

Sugarcane Ethanne Ethanol FAPRI 0.6 3.1 2.5 

2.3.2.2 System Boundaries 

It is important to establish clear system boundaries in this analysis. By determining a 

common set of system boundaries, different fuel types can then be validly compared. As 

described in the previous section, we have assessed the direct and indirect GHG impacts in each 

stage of the full fuel lifecycle for biofuels and petroleum fuels. Figure 2.3-1 provides a 

simplified diagram describing the system studied. 

Figure 2.3-1. Simplified Lifecycle System Diagram 

International 

Agricultural 

Sector 

Domestic 

Agricultural 

Sector 

Conventional 

Petroleum Fuel 

Production 

Food / Feed Uses Transportation Sector 

Fuel Demand 

Biofuel 

Production 

The different fuel use volume scenarios will be compared on delivering the same 

functions, in this case providing for both the agricultural sector market and transportation fuels 

market. Within the overall system shown in Figure 2.3-1, the unit process listed in Table 2.3-2 

will be considered. 

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Table 2.3-2. Unit Processes Considered 

Biofuel Petroleum-Based Fuel 

Feedstock Agriculture Crude Oil Extraction 

Feedstock Transport Crude Oil Transport 

Feedstock Processing & 

Biofuel Production 

Refining 

Biofuel Transport and 

Distribution 

Fuel Transport and 

Distribution 

Biofuel Tailpipe Emissions Fuel Tailpipe Emissions 

In setting system boundaries for this analysis, we use a consistent approach across all 

fuels to determine what is included in the system boundaries considered. In this way renewable, 

alternative and petroleum based fuels are all compared based on the same system boundaries. In 

general this type of analysis could be expanded to cover many different sectors of the economy, 

with diminishing impact on the overall results. Therefore, we rely on internationally accepted 

lifecycle assessment standards, developed by the International Organization for Standardization 

(ISO), when setting the system boundaries of this analysis. Based on the ISO standards we 

consider environmental significance as a cut off criteria for what to include in our system 

boundaries. 

Included in each unit process shown in Table 2.3-2 are the emissions and energy use 

associated with that operation as well as upstream components that feed into it. For example, the 

feedstock agriculture stage includes emissions from fuel used in tractors as well as from 

producing and transporting the fertilizer used in the field. Electricity production emissions are 

included in almost all of the stages shown. For direct impacts, this results in system boundaries 

that include operation-related activities, but not infrastructure-related activities. As such, while 

we do include the emissions associated with the operation of farm equipment and trucks used for 

feedstock / fuel transportation we do not include the emissions associated with the production of 

the equipment or vehicles. Furthermore, we include the emissions from the operations of biofuel 

production plants and petroleum refineries but we do not include emissions from producing the 

material used to construct the facilities. 

This decision was based on analysis done for the RFS1 rulemaking which found that 

including farm equipment production energy use and emissions increases ethanol lifecycle 

energy use and GHG emissions and decreases the percent reduction in GHG emissions from corn 

ethanol in comparison to gasoline by approximately 1 percent. Furthermore, to be consistent in 

the modeling, if system boundaries are expanded to include production of farming equipment 

they should also be expanded to include producing other material inputs to both the ethanol and 

petroleum lifecycles. For example, this expansion of system boundaries would include the 

energy use and emissions associated with producing concrete and steel used in the petroleum 

refinery. The net effect of this would be a slight increase in both the ethanol and petroleum fuel 

lifecycle results and a smaller or negligible effect on the comparison of the two. 

In determining what indirect impacts to include in the system boundaries of this analysis 

we again focus on those sources that will have the biggest effect on overall results. Therefore, 

for the analysis used in this proposed rulemaking we have included significant direct and indirect 

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domestic and international agricultural sector impacts. We also plan to consider indirect effects 

in energy markets due to increased use of biofuels in the transportation sector, and changes in 

fossil fuel markets due to increased fuel (primarily natural gas) used in the ethanol production 

sector. EPA is still developing the modeling approach to capture these energy sector indirect 

effects and some preliminary analysis is presented in Section 2.5. 

In comparing renewable and alternative fuels to the petroleum fuel that they replace we 

have made the assumption that the amount of conventional fuel no longer consumed – that is, 

displaced – as a result of the use of the replacement renewable or alternative fuel is equal on an 

energy basis. This assumes 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). Therefore, for every Btu of ethanol produced there is a 

corresponding decrease of a Btu of gasoline use, and associated quantity of crude oil is not 

extracted or processed to make this gasoline. Some studies have shown that because of the 

increased octane content of ethanol (and specifically E85) vehicle efficiency may actually be 

slightly improved with use of E85 vs. gasoline. This would imply that a Btu of ethanol would 

actually displace slightly more that a Btu of gasoline because of improved engine efficiency. 

However, these studies are not conclusive enough for us to include in our analysis at this point. 

This is something we will be considering for the final rule and may add as a sensitivity case. 

This type of modeling also does not allow for behavioral changes that could occur, what 

we call the “secondary oil market” impacts. For example, a worldwide reduction in oil prices 

could result from the increased use of renewable fuels (as discussed in Chapter 5.2). To the 

extent world fuel prices are decreased, demand and consumption would tend to increase; this 

impact is labeled the “international oil takeback effect.” The result could be less than a Btu of 

gasoline displaced for each gallon of ethanol produced. We have not yet conducted the modeling 

to quantify the magnitude of this effect or factored it into our lifecycle analysis. However, we 

are looking at options to consider this impact in the final rule analysis, as discussed in Section 

2.5. 

2.3.2.3 Environmental Flows Considered 

The lifecycle analysis discussed here evaluates the impacts of increased renewable fuel 

use on greenhouse gas emissions. EISA specifies a definition of greenhouse gases to include in 

the analysis: 

The term ‘greenhouse gas’ means carbon dioxide, hydrofluorocarbons, methane, 

nitrous oxide, perfluorocarbons, sulfur hexafluoride. The Administrator may 

include any other anthropogenically emitted gas that is determined by the 

Administrator, after notice and comment, to contribute to global warming. 

EISA also specifies that the mass values for all greenhouse gases are adjusted to account 

for their relative global warming potential. 

The relative global warming contribution of emissions of various greenhouse gases is 

dependant on their radiative forcing, atmospheric lifetime, and other considerations. For 

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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 in this analysis were developed by the UN Intergovernmental Panel on Climate 

Change (IPCC) as listed in their Second Assessment Report, and are shown in Table 2.3-3. 

Second assessment report values are used to be consistent with current standards for international 

reporting of GHG emissions. 

Table 2.3-3. 

100 Year Global Warming Potentials for Greenhouse Gases 

Greenhouse Gas GWP 

CO2 1 

CH4 21 

N2O 310 

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 

emissions for each pollutant. The sum of impacts for CH4, N2O, and CO2, yields the total 

effective GHG impact. Other GHGs like HFCs, PFCs and SF6 are not released in significant 

amounts over the lifecycle of renewable or petroleum fuels, and are therefore not tracked in this 

analysis. Other non-GHG climate impacts like albedo (light reflectance), land surface 

roughness, hydrologic and energy flux, and loss of forest aerosols, while potentially an important 

aspect of climate impacts associated with land use change, are currently outside the scope of this 

analysis. 

Other environmental flows besides GHG emissions are also considered in our analysis for 

this rulemaking. Criteria and toxic air pollutants are modeled and results are described in 

Chapter 3 of the DRIA. Water use and impacts are also considered and are described in Chapter 

6 of the DRIA. 

2.3.2.4 Data Quality 

Lifecycle analysis is a data intensive process and the results are affected by data quality. 

Data quality may be defined by specific characteristics that describe both quantitative and 

qualitative aspects of data, as well as the methods used to collect and integrate those data into the 

analysis. The quality of data used can be characterized by how well the geographic, technical 

and temporal aspects of the data match the goals and scope of the analysis in question. 

The quality of the data used in this analysis was classified based on its geographic, 

technical and temporal relevance to the goals of the study as follows: 

Geographic coverage – this analysis was conducted without any regard to the 

geographic attributes of where emissions or energy use occurs. The benefits of this 

proposed rule represent global reductions in GHG emissions and energy use, not just 

those occurring in the U.S. For example, the savings associated with reducing overseas 

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crude oil extraction and refining are included here, as are the international emissions 

associated with producing imported ethanol. Data for agricultural sector impacts include 

both U.S. and international defaults. Agricultural commodity production in other 

countries was based on data specific to those areas (e.g., fertilizer production in other 

countries). Land use change was specifically modeled in different countries, impacts of 

land use change were based on factors representing sub-country level land characteristics, 

and for areas where data was not available averages were used. 

Technology coverage – this analysis models industries that do not exist yet – cellulosic 

ethanol and renewable diesel for example. Therefore assumptions based on existing 

information and modeling were made to represent these industries rather than relying on 

existing facility data. Even for industries that currently exist there is expected to be a 

range of technology development over time. For this analysis we have made our best 

projections for what the industry may look like by 2022. There is expected to be 

considerable variation in the technologies used, for example combined heat and power 

and corn oil fractionation in a dry mill ethanol plant. To account for this we have looked 

at different fuel technology pathways as shown in Section 2.6.7. 

Temporal coverage – this analysis considered impacts in 2022. Therefore we modeled 

future data; we projected ethanol production in 2022 based on process models – 

consistent with cost analysis used in this proposed rulemaking. For example, this 

assumed that future plants will be more energy efficient then current plants. Agricultural 

sector models also represented 2022 values including improvements in yields and 

cropping patterns. 

2.3.2.5 Uncertainty Analysis 

While EPA believes the methodology presented here represents a robust and 

scientifically credible approach, we recognize that some calculations of GHG emissions are 

relatively straight-forward, while others are not. The direct, domestic emissions are relatively 

well known. These estimates are based on well-established process models that can relatively 

accurately capture emissions impacts. For example, the energy and GHG emissions used by a 

natural gas-fired ethanol plant to produce one gallon of ethanol can be calculated through direct 

observations, though this will vary somewhat between individual facilities. The indirect 

domestic emissions are also fairly well understood, however these results are sensitive to a 

number of key assumptions (e.g., current and future corn yields, energy prices, etc.). We address 

uncertainty in this area by testing the impact of changing these assumptions on our results. 

Finally, the indirect, international emissions are the component of our analysis with the highest 

level of uncertainty. For example, identifying what type of land is converted internationally and 

the emissions associated with this land conversion are critical issues that have a large impact on 

the GHG emissions estimates. We address this uncertainty by using sensitivity analyses to test 

the robustness of the results based on different assumptions. We also identify areas of additional 

work that will be completed prior to the final rulemaking. For example, while we utilized an 

approach using comprehensive agricultural sector models and recent satellite data to determine 

the GHG emissions resulting from international land use impacts, we are also considering an 

alternative methodology (the analyses using GTAP) that estimates changes in land use based on 

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the relative land use values of cropland, forest, and pastureland. Additionally, we are 

considering country-specific information which may allow us to better predict specific trends in 

land use such as the degree to which marginal or abandoned pasture land will need to be replaced 

if used instead for crop production. 

Despite the uncertainty associated with international land use change, we would expect at 

least some international land use change to occur as demand for crop land increases as a result of 

this rule. Furthermore, the conversion of crop land will lead to GHG emission from land 

conversion that must be accounted for in the calculation of lifecycle GHG emissions. We 

believe that uncertainty in the effects and extent of land use changes is not a reason for not 

accounting for land use change emissions. Although there are uncertainties associated with these 

estimates, it would be far less scientifically credible to ignore the effects if land use change 

altogether than it is to use the best approach available to assess these known emissions. 

There are several ways of specifically dealing with uncertainty in this analysis. One 

approach would be to perform statistical analysis, applying distribution curves to each input and 

running Monte Carlo analysis to determine a range of results. While this may be the most 

intellectually pleasing approach in theory, there are several significant barriers to this approach. 

Most significantly, it is difficult to determine scientifically-defensible probability distribution 

functions for all (or even the most significant) input variables. Applying functions that are not 

well understood may serve to misstate uncertainty. Furthermore, an analysis that treats all 

variables independently would not capture the fact that there are links between inputs with 

potentially conflicting impacts on results (e.g., higher fertilizer use linked to higher crop yields). 

To do this correctly, we need to determine the covariance matrix of all variables, or risk further 

obscuring the degree of true uncertainty in the analysis. 

Another approach to examining these uncertainties is to identify variables with the 

greatest impact on the overall results and apply sensitivity analysis. This is the approach we 

have taken, for example, looking at a range of ethanol plant types, as well as ranges of land use 

change factors. In this way we bound the results with high and low cases. The challenge in a 

complicated analysis with so many variables, of course, is to ensure that we have identified the 

most significant factors influencing GHG emissions, and that our choices of low and high cases 

accurately encompass the range of possible outcomes. We note that further research on key 

variables will allow for a more robust assessment of these impacts in the future. 

2.4 Baseline Gasoline and Diesel Fuel 

2.4.1 Modeling Approach 

EISA specified the baseline petroleum gasoline and diesel fuel that renewable fuels 

would be compared to for assessing their performance in comparison to the thresholds. 

The term ‘baseline lifecycle greenhouse gas emissions’ means the average lifecycle 

greenhouse gas emissions, as determined by the Administrator, after notice and 

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opportunity for comment, for gasoline or diesel (whichever is being replaced by the 

renewable fuel) sold or distributed as transportation fuel in 2005. 

To estimate the lifecycle GHG emissions associated with baseline petroleum-based 

gasoline and diesel fuel, we based our analysis on the GREET model. Lifecycle energy use and 

associated emissions for petroleum-based fuels in GREET are calculated based on energy 

efficiency metrics for the different processes involved in petroleum-based fuels production. The 

energy efficiency metric is a measure of how many Btus of input energy are needed to make a 

Btu of output product. GREET has assumptions on energy efficiency for different finished 

petroleum products as well as for different types of crude oil. 

GREET also has assumptions on the mix of energy sources used to provide the energy 

input which determine GHG emissions. The GHG emissions associated with petroleum fuels are 

based on the emissions from producing and combusting the input energy sources (with noncombustion sources included where applicable). 

The following sections describe the GREET assumptions for different petroleum-based 

fuels production processes and final products. 

2.4.2 Crude Oil Extraction 

GREET has assumptions for different types of crude oil extraction, conventional crude 

and oil sands crude.NNNNNNN The values for conventional crude oil are assumed to represent 

average crude oil extraction, including domestic and foreign production, and onshore, offshore 

and enhanced oil recovery processes. Oil sands recovery was used in this analysis to represent 

Canadian oil sands recovery. The assumptions for each type of crude oil extraction are shown 

here. 

Conventional crude oil extraction is assumed to have an energy efficiency metric of 98%. 

This means that every one mmBtu of crude oil produced requires 1,020,408 Btu of energy input. 

One mmBtu of that input is crude oil feedstock (from the ground) that ends up in the final 

product and therefore only 20,408 Btu of additional process energy is required. Table 2.4-1 

shows the breakout of the energy sources used to provide the additional process energy. 

NNNNNNN Oil sands crude is also commonly referred to as tar sands. 

305 
 

Table 2.4-1. Conventional Crude Oil Production 

Process Fuel Share of Input Energy 

(%) 

Energy use 

(Btu/mmBtu of fuel throughput) 

Crude oil 1.0% 204 

Residual oil 1.0% 204 

Diesel fuel 15.0% 3,057 

Gasoline 2.0% 408 

Natural gas 61.9% 12,635 

Electricity 19.0% 3,872 

Feed loss 0.1% 28 

Total: 100% 20,408 

The GHG emissions from conventional crude oil extraction are calculated by multiplying 

the Btus of the different types of energy inputs by emissions factors for combustion of those fuel 

sources. The emission factors for the different fuel types are from GREET based primarily on 

assumed carbon contents of the different process fuels. The emissions from producing electricity 

are also taken from GREET and represent average U.S. grid electricity production emissions. In 

addition to process energy GHG emissions, GREET also assumes there are also GHG emissions 

from associated flaring of natural gas at the oil well, assuming 16,800 Btu of natural gas is flared 

per mmBtu of crude oil produced. The GHG emissions from flared natural gas are again based 

on emissions factors for natural gas combustion. GREET also accounts for fugitive methane 

emissions from crude oil extraction and processing, assuming that 13.15 g of fugitive methane is 

released per mmBtu of crude oil produced. 

Similar to the assumptions for conventional crude oil extraction, GREET has assumptions 

about oil sands crude oil extraction. Oil sands can be either mined or recovered in situ - meaning 

in place, GREET has assumptions for both processes. The oil sands recovery processes include 

both extraction (surface or in situ) and separation systems to remove bitumen from sand and 

water. 

Surface mining of oil sands involves open-pit mining techniques. About two metric tons 

of oil sands must be dug up, moved and processed to produce one barrel of oil. In situ recovery 

is used for bitumen deposits buried too deeply for mining to be practical. Cyclic steam 

stimulation (CSS) and steam-assisted gravity drainage (SAGD) are in situ recovery methods, 

which include thermal injection through vertical or horizontal wells. The following Tables show 

the energy efficiency metric and assumed energy sources used in oil sands extraction. GHG 

emissions from the oil sands extraction process are based on applying emission factors to the 

different energy inputs. 

306 
Table 2.4-2. Oil Sands Recovery: Bitumen Extraction – Surface Mining 

Energy Efficiency 94.8% 

Process Fuel Share of Input Energy 

(%) 

Energy use 

(Btu/mmBtu of fuel throughput) 

Diesel fuel 0.6% 329 

Natural gas 82.3% 45,132 

Electricity 17.1% 9,377 

Feed loss 0.03% 14 

Total: 100% 54,852 

Table 2.4-3. Oil Sands Recovery: Bitumen Extraction – In-Situ Production 

Energy Efficiency 84.3% 

Process Fuel Share of Input Energy 

(%) 

Energy use 

(Btu/mmBtu of fuel throughput) 

Natural gas 97.2% 181,011 

Electricity 2.8% 5,214 

Feed loss 0.01% 14 

Total: 100% 186,239 

Once oil sands are extracted through either the surface mining or in situ process they are 

further processed for transportation. The energy efficiency metric and assumed energy input 

sources for the bitumen upgrading are shown in Table 2.4-4. 

Table 2.4-4. Oil Sands Recovery: Bitumen Upgrading 

Energy Efficiency 98.6% 

Process Fuel Share of Input Energy 

(%) 

Energy use 

(Btu/mmBtu of fuel throughput) 

Natural gas 97.1% 13,787 

Electricity 2.8% 397 

Feed loss 0.1% 14 

Total: 100% 14,198 

In addition to the GHG emissions from the process energy used in the upgrading process, 

GREET also assumes hydrogen is needed as an input to the upgrading process. GHG emissions 

from hydrogen production, based on GREET defaults, are included in the emissions of bitumen 

upgrading. GREET assumes 84,187 Btu of hydrogen is used per mmBtu of oil sand crude 

produced through surface mining, and 32,364 Btu of hydrogen is used per mmBtu of oil sand 

crude produced through the in situ process. 

Emission factors from GREET were used for bitumen extracted in-situ, bitumen extracted 

by surface mining, and light crude oil extraction. Emission factors from McCann (1999) were 

used to calculate GHG emissions from heavy oil and Venezuela extra heavy oil by considering 

the incremental extraction and processing emissions relative to the average of the light crudes 

analyzed by McCann.515 Instead of using McCann GHG values directly we used these results to 

307 
 

 

determine a scaling factor for the heavy crudes compared to the conventional crude types. We 

then applied this scaling factor to the GREET conventional crude emissions to represent 

emissions from heavy crude production. The results of the crude oil production differentiation 

are shown below in Table 2.4-5. 

Table 2.4-5. 

Scaling factors Used to Calculate Heavy Crude Extraction GHG Emissions 

Crude Production Emissions (gCO2-eq. / mmBtu LHV of fuel produced) 

Canadian 

Light 

Brent North 

Sea 

Saudi 

Light 

Average 

"conventional" 

Heavy 

Oil 

Venezuela Extra 

Heavy Oil 

Production 

Emissions 6,617 5,081 7,746 6,482 6,962 15,524 

Scaling Factor 1.07 2.40 

The importation of heavy crude oil and extra heavy crude oil in the U.S. comprises a 

relatively small but growing fraction of current total crude oil imports. Heavy crude oils are 

generally of higher density and higher viscosities compared to lighter crude oils and similarly, 

are not as readily extracted from reserves. The American Petroleum Institute’s “API Gravity” is 

commonly used to delineate light, medium, heavy and extra heavy crude oils. Although 

definitions can vary slightly, the U.S. Geological Survey (USGS) categorizes light crude oil as 

having an API gravity of at least 22° and viscosity less than 100 centipoise (cP).516 Heavy oil, 

by contrast, is defined as an “asphaltic, dense, and viscous oil” with an upper API limit of 22° 

and viscosity between 100 – 10,000 cP. Heavy oil with an API less than 10° is defined as extraheavy oil. Natural bitumen –also referred to in the literature as oil sand, tar sand, oilimpregnated sand, asphaltic sand, rock asphalt, bituminous rock, and bitumen-bearing rock– 

have a similar API range as extra-heavy oils but have viscosities greater than 10,000 cP. 

To determine the mix of crudes used in 2005 to produce the gasoline and diesel baseline 

required by EISA, EPA analyzed the types of crude oils used in the U.S. by examining crude oil 

import data from the Energy Information Administration for 2005, which is based on reporting 

by refineries.517 The amount of crude imports reported by refineries with API less than or equal 

to 22° – heavy oil – was approximately 2.9 million barrels per day (mmbd) in 2005 out of the 

15.2 mmbd refinery net input in the U.S. estimated by EIA. Figure 2.4-1 below displays the 

break-down of U.S. heavy crude imports by country. 

308 
Mexico 

Venezuela 

Canada 

Ecuador 

Brazil 

Chad 

Norway 

Russia 

United Kingdom 

Kuwait 

Angola 

Saudi Arabia 

Indonesia 

Guatamala 

China 

Peru 

Columbia 

Nigeria 

Malaysia 

Oman 

Argentina 

Bolivia 

Figure 2.4-1. U.S. Imports of Heavy Crude Oil in 2005 (API of 22° or less) 

2005 Heavy Oil Imports (<=22.0) 

Source: EIA Form 814 Data 

-

200,000 

400,000 

600,000 

800,000 

1,000,000 

1,200,000 

bb l/ day

Barrels per Day 

Note that this is an underestimate of the actual heavy crude oil, extra heavy crude oil, or 

bitumen used by U.S. refineries since a fraction of these crudes are upgraded at the country of 

origin and/or diluted with diluents (gas condensate, natural gas liquids or light crude) and 

transported to the U.S. These upgraded crude oils would then appear as imports with an API 

greater than 22° (i.e. light or medium crude oil). EPA has identified that crude oil from 

Venezuela and Canada would likely have the most upgrading of extra heavy crude oil or bitumen 

to synthetic crude, or syncrude, due to the nature of the reserves and current information 

regarding the crude oil types extracted. The International Energy Agency estimates that in 2005, 

Venezuela produced approximately 565,000 bpd of syncrude from its extra heavy oil reserves in 

the Orinoco oil belt.518 An analysis of the production output from the four members of the 

Orinoco Belt Strategic Association shows that roughly three-fourths of the upgraded syncrude 

has an API greater than 22°.519 Thus, out of the 3 mmbd of crude oil produced in Venezuela, 

approximately 19% was syncrude (i.e. 14% with API greater than 22° and 5% with API less than 

22%). Applying these splits to the U.S. import data would result in roughly 145,000 bpd of 

syncrude from extra heavy oil, 715,000 heavy oil, and 684,000 light (or conventional) crude oils. 

This split would still likely underestimate the extra heavy oil/syncrude used by the U.S. since 

Venezuela tends to ship a greater fraction of its heavier crude oils to U.S. refineries that are 

specifically configured to handle heavier crude oils. 

Estimates on the types of crude oil imported from Canada were also adjusted based on 

available information. Canadian production information for 2005 was obtained from statistical 

information from the Canadian Association of Petroleum Producers.520 Production of crude oil 

in Canada totaled 2.35 mmbd in 2005, with 35% of the volume comprised of light crude oil, 22% 

heavy crude oil, 23% from bitumen or synthetic crude obtained via surface mining, and 19% 

from bitumen produced from in-situ methods. Surface mining comprised over half of the 

Canadian bitumen extraction, but use of in-situ techniques is now growing at a faster rate due to 

the lower availability of surface bitumen and improvements in in-situ techniques. 

309 
Domestic production of heavy oil was not included in the EIA import data analyzed by 

the EPA.521 To account for this, various estimates were used from different sources. In 2005, we 

estimate that roughly 475,000 bpd of heavy oil was produced in the U.S. with the vast majority 

produced in California. 

A fraction weighted estimate of the crude oil types used in the U.S., calculated based on 

the data sources and calculations described above, was used in our estimation of the 2005 

gasoline and diesel baseline. Note that this does not include crude-type breakdowns for finished 

products imported into the U.S. from overseas (e.g. Europe) or exported and consumed overseas, 

which may change the fractions slightly. Out of the 15.3 mmbd of crude oil reported to be used 

in the U.S. in 2005522, approximately 5% was composed of bitumen-based syncrude (mainly 

from Canada), 1% was extra heavy crude oil based syncrude (mainly from Venezuela), and 23% 

was heavy crude oil, as shown in Figure 2.4-2. 

Figure 2.4-2. Percent of U.S. Crude Oil by Source 

U.S. Crude Oil Consumption 

5% 1% 

23% 

72% 

-

2.00 

4.00 

6.00 

8.00 

10.00 

12.00 

million barrels per day . . 

Bitumen-based Extra heavy oil-based Heavy crude oil Light or medium crude 

syncrude syncrude oil 

The emission factors for the 2005 baseline were adjusted based on the above weighting 

for the different types of crude oil. 

2.4.3 Crude Transport 

Transport of crude oil to the U.S. was based on GREET defaults, which are shown in the 

Figure 2.4-3. The figure indicates the percent of the different types of crude oil used (Canada 

and Mexico are assumed to include the Canadian oil sands imports) and associated modes of 

transportation and miles traveled for each mode. The GHG emissions are based on emission 

factors for each type of vehicle including capacity, fuel economy, and type of fuel used. 

310 
Figure 2.4-3. Crude Oil Transportation Assumptions 

7.0% 7.0% 

2,100 

35.0% 

1.0% 

500 

50.0% 50.0% 

5,500 92.0% 

750 

8.0% 

750 0.0% 

8.0% 800 

0.0% 

800 

US Terminal 

Petroleum 

Refinery 

Domestic: 

Alaska 

Domestic: 

US 48 States 

Imported: 

Canada and 

Mexico 

Imported: 

Offshore 

Countries 

Ocean Tanker 

Pipeline 

Rail 

Ocean Tanker 

Pipeline 

Barge 

Rail 

2.4.4 Refining 

The GHG emissions associated with petroleum refining can also be calculated based on 

the energy efficiency of the refinery and the type of process energy fuel sources used. However, 

the refinery is producing a number of different petroleum-based products including different 

transportation fuels. Therefore, the total energy use and emissions from the refinery needs to be 

allocated to the different products. 

The basis for the overall refinery energy efficiency in GREET are numerous linear 

programming model runs representing energy use in a typical refinery. Different refinery 

configurations with different slates of products produced will have different energy efficiencies. 

For calculating baseline GHG emissions associated with gasoline and diesel fuel we are 

assuming an average U.S. refinery, so defaults in GREET are reasonable for our analysis. 

Allocation of the total refinery energy use and emissions to the different products can be 

done in a number of ways. Total energy use and emissions can be allocated based on the energy, 

mass, or economic value of the different output products. Alternately, energy use and emissions 

can be based on first breaking out total refinery energy use to the different refinery sub-processes 

(e.g., distillation, cracking, alkylation, isomeration, desulfurization), and then allocating energy 

from each sub process to the different products, for example 100% of alkylation used for 

gasoline. This type of sub process allocation would require a level of detail that was beyond the 

scope of this analysis. Therefore, we used the GREET default allocation which in general 

allocated 60–65% of total refining process fuel use to gasoline production, 18–22% to diesel 

production, and the remaining 13–22% to other petroleum products. 

The refinery modeling runs and the allocation to different products results in the energy 

efficiency values for different types of gasoline and diesel fuel shown in Table 2.4-6. 

311 
 

Table 2.4-6. Refinery Energy Efficiency 

Transportation Fuel Type Energy Efficiency 

Conventional Gasoline 87.7% 

Reformulated Gasoline Feedstock 87.2% 

Low Sulfur Diesel Fuel 89.3% 

The following table shows the process fuel breakout and energy use for each 

transportation fuel. 

Table 2.4-7. Refinery Energy Use 

Process Fuel Share of Input Energy use (Btu/mmBtu of fuel throughput) 

Energy 

(%) 

Conventional 

Gasoline 

RFG Feedstock Low Sulfur Diesel 

Fuel 

Residual oil 3.0% 4,208 4,404 3,595 

Natural gas 30.0% 42,075 44,037 35,946 

Coal 13.0% 18,233 19,083 15,577 

Electricity 4.0% 5,610 5,872 4,793 

Refinery still 

gas 

50.0% 70,125 73,395 59,910 

Total: 100% 140,251 146,789 119,821 

The GHG emissions from refining are calculated by multiplying the Btus of the different 

types of energy inputs by emissions factors for combustion of those fuel sources. The emission 

factors for the different fuel types are from GREET based primarily on assumed carbon contents 

of the different process fuels. The emissions from producing electricity are also taken from 

GREET and represent average U.S. grid electricity production emissions. In addition to process 

energy GHG emissions, GREET also assumes there are also non-combustion GHG emissions 

associated with petroleum refining. These emissions are also allocated to the different fuels 

based on the same energy efficiency ratios used to allocate energy use. The non-combustion 

CO2 emissions amount to 1,172 g CO2 per mmBtu of conventional gasoline, 1,214 g CO2 per 

mmBtu of RFG blendstock, and 1,088 g CO2 per mmBtu of low sulfur diesel fuel. 

To represent baseline gasoline we considered the types of gasoline used in 2005. Based 

on EIA data on sales of gasoline to end users in 2005, 57.4% was conventional gasoline, 28.4% 

was reformulated gasoline and 14.2% was Californian reformulated gasoline. The California 

reformulated gasoline is represented in GREET as reformulated with slightly different 

assumptions about crude transport distances. We also considered imported finished product vs. 

domestically produced gasoline. According to EIA data, in 2005 6.0% of conventional gasoline 

used was imported and 7.7% of reformulated gasoline was imported. Imported gasoline was 

modeled the same as domestic for refinery emissions, except conventional crude was used to 

represent crude oil production impacts, instead of a domestic mix. To represent baseline diesel 

fuel use we used a similar analysis and assumed 100% low-sulfur diesel fuel and 8.0% imported 

finished product. 

2.4.5 Fuel Transport 

Transport of the finished petroleum product was also included in the baseline values for 

gasoline and diesel fuel. Transport included carriage from refinery to bulk terminal and from 

312 
bulk terminal to retail location. Transport of imported finished product was also included and 

was assumed to be transported by ocean tanker 2,600 miles to the U.S. Once in the U.S. both 

domestic and imports were assumed to be transported by the modes and distances shown in 

Tables 2.4-8 and 2.4-9. 

Table 2.4-8. Gasoline Transport Assumptions 

Refinery to Bulk Terminal Bulk Terminal to Refueling Station 

Mode Percent Distance Percent Distance 

Ocean Tanker 17 1,500 0 N/A 

Barge 4 520 0 N/A 

Pipeline 72 400 0 N/A 

Rail 7 800 0 N/A 

Truck 0 N/A 100 30 

Table 2.4-9. Diesel Fuel Transport Assumptions 

Refinery to Bulk Terminal Bulk Terminal to Refueling Station 

Mode Percent Distance Percent Distance 

Ocean Tanker 12 1,500 0 N/A 

Barge 6 520 0 N/A 

Pipeline 72 400 0 N/A 

Rail 7 800 0 N/A 

Truck 0 N/A 100 30 

The GHG emissions from transport of gasoline and diesel fuel were based on GREET 

default emission factors for each type of vehicle including capacity, fuel economy, and type of 

fuel used. 

2.4.5 Petroleum Fuel 2005 Baseline Well-To-Tank GHG Emissions 

The results of each of the lifecycle stages for the petroleum fuels were combined to 

generate a well-to-tank lifecycle GHG value for 2005 gasoline and diesel fuel as shown in Table 

2.4-10. Tailpipe combustion emissions for the two fuels are described in Section 2.7. When the 

tailpipe emissions are included, the well-to-wheel results for baseline gasoline and diesel fuel are 

98,395 and 96,843 gCO2eq/mmBtu respectively. 

Table 2.4-10. 

Petroleum Fuel Baseline Well-To-Tank GHG Emissions 

(g/mmBtu of fuel) 

CH4 N2O CO2 CO2-eq. 

Diesel Fuel 106 0.25 15,074 17,381 

Gasoline 107 0.27 16,762 19,102 

In December 2008, the U.S. Department of Energy’s National Energy Technology 

Laboratory (NETL) released a report that estimates the average lifecycle GHG emissions from 

313 
 

 

petroleum-based fuels sold or distributed in 2005.OOOOOOO The estimates in the report are based 

on a slightly different methodology than EPA’s analysis of lifecycle GHG emissions for the 

petroleum baseline. The NETL report is available on the docket for this rulemaking. 

2.5 Secondary Energy Sector Impacts Modeling 

2.5.1 Indirect Energy Sector Impacts from Renewable Fuel Consumption 

We have started an analysis using an EPA version of the Energy Information Agency’s 

National Energy Modeling System (NEMS-EPA)PPPPPPP to estimate indirect impacts on energy 

use associated with increased renewable fuel consumption. NEMS is a modeling system that 

simulates the behavior of energy markets and their interactions with the U.S. economy by 

explicitly representing the economic decision-making involved in the production, conversion, 

and consumption of energy products. NEMS can represent the secondary impacts that greater 

renewable fuel use may have on the prices and quantities of other sources of energy, and the 

GHG emissions associated with these changes in the energy sector. For example, the use of 

natural gas at corn ethanol production plants could increase the price of natural gas, and thus 

encourage the use of other energy sources in other sectors of the economy. Due to time 

constraints, we did not include indirect energy sector impacts in the lifecycle GHG results for the 

proposed rule. Below we explain the preliminary results, and outline our plans to refine this 

analysis for the final rule. 

We successfully used NEMS-EPA to simulate the RFS2 fuel volumes for this 

rulemaking, and the projections from that effort were used in our energy security results, and 

other analyses for the proposed rule. However, we had difficulties isolating volume changes for 

specific renewable fuel types. When we attempted to model the fuel-specific volume scenarios 

that were used for FASOM and FAPRI analysis of the agricultural sector (See Section 2.3.2 for a 

description of the FASOM and FAPRI fuel-specific scenarios), we had trouble designing model 

runs that held the other fuel volumes constant. For example, when we tried to use NEMS-EPA 

to model an increase in corn ethanol consumption from 12.4 to 15 billion gallons, the volumes of 

cellulosic ethanol consumption also changed. We could not use model results with variable 

cellulosic ethanol production to estimate the secondary energy sector impacts of corn ethanol, 

because the modeled cellulosic ethanol plants export electricity to the grid, which has significant 

energy sector impacts that could not be assigned to corn ethanol. 

To effectively model a scenario where only corn ethanol consumption increased, we 

departed from the volume scenarios that were used for the other analyses in this rule. Table 2.5­

1 shows renewable fuel volumes for two NEMS-EPA scenarios (Lower Corn Ethanol and 

Control Case) that successfully varied corn ethanol consumption and held cellulosic ethanol 

consumption constant. 

OOOOOOO DOE/NETL. 2008. Development of Baseline Data and Analysis of Life Cycle Greenhouse Gas Emissions 

of Petroleum-Based Fuels. DOE/NETL-2009/1346 

PPPPPPP This version is called NEMS-EPA to make it clear that EPA, rather than EIA, conducted this analysis. 

314 
Several assumptions were modified in order to create the differences in corn ethanol 

while keeping the other biofuels (such as cellulosic ethanol and biodiesel) unchanged between 

the cases. In addition, a larger difference in corn ethanol than that of the Reference to EISA 

cases was desired so that the change was more significant relative to the convergence tolerance 

of the model. 

In the Lower Corn Ethanol Case, the RFS credit was reduced for non-advanced biofuels 

(i.e. corn ethanol) and the cost of new corn ethanol plants was increased in order to reduce 

projected corn ethanol production. The Control Case includes a higher RFS requirement for total 

biofuels to give credit to corn ethanol above 15 billion gallons as well as a reduction in the cost 

of new corn ethanol plants. Both cases also include modifications to the cost of soy-based 

biodiesel as a device that keeps the biodiesel production only at the minimum EISA-mandated 

level in both cases. We modified the RFS requirements such that the cellulosic requirement 

would be met and be binding in both cases, and reduced the advanced biofuels requirements to 

equal that of cellulosic. Both changes were made to minimize the change in other biofuels 

between the two cases. The cases also eliminate biomass-to-liquids (which was included in 

EIA’s Annual Energy Outlook but not included in any of the EPA cases). 

Table 2.5-1. Fuel Volumes for NEMS Corn Ethanol Scenario 

(Billions of Gallons Consumed Per Year) 

2017 2022 

Lower Corn 

Ethanol Case Control Case Difference 

Lower Corn 

Ethanol Case Control Case Difference

 Corn Ethanol 10.5 15.2 4.8 4.1 15.6 11.5

 Cellulosic Ethanol 3.0 3.0 0.0 12.5 12.5 0.0

 Imported Ethanol 1.5 2.2 0.7 1.2 3.0 1.8

 Exported Ethanol 1.0 0.7 -0.3 1.2 0.5 -0.7

 Biodiesel 1.0 1.0 0.0 1.0 1.0 0.0 

Total Biofuels 16.9 22.0 5.1 20.0 32.5 12.6 

We computed the difference in energy consumption between the Control Case and the 

Low Corn Ethanol Case shown in Table 2.5-1. New ethanol plants built after 2015 were 

modeled to use natural gas and electricity but not coal as energy sources. To isolate the indirect 

energy sector impacts not included in the rest of our lifecycle analysis, we excluded changes in 

energy use for biofuel refining, agriculture, petroleum refining, and gasoline and diesel use for 

transportation. In other words, we used the NEMS-EPA analysis to project how an increase in 

corn ethanol production would affect energy consumption in the residential, commercial, and 

non-refining industrial sectors. Table 2.5-2 shows how energy consumption in these sectors 

changed between the Control Case and the Lower Corn Ethanol case. 

315 
 

 

 

 

 

 

 

 

 

 

Table 2.5-2. Projected Indirect Impacts from Corn Ethanol Production on Energy Use by 

Energy Source in the Residential, Commercial, and Non-Refining Industrial Sectors 

(Quadrillion Btu) 

2017 2022 

Lower Corn 

Ethanol Case Control Case Difference 

Lower Corn 

Ethanol Case Control Case Difference 

Liquid Fuels 14.585 14.587 0.002 14.653 14.683 0.030

 Liquified Petroleum Gases 2.489 2.489 0.000 2.397 2.396 -0.001

 E85 0.000 0.000 0.000 0.000 0.000 0.000

 Motor Gasoline 0.423 0.423 0.000 0.422 0.421 0.000

 Jet Fuel 3.955 3.955 0.000 4.283 4.283 0.000

 Kerosene 0.124 0.124 0.000 0.125 0.125 0.000

 Distillate Fuel Oil 2.582 2.582 -0.001 2.541 2.540 -0.001

 Residual Fuel Oil 1.567 1.568 0.001 1.569 1.574 0.006

 Petrochemical Feedstocks 1.433 1.433 0.000 1.357 1.357 0.000

 Liquid Hydrogen 0.000 0.000 0.000 0.002 0.002 0.000

 Other Petroleum 2.010 2.012 0.002 1.958 1.984 0.026 

Natural Gas 23.270 23.274 0.003 22.867 22.813 -0.054 

Coal 24.641 24.642 0.001 26.410 26.501 0.092 

Nuclear Power 8.487 8.484 -0.003 9.194 9.158 -0.036 

Hydropower 2.985 2.983 -0.001 3.009 3.007 -0.003 

Traditional Biomass 2.569 2.569 0.000 2.786 2.786 -0.001 

Other Renewable Energy 1.786 1.785 -0.001 2.023 2.023 0.000 

Other 0.180 0.180 0.000 0.175 0.175 0.000 

Total 78.503 78.504 0.001 81.119 81.146 0.027 

We applied emissions factors to estimate the GHG impacts of the energy consumption 

changes shown in Table 2.5-2. We estimated the GHG impacts in terms of GHG emissions 

impacts per Btu of additional corn ethanol consumption. The results in Table 2.5-2 imply an 

increase in GHG emissions of 1,356 g/mmBtu in 2017, and an increase in GHG emissions of 

9,290 g/mmBtu in 2022. A large part of these GHG results can be attributed to the increase in 

coal consumption and the decrease in nuclear energy consumption projected by NEMS-EPA in 

the Control Case relative to the Lower Corn Ethanol Case. If we hold nuclear energy 

consumption constant (i.e. assume that Control Case nuclear power consumption equals nuclear 

power consumption in the Lower Corn Ethanol Case), the GHG impacts become an increase of 

437 g/mmBtu in 2017 and an increase of 5,117 g/mmBtu in 2022. 

We did not include the results of this NEMS-EPA analysis in our lifecycle GHG 

estimates for the proposed rule. For the final rule we intend to continue exploring the use of 

NEMS-EPA to estimate the indirect energy sector impacts of renewable fuel consumption. To 

use the NEMS-EPA model for this purpose, we would like to gain a better understanding of why 

the energy sector impacts vary between years. We may also explore other models and data 

sources that could be utilize for this part of the lifecycle analysis. 

2.5.2 Indirect Impacts on Petroleum Consumption for Transportation 

EPA recognizes that with the increase in demand for biofuels from the RFS2 program 

there could be secondary impacts on oil markets. For example, an increase in the use of biofuels 

could result in lower U.S. demand for imported oil. Lower U.S. imported oil demand could cause 

the world oil price to modestly decline, and result in an increase in oil consumption outside of 

the U.S. (referred to here as the “international oil takeback effect”). In addition, with the greater 

use of biofuels in the U.S., we estimate that the cost of transportation fuels in the U.S. would 

316 
increase. This increase in the costs of U.S. transportation fuels would likely lower the domestic 

demand for oil beyond the direct substitution of biofuels for gasoline and diesel. The response of 

U.S. oil demand to price is referred to here as the “rebound effect.” From an overall standpoint, 

total global oil demand is the result of the two combined effects, decreases in U.S. oil demand 

(from the “rebound effect”) and increases in oil demand outside of the U.S. (from the 

“international oil takeback effect”). These effects work in opposite directions to influence the 

overall change in global oil demand. Besides providing a complete picture of oil market impacts 

of the RFS2 program, this issue could also be important because secondary impacts on oil 

demand from the RFS2 program, assuming that they can be reliably determined, could be 

factored into the lifecycle GHG emissions estimates. 

Estimates of the “international oil takeback effect” and, to a lesser extent, the “rebound 

effect” are difficult to quantify. Take the case of the “international oil takeback effect.” While a 

decline in the world oil price is likely to increase world oil consumption, oil consumption 

patterns vary significantly across different regions of the world (i.e., Southeast Asia, South 

America). As a result, each region may have a different demand response to a change in the 

international price of crude oil. For example, in Europe, the price of crude oil comprises a much 

smaller portion of the overall fuel prices seen by consumers than in the U.S., since Europeans 

pay significantly more fuel tax than their U.S. counterparts. A decline in the price of crude oil is 

likely to have a smaller impact on prices at the pump and therefore a lesser impact on demand. 

In many other countries, particularly developing countries such as China and India, oil is used 

more widely in industrial and electricity generation applications, although the energy picture in 

China and India is evolving rapidly. In addition, many countries around the world subsidize 

their oil consumption, and oil markets are influenced by monopolistic control of prices, both on 

the supply and demand sides. It is, therefore, not clear how oil consumption would change due 

to changes in the market price of oil with the current pattern of subsidies. The factors listed 

above illustrate the difficulty in trying to estimate the overall impact of a reduction in world oil 

price on oil consumption outside of the U.S. 

Even for the U.S., there is some controversy about the impact of a change in the price of 

oil on domestic U.S. oil consumption. Since approximately 70 percent of the U.S. oil use is 

concentrated in the U.S. transportation sector, most discussion of the so called “rebound effect” 

revolves around the impact of a change in driving in response to a change in the price of 

transportation fuels. Many factors influence the magnitude of the U.S. rebound effect, including 

how fuel cost increases are passed through to prices at the pump for consumers, the composition 

of adult drivers, the level of urbanization, income levels, and the amount of congestion. 

In any case, the Agency recognizes that both the “international oil takeback effect” and 

the “rebound effect” are important to estimate and we are examining methodologies for 

quantifying them for the final rule. For example, the most straightforward approach would be to 

utilize an elasticity estimate of global oil demand with respect to the international oil price and 

use this estimate to calculate the “international oil takeback effect.” However, a global estimate 

would not capture regional or country specific demand responses, which as indicated above 

could be very different. Alternatively, as another approach for estimating the “international oil 

takeback effect,” EPA is asking ORNL to explore an approach based upon a review of the 

international energy economics literature to see if a set of bottom-up estimates of oil demand 

317 
 

elasticities by world regions (i.e., Southeast Asia and South America) and oil-using sectors (i.e., 

transportation and non-transportation) can be developed and used to address this issue. If the 

bottom-up estimates can be developed or a global demand elasticity can be agreed upon, they 

will help inform the development by ORNL of an integrated petroleum/biofuels market tool to 

examine fuel market issues associated with the RFS2 program. 

2.6 Biofuels Analysis 

2.6.1 Modeling Approach 

As mentioned in Section 2.2, to address some of the issues with our RFS1 lifecycle 

modeling for biofuels we have updated our methodology to include the use of agricultural sector 

economic models. Our methodology involves the use of the FASOM model to determine 

domestic agriculture sector-wide impacts of increased biofuel production, and the FAPRI model 

to determine international changes in crop production and total crop. Agricultural sector GHG 

emissions are estimated by FASOM, and FAPRI results were converted to GHG emissions based 

on GREET defaults and IPCC emission factors. Biofuel process energy use and associated GHG 

emissions were based on process models for the different pathways considered. Feedstock and 

co-product transportation GHG emissions were based on GREET defaults. 

The agricultural sector models were used to determine the impacts associated with 

biofuels production by comparing two similar scenarios in both models. Both agricultural sector 

models were run with two similar volumes of the specific fuel in question, while other fuel 

volumes were held constant to isolate the fuel-specific impacts. Table 2.6-1 shows the 2022 fuel 

volumes modeled in FASOM in order to isolate the incremental impacts of each type of 

renewable fuel. Section 2.3 includes more discussion of the fuel volume scenarios. 

Table 2.6-1. 2022 Fuel Volumes Modeled with FASOM (Billions of Gallons) 

Control Case 

Biodiesel Only 

Case 

Corn Ethanol 

Only Case 

Corn Stover 

Ethanol Only 

Case 

Switchgrass 

Ethanol Only 

Case 

Biodiesel 0.6 0.2 0.6 0.6 0.6 

Corn Ethanol 15.0 15.0 12.4 15.0 15.0 

Corn Stover 

Ethanol 7.6 7.6 7.6 0.0 7.6 

Switchgrass 1.1 1.1 1.1 1.1 5.7 

Bagasse 

Ethanol 1.4 1.4 1.4 1.4 1.4 

The total impacts from changes in biofuel production were calculated by taking the 

difference in total GHG emissions from the two scenarios considered. Per gallon (or mmBtu) 

impacts were calculated by dividing the total GHG emission changes by the increase in volume 

of fuel represented in the scenarios. Therefore, the results presented in this proposed rulemaking 

represent the per mmBtu “average marginal” impact of the change in fuel volumes considered. 

In other words, the GHG impacts were estimated for a marginal increase in fuel production, and 

the average impact of a marginal gallon was calculated. 

318 
2.6.2 Domestic Agriculture 

GHG emissions from the domestic agricultural sector were estimated with the FASOM 

model, a partial equilibrium economic model of the U.S. forest and agricultural sectors. As 

discussed in Section 2.3, FASOM accounts for changes in GHG emissions from most 

agricultural activities, including the total amount of fertilizer, chemicals, gasoline, diesel and 

electricity used on farms for the entire domestic agricultural sector. It also captures changes in 

the soil management, livestock production and U.S. agricultural exports. More detail on the 

FASOM model can be found in Chapter 5 of the DRIA. 

Figure 2.6-1 shows the total harvested crop acres in the different fuel volume cases. The 

projected changes in total harvested acres are modest, partly because we only modeled the 

incremental difference in renewable fuel volumes between the cases. 

Figure 2.6-1. FASOM Projected Domestic Harvested Acres, 2022 

Millions of Harvested Acres 

300 

250 

200 

150 

100 

50 

0 

Corn 

Soybeans 

SwitchGrass 

Wheat 

Rice 

Hay 

Sorghum 

Cotton 

Sugarcane 

Sugarbeet 

Silage 

Oats 

Barley 

Other 

Control Case Biodiesel Only Case Corn Ethanol Only Corn Stover Ethanol Switchgrass Ethanol 

Case Only Case Only Case 

Figure 2.6-2 includes the projected changes in harvested crop acres by field crop for the 

fuel volume cases considered (acreage changes are normalized per thousand gallons of 

renewable fuel production). In the corn ethanol scenario, corn acreage increased; area planted 

with soybeans, hay, sorghum and rice decreased; and harvested acres of other crops were 

practically unchanged. It is not surprising that soybean acreage decreased the most when corn 

ethanol production increased, because corn and soybeans are often in direct competition for 

fertile land. As discussed more below, the small decrease in rice acres had a relatively large 

impact on GHG emissions estimates, because domestic rice production requires more energy 

than other crops and is a source of methane emissions. 

Soy-based biodiesel production induced a large increase in harvested soybean acres, 

largely due to the low yield of soy-based biodiesel in terms of gallons produced per acre. Cotton 

319 
 

 

 

 

 

 

 

 

 

was the only other crop that increased along with biodiesel production. The competition 

between corn and soybeans was evident again, as corn acreage saw the steepest decline. Wheat, 

hay, sorghum, oats and rice also declined when biodiesel volumes increased. 

Production of ethanol from corn residue had a very small effect on the acreage of other 

crops. This was expected because corn stover production does not displace other crop 

production, as corn stover is a residual product of corn cultivation. FASOM did project minor 

amounts of crop shifting in the corn stover scenario, because using corn stover for ethanol can 

increase the profitability of corn production in certain regions, with subsequent impacts. The 

effects of corn stover harvesting on agricultural inputs, such as the need to use more fertilizer 

after stover removal, are discussed below. 

In the scenario where switchgrass ethanol production increased, switchgrass was the only 

field crop to gain acreage. As Figure 2.6-2 shows, new switchgrass plantings displaced a wide 

variety of other crops. As discussed more in DRIA Chapter 5, the FASOM runs for the proposed 

rule project that switchgrass will primarily be grown in Oklahoma, Texas, Virginia and West 

Virginia. 

Figure 2.6-2. 

Normalized Changes in Domestic Cropland by Crop, 2022 

(acres per thousand gallons of renewable fuel) 

4.00 

3.00 

2.00 

1.00 

0.00 

-1.00 

-2.00 

-3.00 

-4.00 

0.13 

0.34 

0.00 

0.28 

Corn Ethanol Soybean Biodiesel Corn Stover Ethanol Switchgrass Ethanol 

Corn and Silage 

Soybeans 

Switchgrass 

Wheat 

Rice 

Sorghum 

Oats 

Hay 

Cotton

 Other Crops 

Net Total Cropland 

Harvested Acres per Thousand Ethanol Equivalent Gallons 

320 
 

 

 

2.6.2.1 Domestic Crop Inputs 

FASOM utilizes data about crop inputs to build crop budgets for field crops across 11 

market regions and 63 sub-regions. FASOM crop budgets include data on yields, fertilizer, 

chemicals, and energy use needed to grow crops in each of the different regions. The crop 

budgets are based on USDA historic data and are also projected into the future. The crop 

budgets represent an average for each region, and do not specifically calculate input or yield 

changes that could result from the use of marginal croplands or altered crop rotation patterns 

(e.g., continuous corn production).QQQQQQQ Table 2.6-2 defines the 11 market regions in 

FASOM. DRIA Chapter 5 includes a detailed discussion of the FASOM crop budgets, including 

assumptions about crop yields and yield growth rates. Below we provide a summary of some of 

the key FASOM assumptions that were used to estimate domestic agricultural GHG emissions. 

Table 2.6-2. Definitions of 11 Market Regions in FASOM 

Key Market Region Production Region (States/Subregions) 

NE Northeast Connecticut, Delaware, Maine, Maryland, Massachusetts, New 

Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, 

Vermont, West Virginia 

LS Lake States Michigan, Minnesota, Wisconsin 

CB Corn Belt All regions in Illinois, Indiana, Iowa, Missouri, Ohio (IllinoisN, IllinoisS, 

IndianaN, IndianaS, IowaW, IowaCent, IowaNE, IowaS, OhioNW, OhioS, 

OhioNE) 

GP Great Plains Kansas, Nebraska, North Dakota, South Dakota 

SE Southeast Virginia, North Carolina, South Carolina, Georgia, Florida 

SC South Central Alabama, Arkansas, Kentucky, Louisiana, Mississippi, Tennessee, Eastern 

Texas 

SW Southwest (agriculture 

only) 

Oklahoma, All of Texas but the Eastern Part (Texas High Plains, Texas 

Rolling Plains, Texas Central Blacklands, Texas Edwards Plateau, Texas 

Coastal Bend, Texas South, Texas Trans Pecos) 

RM Rocky Mountains Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Utah, 

Wyoming 

PSW Pacific Southwest All regions in California (CaliforniaN, CaliforniaS) 

PNWE Pacific Northwest— 

East side (agriculture 

only) 

Oregon and Washington, east of the Cascade mountain range 

PNWW Pacific Northwest— 

West side (forestry 

only) 

Oregon and Washington, west of the Cascade mountain range 

QQQQQQQ FASOM does not explicitly model the selection of alternative crop rotations. Because the model operates 

in 5-year time steps, it has not generally been applied to shorter-term decisions such as changes in rotation patterns. 

Rather, the model data implicitly reflect average conditions for crop production (e.g., yields, input use, etc.) 

associated with historical rotation patterns on a regional level. 

321 
 

The crop budgets included in the FASOM model include data on input use that varies by 

crop, management practices, and region (See DRIA Chapter 5 for a full listing). There is often 

considerable regional variation in the inputs used per acre, which suggests that total input use 

(and the associated GHG emissions and other environmental impacts) will be affected as biofuel 

production causes crop shifting and alters crop management practices. For example, nitrogen 

fertilizer use is an important factor for lifecycle GHG analysis because of GHG emissions from 

fertilizer production and use. Figure 2.6-3 includes FASOM assumptions about average nitrogen 

fertilizer use by crop in 2022 for non-irrigated production without residue harvesting. Regions 

that have a zero nitrogen fertilizer use rate are not included in the averages. Figure 2.6-3 

illustrates the relative fertilizer intensity of major crops. The figure indicates that corn, hay and 

silage are relatively fertilizer-intense crops; whereas soybeans require less than 10 pounds of 

nitrogen per acre (soybeans naturally fix nitrogen in the soil as they grow). 

Figure 2.6-3. 

FASOM Average Nitrogen Fertilizer Use by Crop, 2022 

Non-Irrigated, No Residue Harvesting 

(lbs per acre) 

0 

20 

40 

60 

80 

100 

120 

140 

160 

180 

Nitrogen Fertzilier Use (lbs per acre) 

Corn Soybeans Switchgrass Wheat (hard Rice Sorghum Oats Hay Cotton 

red winter) (irrigated) 

Note: The range indicates the regions with the highest and lowest average nitrogen fertilizer use rates. 

Figure 2.6-4 shows the change in nitrogen fertilizer use by crop per thousand gallons of 

biofuel production. In the corn ethanol scenario, the net increase in fertilizer use is moderated by 

the decrease in hay and rice acres, which use more fertilizer per acre than corn production in 

most regions. Fertilizer use drops in the soy-based biodiesel scenario because soybeans, which 

require scarce fertilizer use, replace crops that require many times more fertilizer per acre. 

Fertilizer use increases in the corn stover ethanol scenario, because additional fertilizer is 

required to compensate for nitrogen lost when stover is removed for ethanol production 

(discussed in more detail in DRIA Chapter 5). 

322 
Figure 2.6-4. 

Normalized Changes in Domestic Nitrogen Fertilizer Use, 2022 

(lbs per thousand ethanol equivalent gallons of biofuel) 

300 

Corn and Silage 

200 Soybeans 

100 60 68 57 Switchgrass 

0 Wheat 

Rice 

-100 

Sorghum 

-200 

Oats 

-300 -334 

Hay 

-400 

Cotton 

-500 Other Crops 

-600 Net Total 

Mechanized agriculture requires many forms of energy including diesel, gasoline, natural 

gas and electricity. The FASOM crop budgets include detailed energy use information by crop 

and region (See DRIA Chapter 5 for a full listing). Figure 2.6-5 includes FASOM assumptions 

for average diesel use by crop in 2022, for non-irrigated production without residue harvesting. Nitrogen Fertilizer Use (lbs per thousand etoh equiv. gallons) 

Corn Ethanol Soybean Biodiesel Corn Stover Ethanol Switchgrass Ethanol 

323 
 

Figure 2.6-5. 

FASOM Average Diesel Use by Crop, 2022 

Non-Irrigated, No Residue Harvesting 

(gallons per acre) 

0 

5 

10 

15 

20 

25 

Diesel Use (gal per acre) 

Corn Soybeans Switchgrass Wheat (hard Rice (irrigated) Sorghum Oats Hay Cotton 

red winter) 

Note: The range indicates the regions with the highest and lowest average diesel use rates. 

Figure 2.6-6 shows the change in domestic diesel use per thousand gallons of biofuel 

production. Comparing the relative diesel intensity of the crops shown in Figure 2.6-5 and the 

crop shifting patterns illustrated in 2.6-2, helps to explain the overall changes in diesel use in 

Figure 2.6-5. Diesel use increases in the corn ethanol and soy-based biodiesel scenarios as 

domestic crop acreage increases. Diesel use actually declines in the corn stover scenario, in part 

because corn farmers shift towards conservation tillage practices. Overall diesel use declines in 

switchgrass scenario, because switchgrass requires less diesel than the crops it displaces. 

324 
2.38 

0.65 

-2.96 

-5.19 

-6 

-5 

-4 

-3 

-2 

-1 

0 

1 

2 

3 

Diesel Use (gal per thousand gal) 

Figure 2.6-6. 

Normalized Changes in Domestic Agricultural Diesel Use, 2022 

(gallons of diesel per thousand ethanol equivalent gallons of biofuel) 

Corn Ethanol Soy-Based Biodiesel Corn Stover Ethanol Switchgrass Ethanol 

Figure 2.6-7 includes FASOM assumptions for average gasoline use by crop in 2022, for 

non-irrigated production without residue harvesting. The FASOM crop budgets do not include 

gasoline use for switchgrass production. Figure 2.6-8 shows the change in domestic gasoline use 

per thousand gallons of biofuel production. 

325 
Figure 2.6-7. 

FASOM Average Gasoline Use by Crop, 2022 

Non-Irrigated, No Residue Harvesting 

(gallons per acre) 

Corn Soybeans Switchgrass Wheat (hard Rice Sorghum Oats Hay Cotton 

red winter) (irrigated) 

Note: The range indicates the regions with the highest and lowest average gasoline use rates. 

0 

1 

2 

3 

4 

5 

Gasoline Use (gal per acre) 

326 
 

Figure 2.6-8. 

Normalized Changes in Domestic Agricultural Gasoline Use, 2022 

(gallons per thousand ethanol equivalent gallons of biofuel) 

-1.80 

1.04 

-0.29 

-1.73 

-2.0 

-1.5 

-1.0 

-0.5 

0.0 

0.5 

1.0 

1.5 

Gasoline Use (gal per thousand gal) 

Corn Ethanol Soy-Based Biodiesel Corn Stover Ethanol Switchgrass Ethanol 

FASOM crop budgets include electricity and natural gas use for irrigation water 

pumping. Rice and sugarbeets are the only crops assumed to use natural gas for water pumping 

(See Table 2.6-3). Therefore, overall natural gas use in each scenario is dependent on changes in 

these crops. For the rest of the irrigated crops that have private energy use for water pumping, 

electricity is the assumed energy source, with the largest electricity consumption in the Great 

Plains region (See Figure 2.6-10). 

Table 2.6-3. 

Natural Gas Usage by Crop, Irrigation Status and Region, 2022 

(1000 cu ft/acre) 

Crop CB GP LS NE PNWE PSW RM SC SE SW 

Irrigated 

Rice 23.3 NA NA NA NA 0.0 NA 20.1 NA 0.0 

Sugarbeet 26.1 9.7 26.1 NA 3.8 0.0 0.0 NA NA 0.0 

327 
Natural Gas Use (000 cu ft per 000 gal) 

0 

-1 

-2 

-3 

-4 

-5 

-6 

Figure 2.6-9. 

Normalized Change in Domestic Agricultural Natural Gas Use, 2022 

(thousand cubic feet per thousand ethanol equivalent gallons) 

Corn Ethanol Soy-Based Biodiesel Corn Stover Ethanol Switchgrass Ethanol 

Figure 2.6-10. 

FASOM Electricity Use by Crop, 2022 

Irrigated, No Residue Harvesting
 

(kWh per acre) 

0 

2 

4 

6 

8 

10 

12 

14 

Electricity Use (kWh per acre) 

Corn Soybeans Wheat, Hard Red Sorghum Oats Hay Cotton 

Winter 

Note: The range indicates the regions with the highest and lowest average gasoline use rates. 

328 
Figure 2.6-11. 

Normalized Change in Domestic Agricultural Electricity, 2022 

(kilowatt-hours per thousand ethanol equivalent gallons) 

0.27 

0.22 

-0.02 

-0.10 -0.08 

0.00 

0.10 

0.20 

0.30 

Electricity Use (kWh per thousand gal) 

Corn Ethanol Soy-Based Biodiesel Corn Stover Ethanol Switchgrass Ethanol 

Based on input data for each individual crop and the associated costs of production and 

projected prices, the model predicts how the total U.S. agricultural sector will change with 

increased feedstocks used for biofuel production. The results for total agricultural sector inputs 

of the different fuel scenarios considered are shown in Table 2.6-4 through Table 2.6-7. 

Table 2.6-4. 

Change in Domestic Agricultural Inputs from Corn Ethanol Production, 2022 

Units Corn Ethanol Only Case Control Case Difference 

Percent Change 

Total N use Tons 13,579,165 13,656,663 77,497 0.57% 

Total P2O5 use Tons 3,133,112 3,169,185 36,073 1.15% 

Total K2O use Tons 4,071,676 4,099,299 27,624 0.68% 

Total Lime Use Tons 11,010 11,017 6 0.06% 

Herbicide Use Tons 208,026 210,343 2,317 1.11% 

Pesticide Use Tons 41,232 41,168 -64 -0.15% 

Total Diesel Fuel use gal 2,741,271,104 2,747,445,994 6,174,890 0.23% 

Total Gasoline use gal 365,527,816 360,839,070 -4,688,746 -1.28% 

Total Electricity Use kWh 203,558,361 204,268,096 709,735 0.35% 

Total Natural Gas Use Btu 6.9E+13 6.5E+13 -3.6E+12 -5.22% 

329 
Table 2.6-5. 

Change in Domestic Agricultural Inputs from Soybean Biodiesel Production, 2022 

Units 

Soy-Based Biodiesel Only 

Case Control Case Difference 

Percent 

Change 

Total N use Tons 13,754,243 13,656,663 -97,581 -0.71% 

Total P2O5 use Tons 3,173,639 3,169,185 -4,454 -0.14% 

Total K2O use Tons 4,116,977 4,099,299 -17,678 -0.43% 

Total Lime Use Tons 11,056 11,017 -39 -0.35% 

Herbicide Use Tons 210,670 210,343 -328 -0.16% 

Pesticide Use Tons 41,551 41,168 -383 -0.92% 

Total Diesel Fuel use gal 2,747,066,027 2,747,445,994 379,967 0.01% 

Total Gasoline use gal 360,233,446 360,839,070 605,625 0.17% 

Total Electricity Use kWh 204,138,103 204,268,096 129,994 0.06% 

Total Natural Gas Use Btu 6.9E+13 6.5E+13 -3.5E+12 -5.15% 

Table 2.6-6. 

Change in Domestic Agricultural Inputs from Corn Stover Ethanol Production, 2022 

Units 

Corn Stover Only Ethanol 

Case Control Case Difference 

Percent 

Change 

Total N use Tons 13,398,157 13,656,663 258,506 1.93% 

Total P2O5 use Tons 3,040,127 3,169,185 129,057 4.25% 

Total K2O use Tons 3,461,168 4,099,299 638,131 18.44% 

Total Lime Use Tons 11,150 11,017 -134 -1.20% 

Herbicide Use Tons 209,968 210,343 375 0.18% 

Pesticide Use Tons 41,266 41,168 -97 -0.24% 

Total Diesel Fuel use gal 2,769,975,459 2,747,445,994 -22,529,464 -0.81% 

Total Gasoline use gal 363,019,719 360,839,070 -2,180,649 -0.60% 

Total Electricity Use kWh 204,417,097 204,268,096 -149,000 -0.07% 

Total Natural Gas Use Btu 6.6E+13 6.5E+13 -7.2E+11 -1.09% 

Table 2.6-7. 

Change in Domestic Agricultural Inputs from Switchgrass Ethanol Production, 2022 

Calc Units Control Case 

Switchgrass 

Ethanol Only Case Difference 

Difference as a % of 

Low Volume Case 

Total N use Tons 13,656,663 13,789,870 133,207 0.98% 

Total P2O5 use Tons 3,169,185 3,282,355 113,170 3.57% 

Total K2O use Tons 4,099,299 4,167,733 68,434 1.67% 

Total Lime Use Tons 11,017 10,525 -491 -4.46% 

Herbicide Use Tons 210,343 205,014 -5,329 -2.53% 

Pesticide Use Tons 41,168 39,478 -1,690 -4.11% 

Total Diesel Fuel use gal 2,747,445,994 2,723,351,266 -24,094,728 -0.88% 

Total Gasoline use gal 360,839,070 352,830,473 -8,008,597 -2.22% 

Total Electricity Use kWh 204,268,096 203,888,367 -379,729 -0.19% 

Total Natural Gas Use Btu 6.5E+13 6.1E+13 -3.9E+12 -5.96% 

330 
The amounts shown in Tables 2.6-4 through 2.6-7 were combined with GREET defaults 

for GHG emissions from production of fertilizer and chemicals to calculate GHG emissions 

changes. Fuel use emissions included both the upstream emissions associated with production of 

the fuel as well as combustion emissions, also from GREET. Emissions from electricity 

production represented average U.S. grid electricity production. 

In addition to the GHG emissions associated with fertilizer and chemical production, and 

fuel production and use, there are several other non-fossil fuel combustion related GHG sources 

of emissions from the agricultural sector that would be impacted by the increased use of corn for 

ethanol and associated changes to the agricultural sector. FASOM provides directly the GHG 

emissions from these additional sources. 

2.6.2.2 Domestic Nitrous Oxide Emissions 

An important GHG impact from the agricultural sector is releases of nitrous oxide (N2O) 

emissions. N2O can be released from a number of different N-input sources including inorganic 

fertilizer, nitrogen fixing crops (e.g., soybeans), crop residues, and manure management. N2O 

can be released either directly or indirectly through N leaching offsite. Figure 2.6-11 highlights 

some of the major sources of agricultural N2O emissions. 

Figure 2.6-11. Agricultural Sources of N2O Emissions 

This issue has become increasingly important in the context of biofuels production based 

on a recent paper by Paul Crutzen et al.523 The paper examines a top-down method for 

calculating N2O emissions and compares that to the standard IPCC bottom-up approach. The 

conclusion is that it is not appropriate to just consider the direct N2O releases but that all sources 

of N2O are important. The paper recognizes that top-down estimates are not necessarily 

inconsistent with IPCC’s bottom-up range when all direct and indirect agricultural sources are 

considered, highlighting the importance of “indirect” N2O emissions. 

331 
Therefore, for our modeling we capture all sources of N2O emissions shown in Figure 

2.6-4. This section discusses direct and indirect emissions from synthetic fertilizer, N fixing 

crops, and crop residue. Livestock and residue burning emissions are discussed in other sections, 

as are international N2O emissions. 

FASOM estimates direct and indirect emissions from synthetic fertilizer, N fixing crops, 

and crop residues based on the amount of fertilizer used and different regional factors to 

represent the percent of N applied that results in N2O emissions. This approach is consistent 

with IPCC guidelines for calculating N2O emissions from these sources. 

In order to have a better representation of the N2O emissions from agricultural 

production, EPA is working with Colorado State University (CSU) to use the DAYCENT model 

to update the N2O factors in the FASOM model. CSU will obtain initial projections of land use 

trends from FASOM to simulate a suite of domestic U.S. land use and crop management changes 

associated with potential biofuel production between 2007 and 2030. CSU will use the 

DAYCENT model to simulate direct N2O emissions in croplands as well as the N losses 

associated with leaching, volatilization and surface runoff and cropping pattern changes. 

Leaching, volatilization and surface runoff losses will be used to estimate the indirect N2O 

emissions with IPCC default factors. 

Separate DAYCENT simulations will be conducted for each of the 63 agricultural 

regions included in the FASOM analysis. In each region, DAYCENT will simulate land use 

conversions from grassland and forestland, as well as changes in existing cropping rotations that 

are needed to meet the biofuel market demand according to initial FASOM results. Several 

scenarios may be addressed in the analysis. 

Specifically, CSU will provide several key refinements for a re-analysis of land use, 

cropping trends and GHG emissions in the FASOM assessment, including: 

•	 Direct N2O emissions based on DAYCENT simulations with an accounting of all N 

inputs to agricultural soils, including mineral N fertilizer, organic amendments, symbiotic 

N fixation, asymbiotic N fixation, crop residue N, and mineralization of soil organic 

matter. CSU will provide the total emission rate on an acre basis for each simulated 

bioenergy crop in the 63 regions, and also a disaggregation by N source. 

•	 Indirect N2O emissions on a per acre basis using results from DAYCENT simulations of 

volatilization, leaching and runoff of N from each bioenergy crop included in the analysis 

for the 63 regions, combined with IPCC factors for the N2O emission associated with the 

simulated N losses. 

The analyses with updated N2O estimates are not yet complete, but we expect to 

incorporate updated emissions data into FASOM for future analyses. Below we describe the 

current procedures used in FASOM to generate estimates of N2O emissions. 

The primary categories of direct N2O emissions are nitrogen fertilizer and nitrogen-fixing 

crops. Changes in FASOM direct N2O emissions from croplands result from either changes in 

332 
crop acreage or crop mix. To calculate direct N2O emissions from N fertilizer use, FASOM uses 

data on N fertilizer application per acre from the crop budgets. This value varies widely across 

crops, regions, and crop management activities. Emissions from synthetic fertilizer, manure 

applied as fertilizer, and non-manure organic fertilizers are calculated based on IPCC guidance. 

N2O emissions are calculated similarly for organic fertilizers. In FASOM, the only N-fixing 

crops for which N2O emissions are calculated are soybeans and alfalfa hay. More details about 

current FASOM modeling of direct N2O emissions are available in DRIA Chapter 5. 

In addition to direct N2O emissions from croplands, there are several additional sources 

of indirect emissions, including emissions from volatilization, leaching, crop residues, and 

residue burning. Some of the N applied to agricultural soils as fertilizer volatilizes, entering the 

atmosphere as ammonia and other oxides of nitrogen. The volatilized N subsequently returns to 

soils through N deposition and then contributes to N2O emissions. After fertilizer application or 

heavy rain, large amounts of N may leach from the soil into drainage ditches, streams, rivers and 

eventually estuaries. Some of this N is emitted as nitrous oxide when the leached nitrogen 

fertilizer undergoes the process of nitrification or denitrification. There are also N2O emissions 

from crop residues that are incorporated into agricultural soils. Following IPCC guidance, N2O 

emissions are calculated as 1% of the N from crop residues that is incorporated into the soil. 

FASOM also assumes that a certain fraction of fields are burned each year, which results in N2O 

(and methane) emissions. These emissions are calculated using the IPCC default value, which 

assumes that on average 0.7% of N contained in the burned residue is emitted as N2O. In 

addition, methane emissions are calculated based on the average methane emissions per acre, but 

these emissions are typically quite small relative to the other emissions tracked in FASOM. All 

FASOM calculations of N2O emissions are based on IPCC guidance (See DRIA Chapter 5 for 

more details). Figure 2.6-12 summarizes FASOM average direct and indirect N2O emissions per 

acre by crop. 

333 
 

0 

100 

200 

300 

400 

500 

600 

700 

800 

N2O Emissions (kgCO2eq per acre) 

Figure 2.6-12. FASOM Average N2O Emissions by Crop 

Non-Irrigated, No Residue Harvesting 

(kgCO2-eq per acre) 

Indirect -- Residue Burning 

Indirect -- Crop Residues 

Indirect -- Leaching 

Indirect -- Volatilization 

Direct -- N Fixing 

Direct -- Fertilizer Application 

Corn Soybeans Switchgrass Wheat (hard Rice Sorghum Oats Hay Cotton 

red winter) (irrigated) 

Current N2O emission calculations from FASOM are from three main sources of 

emissions, fertilizer application (including direct emissions and indirect emissions from N 

leaching), Emissions from N fixing crops, and emissions associated with residues and N in the 

residue. Total N2O emissions for the different fuels analyzed are presented in Table 2.6-8. 

Table 2.6-8. Change in N2O Emissions in 2022 from Different Fuel Scenarios 

Source Units Corn 

Ethanol 

Only Case 

Soy-based 

Biodiesel 

Only Case 

Corn Stover 

Ethanol Only 

Case 

Switchgrass 

Ethanol Only Case 

N Fert Application ‘000 tons 

CO2-eq. 442 -524 1,562 848 

Emissions from N 

fixing crops 

‘000 tons 

CO2-eq. -1,157 899 130 -2,033 

Emissions from Crop 

residue 

‘000 tons 

CO2-eq. -218 279 -33 -809 

Domestic Net N2O 

Emissions 

‘000 tons 

CO2-eq. -933 654 1,659 -1,994 

The changes in N2O emissions from the different scenarios reflect the crop pattern, and 

management practice changes between the different fuel volumes considered. For example, 

increased corn ethanol production results in more corn and less soybean acres, this is reflected in 

more N2O emissions from increased nitrogen fertilizer and lower N2O emissions from N fixing 

crops. Switchgrass ethanol production results in similar land use changes and less N fixing 

crops. Soy-based biodiesel has the opposite effect, more soybean acres and less other crops. As 

discussed previously, these results do not consider any changes in crop inputs for example 

increased nitrogen fertilizer input to make up for lost soybean nitrogen fixing. 

334 
 

 

 

 

2.6.2.3 Domestic Emissions from Grain Drying 

Energy use for grain drying is calculated in FASOM based on assumptions that removing 

10 percentage points of moisture from 100 bushels of grain requires 17.5 gallons of propane and 

9 kWh of electricity. Thus, energy use per acre is calculated as the number of percentage points 

of moisture to be removed multiplied by the yield per acre and the energy use per percentage 

point and yield unit for each crop that is dried. Emissions are then calculated based on assumed 

emissions factors per unit of energy use by energy type. Table 2.6-9 shows the average 

emissions associated with grain drying that are used in FASOM. Drying rice is a relatively 

energy intensive process, as reflected in the grain drying GHG emissions per acre in Table 2.6-9. 

Emissions from grain drying are included in the overall domestic agricultural GHG emissions 

estimates. 

Table 2.6-9. FASOM Average Carbon Dioxide Emissions from Grain Drying by Region 

(kgCO2-eq. / acre) 

Crop CB GP LS NE PNWE PSW RM SC SE SW 

Dryland 

Corn 161.4 135.9 202.2 160.5 NA NA 66.1 24.5 43.8 15.2 

Sorghum 99.4 22.3 NA 54.3 NA 17.7 NA NA NA NA 

Soybeans 26.0 7.0 24.1 14.3 NA NA NA NA NA NA 

Wheat, Durham NA 5.1 23.4 NA NA NA NA NA NA NA 

Wheat, Hard Red Spring NA 6.7 25.4 NA 9.1 NA NA NA NA NA 

Wheat, Hard Red Winter 51.3 11.1 51.6 34.5 NA 11.6 NA NA NA NA 

Wheat, Soft White NA NA NA NA NA NA 11.6 NA NA NA 

Irrigated 

Corn NA 185.1 NA NA 132.6 121.6 103.2 21.0 NA 30.7 

Rice 1,216.6 NA NA NA NA 1,667.3 NA 1,254.8 NA 1,400.8 

Sorghum NA 33.0 NA NA NA NA NA NA NA NA 

Soybeans NA 10.3 NA NA NA NA NA NA NA NA 

Wheat, Durham NA 11.3 NA NA NA 21.0 NA NA NA NA 

Wheat, Hard Red Spring NA 10.2 NA NA NA NA 17.6 NA NA NA 

Wheat, Hard Red Winter NA 15.4 NA NA NA 22.6 NA NA NA NA 

Wheat, Soft White NA NA NA NA NA NA 18.3 NA NA NA 

2.6.2.4 Domestic Rice Production Emissions 

Another source of non-combustion GHG emissions from the agricultural sector is CH4 

emissions from rice production. Most of the world’s rice, and all rice in the United States, is 

grown on flooded fields. When fields are flooded, aerobic decomposition of organic material 

gradually depletes most of the oxygen present in the soil, causing anaerobic soil conditions. 

Once the environment becomes anaerobic, CH4 is produced through anaerobic decomposition of 

335 
 

 

 

soil organic matter by methanogenic bacteria. Some of this CH4 is transported from the 

submerged soil to the atmosphere primarily by diffusive transport through the rice plants. Minor 

amounts of CH4 also escape from the soil via diffusion and bubbling through floodwaters. 

FASOM assumes that all rice produced in the United States is grown in flooded fields 

and has associated methane emissions. Although there are potentially changes in water and soil 

management practices that could be implemented to reduce methane emissions, FASOM 

currently assumes that the only method available for reducing methane emissions from rice 

cultivation is to reduce rice acreage. Thus, changes in methane emissions from rice cultivation 

will result only from changes in the acreage planted to rice. 

Methane emissions per acre are calculated based on regional emissions factors per acre 

calculated for each region based on 2001 data from the EPA GHG inventory for 1990–2003 (see 

Table 2.6-10).524 The model then calculates emissions from rice production based on emissions 

factors for each region and the distribution of rice acreage in the model solution. 

Table 2.6-10. FASOM Average Methane Emissions from Rice Cultivation by 

Region (kg CO2-eq. / acre) 

Crop CB GP LS NE PNWE PSW RM SC SE SW 

Irrigated 

Rice 1,826.1 NA NA NA NA 1,783.4 NA 2,249.2 NA 4,375.0 

Note: NA indicates not applicable, i.e., those crops were not cultivated under that irrigation status in that FASOM 

region. In addition, there is no dryland rice or sugarcane production or irrigated hybrid poplar, switchgrass, or 

willow production in FASOM. 

As with other sources of emissions different management methods and other factors 

(such as soil type and amounts of fertilization) will impact CH4 emissions from rice production. 

Rice methane emissions are projected to decrease due to a decrease in rice acres as shown in 

Table 2.6-11. 

Table 2.6-11. 

Percent Change in Domestic Rice Emissions in 2022 from Different Fuel Scenarios 

Corn 

Ethanol 

Soybean 

Biodiesel 

Corn Stover 

Ethanol 

Switchgrass 

Ethanol 

Rice Methane Emissions 

(‘000 tons CO2-eq.) -352 -355 -38 -457 

2.6.2.5 Domestic Residue Burning Emissions 

An additional minor source of GHG emissions from agricultural residue burning is also 

included in this analysis. Field burning of crop residues is not considered a net source of CO2, 

because the carbon released to the atmosphere as CO2 during burning is assumed to be 

reabsorbed during the next growing season. Crop residue burning is, however, a net source of 

CH4 and N2O, which are released during combustion. Field burning is not a common method of 

agricultural residue disposal in the United States. The primary crop types whose residues are 

typically burned in the United States are wheat, rice, sugarcane, corn, barley, soybeans, and 

336 
peanuts. FASOM is predicting a minor reduction in GHG emissions from residue burning due to 

reductions in crop production with residues that are typically burned. Non-CO2 residue burning 

emissions factors by crop and region are included in DRIA Chapter 5. 

2.6.2.3 Domestic Livestock Emissions 

Livestock production and management also contribute significant non-combustion GHG 

emissions from the agricultural sector. GHG emissions from livestock come from two main 

sources: enteric fermentation and manure management. Enteric fermentation produces CH4 

emissions as part of the normal digestive processes in animals. During digestion, microbes 

resident in an animal’s digestive system ferment food consumed by the animal. This microbial 

fermentation process, referred to as enteric fermentation, produces CH4 as a by-product. The 

amount of CH4 produced and excreted by an individual animal depends primarily upon the 

animal’s digestive system, and the amount and type of feed it consumes. Ruminant animals 

(e.g., cattle, buffalo, sheep, goats, and camels) are the major emitters of CH4 because of their 

unique digestive system. 

The FASOM modeling reflects changes in livestock enteric fermentation emissions due 

to changes in livestock herds. For example, as more corn is used in producing ethanol the price 

of corn increases, driving changes in livestock production costs and demand. Enteric 

fermentation emissions from livestock are calculated based on the number of animals of each 

type and a calculated value of average emissions per head based on the 2001 emissions values by 

livestock type and the number of livestock in each livestock category reported in the EPA GHG 

inventory report for 1990–2003.525 Average emissions per head of livestock are listed in DRIA 

Chapter 5. There are emissions mitigation options included within the FASOM model, but these 

options do not enter the market in the absence of incentives for reducing CH4 emissions. Thus, 

similar to the case of manure management, emissions from this source are currently affected only 

by the number of animals in each livestock category. The FASOM model predicts reductions in 

livestock herds as shown in Table 2.6-12. 

Table 2.6-12. Percent Change in Domestic Livestock Herd by Scenario, 2022 

Livestock Type Corn Ethanol Soy-based Biodiesel Corn Stover 

Ethanol 

Switchgrass 

Ethanol 

Dairy -0.52% 0.04% 0.03% -0.81% 

Beef -0.48% -0.23% -0.10% -0.48% 

Poultry -0.16% 0.00% 0.00% -0.98% 

Swine -1.63% -0.15% -0.26% -1.04% 

Enteric fermentation emissions are impacted by type and quality of feed. As described in 

DRIA Chapter 5, the mix of feed types used will change based on the increased use of corn in 

ethanol and changes to corn prices. This change in feed type is not reflected in enteric 

fermentation emissions shown here. The direction of this change would be likely be additional 

reductions in enteric fermentation emissions due to the fact that use of ethanol co-products 

DDGS as feed have been found to reduce enteric fermentation emissions. We plan to include 

these CH4 reductions as part of the final rule analysis. 

337 
The management of livestock manure can produce anthropogenic CH4 and N2O 

emissions. CH4 is produced by the anaerobic decomposition of manure. N2O is produced as part 

of the nitrogen cycle through the nitrification and denitrification of the organic nitrogen in 

livestock manure and urine. The type of manure management methods will impact the amount 

of GHG emissions produced. FASOM calculates these manure management emissions based on 

for emissions factors from the different types of livestock and management methods as reported 

in the EPA GHG inventory report for 1990–2003.526. Manure management emissions are 

projected to be reduced as a result of lower livestock herd values. 

2.6.2.6 Domestic Agriculture Sector Results (Excluding Land Use Change) 

Table 2.6-13 provides an overview of the total GHG emissions impacts from the 

domestic agricultural sector based on the results of the FASOM modeling in terms of absolute 

changes between the GHG emissions from the different volume scenarios considered. Results 

are also presented on a per mmBtu basis by dividing total GHG changes by the mmBtu change in 

volume of biofuel produced between the different scenarios. Land use change impacts are 

discussed in Section 2.6.5. 

Table 2.6-13. 

Domestic Agriculture GHG Emission Changes by Scenario, 2022 

Corn Ethanol Soy-Based Biodiesel Corn Stover Ethanol Switchgrass Ethanol 

Emission Source 

Tonnes 

CO2-eq. 

g/MMBtu 

CO2-eq. 

Tonnes 

CO2-eq. 

g/MMBtu 

CO2-eq. 

Tonnes 

CO2-eq. 

g/MMBtu 

CO2-eq. 

Tonnes 

CO2-eq. 

g/MMBtu 

CO2-eq. 

On-Farm Combustion -218,314 -1,105 -228,655 -5,147 -299,049 -518 -578,771 -1,641 

Fuel Production Upstream -29,726 -151 -31,032 -698 -62,305 -108 -108,720 -308 

Farm Chemical Production / 

Transport Upstream 305,681 1,548 -296,291 -6,669 1,228,269 2,127 369,162 1,047 

Livestock Change -1,061,886 -5,377 -181,679 -4,089 -90,825 -157 -1,047,699 -2,970 

Rice Production Changes -352,374 -1,784 -354,897 -7,988 -37,899 -66 -456,840 -1,295 

Fertilizer Application / 

Soil N2O Emissions -933,136 -4,725 654,440 14,730 1,658,579 2,872 -1,994,025 -5,653 

Residue Burning 3,127 16 1,851 42 326 1 -34,647 -98 

Total: -2,286,628 -11,579 -436,263 -9,820 2,397,095 4,150 -3,851,541 -10,920 

As can be see in Table 2.6-13, the net GHG impact of increased biofuel production on the 

U.S. agriculture sector is in general a reduction in GHG emissions. This is driven primarily by 

indirect or secondary impacts such as decreases in energy use from crop shifting and reductions 

in livestock GHG emissions due to higher corn prices. The exception for this reduction is the 

corn stover ethanol case that shows an increase in domestic agricultural sector GHG emissions. 

This is mainly due to the fact that the corn stover case includes energy use for residue harvesting 

and transport, and, because the use of stover for ethanol does not increase feed or food prices, 

less indirect impacts in comparison with other feedstocks. 

Overall the small impact in the domestic agricultural sector is due to the indirect effects 

and demand changes, specifically demand changes in U.S. exports. For example, the sources of 

corn used in ethanol production in the FASOM model are shown in Figure 2.6-13. Some of the 

additional corn comes from increased corn production; however, the increase in corn acres is 

338 
mostly offset by reductions in other crop acres as shown in figure 2.6-2. Some of the corn used 

for ethanol comes from decreased corn used for feed. As ethanol produces the co-product DDG, 

this partially offsets the use of corn directly as feed. The reduction in livestock herds also lowers 

the use of corn for feed. 

Figure 2.6-13. Source of Corn for Ethanol 

0% 

10% 

20% 

30% 

40% 

50% 

60% 

70% 

80% 

90% 

100% 

Source for Change in Corn Usage in 2022 

Other Use 

Corn in Feed 

Corn Exports 

Corn Production 

1 

However, as seen from Figure 2.6-13, one of the biggest sources of corn for ethanol 

production is projected to come from reductions in corn exports. Therefore, the domestic 

agricultural sector impacts are only a portion of the total impacts due to increased ethanol 

production in the U.S. The change in corn and other crop exports will have impacts on the 

international agricultural sector that need to be accounted for when determining lifecycle GHG 

impacts of biofuel production in the U.S. 

2.6.3 Export Comparison between FASOM and FAPRI 

In order to estimate the impact on international agricultural sector GHG emissions the 

FAPRI model was run with domestic biofuel volume scenarios similar to the analysis conducted 

with FASOM. The model provided changes in international production of corn, soybeans, and 

other crops to replace lost U.S. exports. 

339 
The impact on the international agricultural sector is highly dependent on the U.S. export 

assumptions. As we are using the FASOM model to represent domestic agricultural sector 

impacts with an assumed export picture, the international agricultural sector impacts should be 

based on a consistent set of export assumptions. Therefore we worked with both models to build 

in a consistent set of assumptions in order to have an equivalent basis for modeling domestic and 

international impacts. 

One of the key differences we worked to reconcile was based on the different time frames 

considered in the models. FASOM is a long term econometric model, while FAPRI captures 

more short term impacts. Therefore, we worked to put some of the supply and demand 

elasticities on a more consistent basis, specifically the export response and livestock demand and 

feed use. We also coordinated on some of the key input assumptions in the two models as 

follows: 

•	 Current crop yields and projected increases for corn and soybeans based on 

USDA baseline projections. These drive the amount of land required and price 

and demand response of the different commodities in the different fuel scenarios. 

•	 Ethanol yield and co-product use values, this impacts how much commodity is 

needed to produce a certain quantity of fuel as well as how co-products help to 

offset feed use and overall change in crop and livestock production. 

•	 Reversion of CRP acres was limited such that 32 mill acres would remain in CRP. 

We also worked to have consistent set of assumptions for when and where CRP 

acres would be used across both models. 

As a result, the total changes in projected export impacts shown in Figure 2.6-14 are 

relatively consistent across both models with the possible exception of impacts related to 

increased biodiesel production. 

340 
 

Figure 2.6-14. 

Comparison of FASOM and FAPRI Projected Change in U.S. Exports by Scenario, 2022 

(tons per million ethanol equivalent gallons) 

Change in U.S. Exports per Million Gallons of Biofuel 

-14000 

-12000 

-10000 

-8000 

-6000 

-4000 

-2000 

0 

2000 

4000 

6000 

8000 

FASOM FAPRI FASOM FAPRI FASOM FAPRI FASOM 

Switchgrass Ethanol Corn Ethanol Biodiesel (Ethanol Equivalent) 

Corn Residue 

Ethanol 

Tons per Million Gallons of Ethanol

Soybeans 

SoybeanOil 

SoybeanMeal 

Sorghum 

Rice 

Wheat 

Cotton 

Corn 

Barley 

The differences in switchgrass exports are primarily driven by how the different models 

have considered switchgrass acres. Currently, FAPRI does not specifically model cellulosic 

ethanol feedstocks, so CRP land was used as a proxy for switchgrass acres. FASOM specifically 

models switchgrass and how it competes for land with other crops. Therefore, FAPRI domestic 

crop competition and associated export changes are not as large as those predicted in FASOM. 

Compared to other crops, FASOM and FAPRI differ more in their predicted impact on 

soybean export volumes. FASOM assumes more biodiesel will come from new soybean acres 

(but total domestic acres are relatively constant as other crops offset the increase in soybean 

acres). In comparison, FAPRI contains more types of oil, and has a more elastic demand in the 

soybean oil market. In addition, the FAPRI model allows for some corn oil fractionation from 

DDGs, which can be used as a substitute for soybean oil. 

For the analysis conduced and presented here we have used both the FASOM and FAPRI 

results as-is with no adjustments. Because the impact on international land use could be 

significantly different if we had used the FASOM export prediction rather than the FAPRI 

prediction, we intend to further refine the models with the goal of having export response more 

closely aligned for the final rule. 

341 
As the corn residue ethanol production has negligible export change impacts, it is 

assumed that there are no international emissions impacts associated with increased corn stover 

ethanol production in the U.S. However, we have modeled the impact of increased production of 

Brazilian sugarcane ethanol for use in the U.S. market. The FAPRI model has been used to 

determine the international impacts of Brazilian sugarcane ethanol production. The increase in 

Brazilian sugarcane ethanol production is assumed to have no impacts on domestic U.S. 

agriculture emissions. 

2.6.4 International Agriculture 

For this analysis we used the FAPRI model to estimate the impacts on international crop 

production due to changes in biofuel production. These results were used to generate GHG 

emissions from the international agricultural sector, similar to what was done to determine 

domestic agricultural GHG emission changes. 

2.6.4.1 International Crop Input and GHG Impacts 

The FAPRI model does not directly provide an assessment of the GHG impacts of 

changes in international agricultural practices (e.g., changes in fertilizer load and energy use). 

However, it does predict changes in crop area and production by crop type and country. We, 

therefore, determined international fertilizer and energy use based on data collected by the Food 

and Agriculture Organization (FAO) of the United Nations and the International Energy Agency 

(IEA). 

We took the FAPRI provided activity data on changes in crop acres, by crop and country, 

and multiplied by regional fertilizer use rate factors (tons per acre) to determine the global 

impacts of biofuel production on fertilizer application. Fertilizer data was taken from the Food 

and Agricultural Organization's Fertistat database, which reports fertilizer use by crop and 

country for a single year between 1988 and 2004.527 Herbicide and pesticide use data was 

calculated in the same manner. We then used GREET factors for emissions from production of 

agricultural chemicals to estimate the upstream GHG impacts of fertilizer and chemical 

production to calculate total impacts for each fuel scenario. Table 2.6-14 provides the total 

change in fertilizer and chemical use for the different fuel scenarios. 

Table 2.6-14. 

International Change in Fertilizer and Chemical Use by Scenario, 2022 

(tons) 

Input Corn 

Ethanol 

Only Case 

Soy-Based 

Biodiesel 

Only Case 

Switchgrass Ethanol Only 

Case 

Sugarcane Ethanol Only 

Case 

N Application 80,492 3,627 18,167 134,842 

P Application 47,663 9,495 12,774 112,862 

K Application 38,606 8,640 7,549 155,311 

Herbicide Application 230 57 72 524 

Pesticide Application 382 58 111 663 

Foreign agricultural energy use was calculated slightly differently. We collected data 

from IEA on total CO2 emissions from agricultural fuel combustion by country.528 We also 

342 
collected IEA data on agricultural electricity and fuel use by country, which was combined with 

emissions factors to estimate country-level GHG emissions from agricultural electricity and fuel 

use. Historical trends were used to project chemical and energy use in 2022. These total GHG 

emissions were only combustion related, so we scaled them to represent full lifecycle GHG 

emissions from fuel production, based on the ratio of combustion to full lifecycle GHG 

emissions from U.S. fuel and electricity use. Country-level GHG emissions from agricultural 

energy use were then divided by the area of agricultural land in each country, from the 

FAOSTAT land area database to derive a per acre GHG emissions factor from agricultural 

energy use by country. Our estimates use average energy consumption and GHG emissions per 

acre for all crops in each foreign country. We multiplied these agricultural energy consumption 

emissions factors by the country-level crop acreage changes projected by FAPRI to determine 

the change in GHG emissions from foreign agricultural energy use for each fuel scenario. Table 

2.6-15 provides the total change in agricultural energy use GHG emissions for the different fuel 

scenarios. EPA is organizing external expert review of these calculations to be done before the 

final rule. Part of this review will be to look at how energy and fertilizer use will change as crop 

yields change. 

Table 2.6-15. 

International Change in Agricultural Energy Use GHG Emissions by Scenario, 2022 

(MTCO2-eq.) 

Corn 

Ethanol 

Soybean 

Biodiesel 

Switchgrass 

Ethanol 

Brazilian Sugarcane 

Ethanol 

Agricultural Sector 

Energy Use GHG 

Emissions 

618,311 109,552 205,926 338,743 

2.6.4.2 International N2O Emissions 

For international N2O emissions we considered both direct and indirect emissions from 

synthetic fertilizer application, crop residue N, and manure management. Manure management 

emissions are discussed in the following section. Direct and indirect emissions from synthetic 

fertilizer application and crop residues were calculated based on IPCC guidance as shown in 

Table 2.6-16.529 

343 
 

 

 

 

 

Table 2.6-16. Calculations of N2O Emissions from Synthetic Fertilizer and Crop Residues 

Direct N2O Emissions 

Direct Emissions (Overall Equation) Equation 

(N additions to soils from mineral fertilizer + N 

 Emissions = additions to soils from crop residues) × EF 

EF for N additions from mineral fertilizer and crop 

residues = 0.01 kg N2O-N / kg N added 

N Additions from Mineral Fertilizers 

kg fertilizer N applied to soils (i.e., change in 

N additions to soils from mineral fertilizers = fertilizer N applications from Table 2.6-9) 

N Additions from Crop Residues 

above-ground residue dry matter × Crop Area × 

[N content of aboveground residues + ratio of 

belowground residues to harvested yield for crop 

N additions to soils from crop residues = × N content of belowground residues] 

where, 

Above-ground residue dry matter and N additions 

to soils from crop residues = Taken from IPCC default values by crop
 

Indirect N2O Emissions 

Note that for indirect emissions, the calculation of N applied to soils from fertilizers or crop residues is the same 

as for direct emissions 

Indirect Emissions from Volatilization Equation 

N additions to soils from mineral fertilizers × N lost 

 Emissions = through volatilization × EF 

N lost (from synthetic fertilizer additions) through 

volatilization = 0.1 (kg NH3–N + NOx–N) / kg N applied 

0.010 kg N2O–N / (kg NH3–N + NOX–N
 

EF for N lost through volatilization = volatilised) 

Indirect Emissions from Leaching/Runoff Equation 

(N additions to soils from mineral fertilizers + N 

additions to soils from crop residues) × N lost 

 Emissions = through leaching or runoff × EF 

N lost through leaching/runoff (from all N sources) = 0.3 N losses by leaching or runoff / kg N addition 

EF for N lost through leaching/runoff = 0.0075 kg N20-N / kg N leaching or runoff 

Based on the equations in Table 2.6-16 and the crop production changes projected by 

FAPRI, we estimated the total change in N2O emissions for each fuel scenarios, as shown in 

Table 2.6-17. As noted above, we are also working with Colorado State University to update 

these factors as part of the final rule analysis. 

Table 2.6-17. 

International Change in N2O Emissions in 2022 from Different Fuel Scenarios 

(total metric tons N2O) 

Corn 

Ethanol 

Soybean 

Biodiesel 

Switchgrass 

Ethanol 

Brazilian Sugarcane 

Etanol 

Direct and Indirect 

N2O Emissions 1,901 104 446 2,642 

344 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2.6.4.4 International Livestock Change GHG Impacts 

Similar to domestic livestock impacts associated with an increase in biofuel production, 

internationally the FAPRI model predicts changes in livestock production due to changes in feed 

prices. The GHG impacts of these livestock changes, enteric fermentation and manure 

management GHG emissions, were included in our analysis. Unlike FASOM, the FAPRI model 

does not have GHG emissions built in and, therefore, livestock GHG impacts were based on 

activity data provided by the FAPRI model (e.g., number and type of livestock by country) 

multiplied by IPCC default factors for GHG emissions. Table 2.6-18 shows the changes in 

livestock predicted by the FAPRI model in 2022 for each of the fuel scenarios considered. 

Table 2.6-18. 

Foreign Livestock Changes by Region and Renewable Fuel, 2022 

(head per million gallons) 

Corn Ethanol Dairy Cattle Hog Sheep Poultry 

North America (Canada) -1.1 23.4 -117.7 0.0 268.0 

Western Europe -0.4 -11.0 -3.8 0.0 280.7 

Eastern Europe 0.0 7.0 -19.7 0.0 1349.7 

Oceania 1.4 75.0 -1.6 13.5 513.3 

Latin America -40.2 -144.4 13.8 0.0 792.8 

Asia -17.8 368.8 -27.8 -268.6 565.0 

Africa and Middle East -82.2 -14.3 0.0 0.0 -119.4 

Indian Subcontinent 0.0 -11.9 0.0 0.0 10.0 

Total -140.3 292.6 -156.9 -255.1 3660.2 

Soy-Based Biodiesel Dairy Cattle Hog Sheep Poultry 

North America (Canada) 0.3 1.3 64.2 0.0 -130.6 

Western Europe -0.2 16.5 -26.9 0.0 504.8 

Eastern Europe 0.0 -1.5 8.5 0.0 -1017.0 

Oceania 0.2 -4.7 -2.4 -37.9 -631.0 

Latin America -4.1 -66.9 10.5 0.0 -4131.9 

Asia 11.4 -27.4 27.4 137.7 -696.5 

Africa and Middle East -12.0 6.4 0.0 0.0 -51.6 

Indian Subcontinent 0.0 4.8 0.0 0.0 -625.7 

Total -4.3 -71.4 81.3 99.8 -6779.6 

Sugarcane Ethanol Dairy Cattle Hog Sheep Poultry 

North America (Canada) -0.2 2.7 -32.2 0.0 81.8 

Western Europe -0.1 -2.1 -0.6 0.0 90.1 

Eastern Europe 0.0 1.7 -8.3 0.0 417.5 

Oceania 0.2 -4.7 0.2 1.8 26.7 

Latin America -10.1 -40.7 -3.7 0.0 -1889.6 

Asia -3.8 -32.2 -31.1 -66.7 -136.8 

Africa and Middle East -13.0 0.0 0.0 0.0 4.4 

Indian Subcontinent 0.0 26.3 0.0 0.0 -172.8 

Total -27.0 -48.9 -75.8 -64.9 -1578.7 

Switchgrass Ethanol Dairy Cattle Hog Sheep Poultry 

North America (Canada) 0.4 -2.7 37.3 0.0 -99.0 

Western Europe 0.1 3.4 0.0 0.0 -57.8 

Eastern Europe 0.0 -2.4 10.2 0.0 -435.4 

345 
 

 

Oceania -0.5 -11.1 0.4 -3.1 -108.6 

Latin America 10.4 31.0 4.6 0.0 -81.9 

Asia 6.7 1742.5 124.9 91.6 182.2 

Africa and Middle East 21.4 2.3 0.0 0.0 90.1 

Indian Subcontinent 0.0 5.5 0.0 0.0 12.0 

Total 38.5 1768.5 177.3 88.5 -498.4 

The enteric fermentation GHG impacts of livestock changes were calculated by applying 

regional default factors for enteric fermentation CH4 emissions by livestock type. These factors 

are shown in Table 2.6-19. 

Table 2.6-19. Enteric Fermentation Emission Factors 

Enteric Fermentation 

(kg CH4/head/year) Dairy Cattle Swine Sheep 

North America 121 53 1.5 8 

Western Europe 109 57 1.5 8 

Eastern Europe 89 58 1.5 8 

Oceania 81 60 1 5 

Latin America 63 56 1 5 

Asia 61 47 1 5 

Africa and Middle East 40 31 1 5 

Indian Subcontinent 51 27 1 5 

Manure management GHG impacts of livestock changes for each fuel scenario were 

calculated by applying regional default factors for manure management CH4 and N2O emissions 

by livestock type. Manure management CH4 emission factors are shown in Table 2.6-20. 

Manure management N2O values were based on default IPCC nitrogen produced per livestock 

type and IPCC default manure management practices by region. 

Table 2.6-20. Manure Management Methane Emission Factors 

Manure Management (kg 

CH4/head - year) Dairy Cattle Swine Sheep Poultry 

North America 78 2 23.5 0.28 0.02 

Western Europe 51 15 15.5 0.28 0.02 

Eastern Europe 27 13 6.5 0.28 0.02 

Oceania 29 2 18 0.15 0.02 

Latin America 1 1 1 0.15 0.02 

Asia 18 1 4 0.15 0.02 

Africa and Middle East 1.5 1 2 0.15 0.02 

Indian Subcontinent 5 2 4 0.15 0.02 

2.6.4.5 International Rice Production GHG Impacts 

To estimate rice emission impacts internationally, we used the FAPRI model to predict 

changes in international rice production as a result of the increase in biofuels demand in the U.S. 

346 
Since FAPRI does not have GHG emissions factors built into the model, we applied IPCC 

default factors by country. 

Calculating emissions from rice cultivation, per the IPCC 2006 guidelines, requires the 

following data: area of rice harvested, an emissions factor, and planting to harvesting season 

length. Area of rice harvested by country was provided by the FAPRI results. The default IPCC 

emission factors were used scaled for each cropping regime: irrigated, rainfed lowland, upland 

and deepwater by country. Rice cultivation season lengths were available from the International 

Rice Research Institute (IRRI).530 

2.6.4.6 International Crop Residue Burning 

International crop residue burning, and specifically changes in residue burning emissions 

from changes in U.S. biofuel policy, were not specifically included in this analysis. We did 

incorporate emissions from land clearing for crop production as discussed in Section 2.6.5. 

Changes in crop production and acres by country could lead to some changes in international 

residue burning emissions and we will examine methods of incorporating these impacts for the 

final rule. 

2.6.4.7 International Agriculture Sector Results (excluding land use change) 

Table 2.6-19 provides an overview of the total GHG emissions impacts from the 

international agricultural sector based on the results of the FAPRI modeling in terms of absolute 

changes between the GHG emissions from the different volume scenarios considered. Results 

are also presented on a per mmBtu basis by dividing total GHG changes by the mmBtu change in 

volume of biofuel produced between the different scenarios. Land use change impacts are 

discussed in Section 2.6.5. 

347 
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348 
349 

Table 2.6-21. 

Foreign Agriculture GHG Emission Changes in 2022 from Different Fuel Scenarios 

Corn Ethanol Soybean Biodiesel Switchgrass Ethanol 

Braz

Emission Source 

Tonnes 

CO2-eq. 

g/MMBtu 

CO2-eq. 

Tonnes 

CO2-eq. 

g/MMBtu 

CO2-eq. 

Tonnes 

CO2-eq. 

g/MMBtu 

CO2-eq. 

Tonn

CO2-

Farm Energy Use Emissions 618,311 3,131 109,552 3,064 205,926 842 338,74

Farm Chemical Production / Transport Upstream Emissions 

301,148 1,525 26,567 743 70,073 287 595,07

Livestock Changes GHG Emissions 210,309 1,065 -75,984 -2,125 2,666,036 10,906 -189,2

Rice Production GHG Emissions 365,322 1,850 69,645 1,948 228,504 935 134,86

Fertilizer / Soil N2O Emissions 589,342 2,984 32,256 902 138,339 566 819,09

Total: 2,084,432 10,555 162,036 4,532 3,308,879 13,536 1,698,5
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350 
351 

 

2.6.5 Land Use Change GHG Impacts 

Our lifecycle GHG estimates include emissions from domestic and international land use 

changes induced by increased renewable fuels consumption in the U.S. To estimate land use 

change GHG emissions we had to answer five key questions: 

1. How much land is converted? 

2. Where does land use change occur? 

3. What types of land are converted? 

4. What are the GHG emissions from that land conversion? 

5. How do we account for the variable timing of land use change GHG releases? 

This section describes our approach for answering these questions about land use change. 

We used FASOM to predict the total amount of cropland expansion in the U.S. FASOM was 

designed to simulate land use interactions to predict the types of land converted in the U.S. We 

used the FAPRI model to project international cropland expansion in response to increased U.S. 

biofuel consumption. The FAPRI model projects the area and amount of additional crop 

production, both by crop and country. FAPRI does not, however, project which types of land 

would be cleared to make room for additional cropland, or where within in each country or 

region cropland expansion would likely take place. To fill this information gap we used MODIS 

satellite data provided by Winrock International Incorporated (from now on referred to as 

Winrock), that shows recent trends in land use change from 2001 to 2004. To determine the 

GHG impacts of the projected land use changes we applied GHG emissions factors prepared by 

Winrock. We then used a net present value of GHG emissions to account for the variable time 

profile of land use change emissions. 

2.6.5.1 How Much Land Is Converted 

The main question regarding the amount of new land needed to meet an increasing 

demand for biofuels hinges on assumptions about the intensification of existing production 

versus expansion of production to other lands. This interaction is driven by the relative costs and 

returns associated with each option, but there are other factors as described in the following 

sections. 

2.6.5.1.1 Co-Product Use 

One factor determining the amount of new crop acres required under an increased biofuel 

scenario is the treatment of co-products. For example, distillers grains (DGs) are the major coproduct of dry mill ethanol production that is also used as animal feed. Therefore, using the DGs 

as an animal feed to replace the use of corn tends to offset the loss of corn to ethanol production, 

and reduces the need to grow additional corn to feed animals. Along with the recent growth in 

corn ethanol production has been an expansion in the handling and use of DGs. FASOM and 

FAPRI use data about recent DGs usage to predict how DGs will affect agricultural markets as 

corn ethanol production expands even further, but there is still some uncertainty about how these 

co-products will be used in the future (e.g., whether it can be reformulated for higher 
 

incorporation into pork and poultry diets, whether it will be dried and shipped long distances, 

whether fractionation will become widespread). 

Both our FASOM and FAPRI models account for the use of DGs in the agricultural 

sector. The FASOM and FAPRI models both assume that a pound of co-product would displace 

roughly a pound of feed. DG replacement is driven by how much DG can be included in animal 

feed, this so called inclusion rate differs by type of animal. The inclusion rate in turn impacts 

what percent of the DG produced will be used in which animal feed market. Finally the DG will 

substitute for different alternative feed products in different animal diets. 

USDA reports that typical inclusion rates are 30-40 percent for beef cattle, 20-25 percent 

for dairy, 20 percent for hogs and 15 percent for poultry.531 Furthermore, the same report 

indicates that a pound of DG will replace a pound of corn in beef rations, 0.45 pounds of corn in 

dairy rations, 0.85 pounds of corn in hog rations and 0.55 pounds of corn in poultry rations, with 

the remainder replacing soybean meal. Based on these assumptions and also that the majority of 

DG is used in the beef cattle market, FASOM assumes that one pound of DG will offset 0.9 

pounds of corn and 0.1 pound of soybean meal. 

The FAPRI model uses a slightly different set of assumptions for DG inclusion rates.532 

Beef cattle feed ration has the highest inclusion rate at 41% to 50%, the maximum inclusion rate 

for dairy follows at 26% to 30%, for hogs 20%, and for poultry 20%. Furthermore FAPRI 

assumes that DG will replace corn in beef and dairy cattle rations at 0.97 pound per pound, 

followed by pork at 0.89 pound per pound, and then poultry at 0.79 pound per pound. 

Displacement of soybean meal as a source of protein is 0.03 pound per pound of DG for beef and 

dairy cattle, 0.11 for pork, and 0.21 for poultry. FAPRI accounts for DG exports so that not all 

of the DG produced in the domestic ethanol market is used in the U.S. animal feed sector. Of the 

amount that is used in the U.S., FAPRI assumes that the use of DG in animal feed is highest in 

the beef cattle sector (61% share), followed by the dairy sector (21%), and then pork (9%) and 

poultry (9%) sectors. Based on all these assumptions, FAPRI calculates that a pound of DG 

replaces 0.95 pounds of corn and 0.05 pounds of soybean meal. 

A recent paper by Argonne National Laboratory533 estimates that 1 pound of DGs can 

displace more then a pound of feed due to the higher nutritional value of DGs compared to corn. 

However, the Argonne replacement ratios do not take into account the dynamic least cost feed 

decisions faced by livestock producers. The actual use of DGs will depend on the maximum 

inclusion rates for each type of animal (based on the digestibility of DGs), the displacement ratio 

for each type of animal (based on DGs energy and protein content), and the adoption rate (based 

on the feed value relative to price). 

Furthermore, as world vegetable oil prices increase, dry mill ethanol producers will have 

an incentive to extract the corn oil from the DGs. This step changes the nutritional content of the 

DGs, which results in different replacement rates than currently used in FAPRI or FASOM or 

described by Argonne. 

We plan to evaluate and incorporate a least cost feed rationing approach for the final rule 

in both the FASOM and FAPRI modeling systems. This will include assumptions about 

352 
 

inclusion rates and displacement ratios, including considering additional replaced feed inputs 

such as urea as a protein source. 

2.6.5.1.2 Crop Yields 

Assumptions about yields and how they may change over time can also influence land 

use change predictions. Domestic yields were based on USDA projections, extrapolated to 2022. 

In 2022 we estimate that the U.S. average corn yield will be approximately 180 bushels/acre (a 

1.6% annual increase consistent with recent trends) and average U.S. soybean yields will be 

approximately 50 bushels per acre (a 0.4% annual increase).RRRRRRR Using the FASOM model, 

we conducted a sensitivity analysis on the impact of higher and lower yields in the U.S. Details 

on this scenario are included in DRIA Chapter 5.1. International yields changes are also based 

on historic trends. The FAPRI model contains projected yields and yield growth rates that are 

generally lower in other countries compared to the U.S. For example, corn yields in Argentina 

are assumed to be approximately 140 bu/acre in 2022 (a 0.8% annual increase). Corn yields in 

Brazil are assumed to be 68 bu/acre in 2022 (a 1.1% annual increase). 

The FASOM and FAPRI models currently do not take into account changes in 

productivity as crop production shifts to marginal acres or the impact of price-induced yield 

changes on land use change. We would expect these two factors to work in opposite directions, 

and therefore serve as offsetting impacts. Marginal acres in fully developed agricultural systems 

are expected to have lower yields, because most productive acres are already under cultivation. 

This may not be the case in developing systems where prime agricultural lands are not currently 

in full production due to, for example, lack of supporting infrastructure. Changes in agricultural 

inputs (e.g., fertilizer, pesticides) can also change crop yields per acre. Higher commodity prices 

might provide an incentive to increase production on existing acres. If the costs of increasing 

productivity on existing land were minimal relative to the value of the increased production, then 

agricultural landowners would presumably adopt these productivity-enhancing actions under the 

reference case. Although it is reasonable to assume a trend wherein some productivityenhancing practices may become profitable if commodity prices are high enough, it is not clear 

that farmers would find significant increases in production per acre profitable. If crop yields 

either domestically or international are significantly impacted by higher commodity prices, this 

could affect our assessment of land use impacts and the resulting GHG emissions due to 

increased biofuel demand in the U.S. However, as described in Chapter 5, the change in 

commodity prices associated with the increase in U.S. biofuel as a result of the EISA mandates 

are relatively small and likely not large enough to induce very large yield changes. 

2.6.5.1.3 Land Conversion Costs 

The assumed cost associated with different types of land conversion can also play a key 

role in determining how much land will be converted. In FASOM, the decision to convert land 

from pasture or forest to cropland is based on whether the landowner can increase the net present 

value of expected returns through conversion (including any costs of conversion). Among other 

things, the decision to convert land depends on regional yields, costs, and other factors affecting 

RRRRRRR Note that these assumptions about exogenous yield increases were applied in every scenario. 

353 
profitability and on the returns to alternative land uses. In other words, FASOM assumes that 

land conversion is based on maximizing profits rather than minimizing costs. 

FASOM allows acres to convert between different types of crops without incurring 

conversion costs. Crop land is allowed to move from the pasture land inventory into the crop 

land category and backwards; however, there are replacement costs for forage as well as 

conversion costs of moving between land uses. Conversion costs from pasture to crop are 

expected to be generally lower than conversion costs from forest to crop, because forest 

conversion requires an investment to clear stumps, level, and otherwise prepare the land for 

planting. Conversion cost will also depend on the type of forest land converted and the value of 

the lumber or other products removed. The land quality factors such as topography or soil 

characteristics generally restrict some lands to only be in forest. Likewise, growing conditions 

render some lands unsuitable for forest uses at all, particularly in the drier plains areas and would 

thus only be suitable for some agricultural uses. For land moving from forest to agriculture, the 

net present value of land in agriculture must exceed returns to a rotation in forestry plus the 

future value of forested land by the investment cost to transfer land plus any hurdle cost (this 

term is currently set to zero). In both land transfer cases, the land moves between sectors until 

the markets equilibrate and the net present value plus the investment and market wedges are 

equal across the sectors for lands on the margin. Land movement does not occur if the 

differences in the land returns are less than the hurdle cost plus the land transformation 

investment costs. 

FAPRI does not explicitly model land conversion costs, but the international production 

supply curves in the FAPRI model implicitly account for conversion costs. FAPRI's supply 

curves are based on historical responses to price changes, which account for land conversion 

costs, based on expected future returns associated with land conversion. Thus, international land 

use changes projected by FAPRI are based on economic land-use decisions. 

2.6.5.1.4 Total Area of Land Converted 

We ran the FASOM and FAPRI models with the volume scenarios described in Table 

2.3-1 to estimate biofuel induced crop expansion domestically and internationally. The FASOM 

results were used to represent domestic land use change and FAPRI results were used to 

determine international land use change. 

FASOM domestic land use change was described in Section 2.6.2.1. Table 2.6-22 shows 

the FASOM land use change results for the different fuel scenarios considered. 

Table 2.6-22. Domestic Crop Expansion by Scenario, 2022 

Scenario Total Cropland Increase 

(million acres) 

Normalized Cropland Increase 

(acres per thousand ethanol 

equivalent gallons) 

Corn Ethanol 0.3 0.13 

Soybean Biodiesel 0.2 0.34 

Corn Stover Ethanol 0.0 0 

Switchgrass Ethanol 1.3 0.28 

354 
The FAPRI model predicted cropland shifting internationally due to changes in U.S. 

exports for the different fuel volume scenarios considered. Not all export losses are made up 

with production, as there are shifts in crops and decreases in demand that also occur. Figure 2.6­

14 shows absolute internationally crop production pattern changes and Figure 2.6-14 shows per 

gallon crop pattern changes due to the changes in U.S. exports. 

Figure 2.6-14. 

Foreign Cropland Changes by Scenario, 2022 

(millions harvested acres) 

International Cropland Use Change by Crop in 2022 

-1.0 

0.0 

1.0 

2.0 

3.0 

4.0 

5.0 

Wheat

Cotton

Corn

Sorghum

Barley

Soybean

Rapeseed

Sunflower

Palm

Peanut

Rice

Sugarbeet

Sugarcane

Total 

Millions of Acres 

Corn Only Volume Scenario Biodiesel Only Volume Scenario 

Sugarcane Imports Only Volume Scenario Switchgrass Only Volume Scenario 

355 
356 

Figure 2.6-15. 

Normalized Foreign Cropland Changes by Scenario, 2022 

(harvested acres per thousand gallons) 

International Cropland Use Change by Crop per Thousand Gallons of Biofuel in 2022 

-0.5 

0.0 0.5 1.0 1.5 2.0 

Wheat

Cotton

Corn

Sorghum

Barley

Soybean

Rapeseed

Sunflower

Palm

Peanut

Rice

Sugarbeet

Sugarcane

Acres per Thousand Gallons of Biofuel

(Ethanol Equivalent) 

Corn Only Volume Scenario Biodiesel Only Volume Scenario Sugarcane Imports Only Volume Scenario Switchgrass Only Volume 
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357 
358 

Table 2.6-23 shows the FAPRI land use change results for the different fuel scenarios 

considered. 

Table 2.6-23. Foreign Cropland Increase by Scenario, 2022 

Scenario Total Cropland Increase 

(million harvested acres) 

Normalized Cropland Increase 

(acre per thousand ethanol 

equivalent gallons) 

Corn Ethanol 4.4 1.68 

Soybean Biodiesel 0.9 1.87 

Switchgrass Ethanol 1.3 0.41 

Brazilian Sugarcane Ethanol 3.7 1.48 

The switchgrass ethanol scenario shows the least acreage change per gallon. This is 

partly due to the fact that in 2022 switchgrass ethanol is assumed to have high yields per acre. 

For example, corn ethanol yields in 2022 are assumed to be approximately 480 gal/acre, while 

switchgrass ethanol yields are assumed to be approximately 580 gal/acre. The corn stover 

ethanol case is not assumed to have any land use change impacts. The models also show that 

there are significant land use change impacts associated with increased sugarcane production in 

Brazil, and resultant changes in Brazilian commodity exports. Soybean biodiesel has lower 

gallons per acre yields than other fuels, approximately 75 gallons per acre, requiring more land 

per gallon of soy-based biodiesel production. However, biodiesel has a higher energy content 

then ethanol, so on a per gallon basis offsets more petroleum fuel, which decreases the land use 

impact per gallon of biodiesel production. 

2.6.5.2 Where Does Land Use Change Occur 

The first step in determining what domestic and international land will be converted due 

to biofuels production is to determine to what extent the increased demand for biofuel feedstock 

will be met through increased U.S. agricultural production or reductions in exports. 

This question has several implications. For example, U.S. agricultural production is 

typically more energy and input intensive, but has higher yields, than agricultural production in 

other parts of the world. This implies that increased production in the U.S. has higher input 

GHG emission impacts but lower land use change impacts compared to oversees production. In 

addition, the types of land where agriculture expands would be different in the U.S. as compared 

to other parts of the world. 

As noted previously, EPA’s analysis relies on FASOM predictions to represent changes 

in the U.S. agricultural sector, including land use, and on FAPRI to predict the resulting 

international agricultural sector impacts, including the amount of additional cropland needed 

under different scenarios. The impact on the international agricultural sector is highly dependent 

on U.S. agricultural commodity export fluctuations resulting from increased biofuel production. 

As shown in Section 2.6.3, coordination of assumptions between FASOM and FAPRI has 

generated a consistent export picture response from both the FASOM and FAPRI model for the 

majority of biofuel and feedstock scenarios considered. 
 

 

 

 

 

 

 

 

 

 

 

FASOM and FAPRI also show similar domestic land use change responses, with large 

shifts between crops. Figure 2.6-16 shows the comparison of FASOM and FAPRI domestic crop 

acre changes for the different fuel scenarios. Soy-based biodiesel production has the largest 

impact on U.S. exports per ethanol equivalent gallon. For the corn and switchgrass ethanol, the 

models show the same type of response, with FAPRI showing slightly higher overall net crop 

acreage growth. 

Figure 2.6-16. 

Comparison of FASOM and FAPRI Domestic Crop Acre Changes by Scenario, 2022 

(acres per thousand ethanol equivalent gallons) 

Change in U.S. Acres per Thousand Gallons of Biofuel 

-4 

-3 

-2 

-1 

0 

1 

2 

3 

4 

FASOM FAPRI FASOM FAPRI FASOM FAPRI FASOM FAPRI 

Corn Ethanol Only Volume 

Scenario 

SoyOil Biodiesel Only Volume 

Scenario 

Switchgrass Ethanol Only Volume 

Scenario 

Corn Stover 

Ethanol Only 

Volume 

Scenario 

Sugarcane 

Ethanol Imports 

Only Volume 

Scenario 

Acres per Thousand Gallons (Ethanol Equivalent)

 Other Crops (CARD)

 Other Crops (FASOM) 

Wheat 

Switchgrass 

Sugarcane 

Sugarbeet 

Soybeans 

Sorghum 

Rice 

Oats 

Hay 

Cotton

 Corn (Corn + Silage) 

Barley 

Due to the wide range of carbon and biomass properties associated with land in different 

parts of the world, the location of crop conversion is also important to our lifecycle analysis. For 

example, an acre of forest in Southeast Asia stores a much larger quantity of carbon than an acre 

of forest in Northern Europe. The FAPRI model provides estimates of the acreage change by 

country and crop that result from a decrease in U.S. exports due to the increase in U.S. biofuel 

demand. These estimates are based on historic responsiveness to changes in prices in other 

countries. Implicit in these supply curves are the costs associated with converting new land to 

crop production and the relative competitiveness of each country to increase production based on 

production costs, yields, and transportation costs. FAPRI also includes in its baseline projections 

estimates of future population growth, GDP growth, and other macroeconomic changes. FAPRI 

359 
also takes into account the fact that not all U.S. exports will need to be made up in international 

production, as there are small decreases in demand due to shifts in crop production and higher 

prices. 

Figure 2.6-17 shows absolute acres of crop conversion, and Figure 2.6-18 includes 

normalized cropland changes for the different fuel scenarios. Our modeling predicts that Brazil 

will account for a large portion of international crop expansion as a result of U.S. biofuel 

production and production of sugarcane ethanol in Brazil. However, other countries have major 

crop expansion as well, including India and Nigeria. 

Figure 2.6-17. 

Regional Crop Expansion by Renewable Fuel, 2022 

(thousand harvested acres) 

Soy-Based Biodiesel Corn Ethanol Sugarcane Ethanol Switchgrass Ethanol 

4,500 

4,000 

3,500 

3,000 

2,500 

2,000 

1,500 

1,000 

500 

0 

-500 

Argentina Brazil India China EU & Nigeria Other Paraguay Other Rest of S.E. Asia U.S. Foreign 

Russia Africa Latin World Total 

America 

360 
Figure 2.6-18. 

Normalized Regional Crop Expansion by Renewable Fuel, 2022 

(harvested acres per thousand gallons) 

Soy-Based Biodiesel Corn Ethanol Sugarcane Ethanol Switchgrass Ethanol 

0.0 

0.5 

1.0 

1.5 

2.0 

2.5 

Argentina Brazil India China EU & Nigeria Other Paraguay Other Rest of S.E. Asia U.S. World 

Russia Africa Latin World Total 

America 

2.6.5.3 What Type of Land is Converted 

2.6.5.3.1 Domestic Land Use Conversion 

The FASOM model includes competition for land between agriculture, pasture, and 

forest. The interaction is based on providing the highest rate of return across the different land 

types. Therefore, domestically we have the ability to explicitly model what types of land would 

be converted to increased agriculture based on the rates of return for different land types for the 

63 regions in FASOM. For this proposal we incorporated the agricultural component of the 

FASOM model, but not the forestry component, so domestically all additional cropland comes 

from pasture. As we incorporate the FASOM forestry model for the final rule we expect to see 

more interaction between the forestry and agriculture sectors, such that there may be conversion 

of forest to agriculture. While we do not know if forest will be converted to cropland, or the 

extent that this might occur, if domestic forests were converted to cropland, we would expect 

domestic GHG emissions to increase. On the other hand, if more crop expansion occurs 

domestically we would expect that to offset some of the growth in foreign crop acreage. This 

work will be incorporated for our final rule. 

2.6.5.3.2 International Land Use Conversion 

Since FAPRI does not contain information on what type of land would be converted into 

cropland, we worked with Winrock to address this question. Using satellite data from 2001­

361 
 

2004, Winrock provided a breakdown of the types of land that have been converted into crop 

land for a number of key agricultural producing regions. We used this information about recent 

land use trends to estimate which types of land would be cleared in each region. Below we 

provide details about the data sources and methods used for these calculations. 

2.6.5.3.2.1 International Land Use Conversion Data Sources 

Change in land use and land cover (LU/LC) was estimated at the country and state level 

using MODIS satellite imagery (1 km resolution pixels) for the years 2001 and 2004 for all 

countries. MODIS imagery was chosen for this analysis due to its global coverage and 

homogenous classification scheme that allows direct comparison across time and space. MODIS 

(Moderate Resolution Imaging Spectroradiometer) is a sensor that offers a unique combination 

of features: it detects a wide spectral range; it takes measurements at three spatial resolutions 

(levels of detail); it takes measurements all day, every day; and it has a wide field of view. 

MODIS is one of several sensors carried on both the Terra and Aqua satellites, managed by 

NASA. Terra was launched in December 1999 and Aqua was launched in May 2002. Both 

satellites complete a north to south orbit of the Earth in less than 2 days. The land cover dataset 

published by the USGS used in this analysis, MODIS/Terra Land Cover Type Yearly L3 Global 

1km SIN Grid (MOD12Q1) version 4, comes from the Terra satellite.SSSSSSS 

The MOD12Q1 data are compiled from several sources to create a yearly global land 

cover map. Inputs to the MODIS/Terra Land Cover Type Yearly L3 Global 1km SIN Grid 

include: 

1. Land/water mask that restricts classification to land regions and shallow water 

regions 

2. The MODIS Land Bands (1-7) 

3. Spatial texture derived from Band 1 

4. Directional reflectance information 

5. MODIS Enhanced Vegetation Index (EVI) 

6. Snow cover 

7. Land surface temperature 

8. Terrain elevation information 

These data are composited over a 32-day cycle and values for land classification, change 

detection and mixture modeling are assigned by algorithms using decision tree and artificial 

neural network classifiers. Land cover classes are processed by continent. The 32 day products 

are used to produce the yearly globally-consistent, multi-temporal MOD12Q1 database on a 1­

km grid. 

The algorithm development and validation efforts for the Land Cover Product are based 

on a network of test sites developed to represent major global biomes and cover types. Sites for 

which temporal sequences of Thematic Mapper (TM) and AVHRR data, coupled with fineresolution land cover and vegetation data, are available, especially in North and South America 

SSSSSSS The official MOD12Q1 version 4 data were publicly released at the EDC DAAC on April 16, 2004. It can be 

found at http://edcdaac.usgs.gov/modis/mod12q1v4.asp 

362 
 

(Belward 1999). According to the MODIS land team validation website, the accuracy of the 

IGBP land cover product, version 3, is 75-80 percent globally; 70-85 percent by continental 

regions; and in individual classes ranges from 60 in closed shrubland to 90 percent for barren or 

sparse land cover.TTTTTTT This analysis used version 4 of the MODIS/Terra Land Cover Type 

Yearly L3 Global 1km SIN Grid which is published as being validated to Stage 1. A Stage 1 

validation means that the product accuracy has been estimated using a small number of 

independent measurements obtained from selected locations and time periods and groundtruth/field program effort. There are no published reports as to the accuracy of version 4 but it 

would be safe to assume it is no worse than version 3 and in all likelihood better. 

Two tools are used by the MODIS land team to assess data quality; confusion matrixes 

and aggregations of confidence values. The confusion matrixes describe how well the training 

sites are classified when they are unknown by the classifier, and so provide information on the 

accuracy of the classification process as applied to the training site database. The confidence 

values are generated by the classifier and indicate how well the pattern of spectral and temporal 

variation in annual observations of each pixel fits the examples of training data provided to the 

classifier. They may be treated as probabilities of correct classification, given the input training 

data. 

Within the classification process, errors are generated when the classification algorithm 

selects the wrong class. With respect to a particular class, errors of omission occur when pixels 

of that class are assigned wrong labels; errors of commission occur when other pixels are 

wrongly assigned the label of the class considered. These errors occur when the signal of a pixel 

is ambiguous, perhaps as a result of spectral mixing, or when the signal is produced by a cover 

type that is not accounted for in the training process. These errors are a normal part of the 

classification process. They can be minimized, but not voided entirely. Although they cannot be 

identified on a pixel-by-pixel basis due to processing constraints, they can be characterized in a 

statistical sense. 

Although other global land cover products are available (such as the Global Land Cover 

2000 dataset), the purpose of this analysis was to analyze change in land use and cover over 

time. Thus we chose to use the MODIS imagery because it adheres to a uniform 17-category 

IGBP classification scheme at both time periods (2001 and 2004), allowing for direct comparison 

over multiple regions and years. 

MODIS data are published using the International Geosphere Biosphere Programme 

(IGBP) global land cover categories, a list of 17 cover classes (Table 2.6-23). The IGBP land 

cover list includes eleven classes of natural vegetation, three classes of developed and mosaic 

lands, and three classes of non-vegetated lands. The natural vegetation units distinguish 

evergreen and deciduous, broadleaf and needle-leaf forests, mixed forests, where mixtures occur; 

closed shrublands and open shrublands; savannas and woody savannas; grasslands; and 

permanent wetlands of large areal extent. The three classes of developed and mosaic lands 

distinguish among croplands, urban and built-up lands, and cropland/natural vegetation mosaics. 

Classes of non-vegetated land cover units include snow and ice; barren land; and water bodies. 

TTTTTTT The MODIS land team validation website can be accessed at 

http://landval.gsfc.nasa.gov/ProductStatus.php?ProductID=MOD12 

363 
 

 

 

Table 2.6-23. 

Original IGBP and Modified Classification Schemes for MODIS Land Cover Imagery 

for the Years 2001 and 2004. 

IGBP Land cover class 

Modified land 

cover class 

(this analysis) IGBP Class Explanation 

Water Bodies Excluded 

Evergreen Needleleaf Forests Forest 

Lands dominated by trees with a %canopy cover >60% and 

height >2m. Almost all trees remain green all year, canopy is 

never without green foliage. 

Evergreen Broadleaf Forests Forest 

Lands dominated by trees with a %canopy cover >60% and 

height >2m. A;most all trees remain green all year. Canopy 

is never without green foliage. 

Deciduous Needleleaf Forests Forest 

Lands dominated by trees with a % canopy cover >50% and 

height exceeding 2m. Consists of seasonal needleleaf tree 

communitieis with an annual cycle of leaf-on and leaf-off 

periods. 

Deciduous Broadleaf Forests Forest 

Lands dominated by trees with a %canopy cover >60% and 

height exceeding 2m. Consists of seasonal broadleaf tree 

communities with an annual cycle of leaf-on and leaf-off 

periods. 

Mixed Forests Forest 

Lands dominated by trees with a %canopy cover >60% and 

height >2m. Consists of tree communities with interspersed 

mixtures or mosaics of the other four forest cover types. 

None of the forest types exceeds 60% of landscape. 

Closed Shrublands Shrubland 

Lands with woody vegetation <2m tall and with shrub canopy 

cover >60%. The shrub foliage can be either evergreen or 

deciduous. 

Open Shrublands Shrubland 

Lands with woody vegetation <2m tall with shrub canopy 

cover between 10-60%. The shrub foliage can be either 

evergreen or deciduous. 

Woody Savannas Savanna 

Lands with herbaceous and other understory systems and 

canopy cover of 30-60%. Height >2m. 

Savannas Savanna 

Lands with herbaceous and other understory systems and 

canopy cover of 10-30%. Height >2m. 

Grasslands Grassland 

Lands with herbaceous types of cover. Tree and shrub cover 

is less than 10%. 

Permanent Wetlands Excluded 

Croplands Cropland 

Lands covered with temporary crops followed by harvest and 

a bare soil period (e.g., single and multiple cropping 

systems). Note that perennial woody crops will be classified 

as the appropriate forest or shrub land cover type. 

Urban and Built-Up Excluded 

Cropland/Natural Vegetation 

Mosaic Excluded 

Permanent Snow and Ice Excluded 

Barren or Sparsely Vegetated Excluded 

Unclassified Excluded 

The IGBP land cover categories were not designed for use with MODIS specifically. 

Rather, the classification system was first published with the IGBP Global Land Cover Map 

(DISCover v 1.0) in 1997. This dataset was derived at 1 km resolution from the Advanced Very 

High Resolution Radiometer (AVHRR) sensor on board several NOAA satellites and the 17 land 

cover classes are based on biophysical properties. 

364 
We first reclassified the land use and land cover categories included in the original 

MODIS imagery into five general classes: cropland, forest, grassland, savanna and shrubland 

(See Table 2.6-23). As the MODIS land cover maps used for this analysis are coarse resolution 

(1-km, equivalent to a pixel area of 100 hectares) and classified into broad land cover categories, 

the spectral characteristics of the finer classes may be similar to each other in many cases and 

thus land use conversions among them could be ambiguous. Other categories in the MODIS 

imagery that fell outside these five land cover classes (e.g., urban/built-up land) were excluded 

from the analysis. An example of the imagery before and after reclassification is shown for 

Argentina (top) and Brazil (bottom) in Figure 2.6-18. 

365 
Figure 2.6-18. 

Comparison of Original MODIS Classification (left) and Reclassification Used for This 

Analysis (right) for Two Sample Countries: Argentina (Top) and Brazil (Bottom). 

Argentina 

Peru 

Bolivia 

Colombia 

Paraguay 

yana 

Uruguay 

Argentina 

Peru 

Bolivia 

Colombia 

Paraguay 

Guyana 

Uruguay 

After we had reclassified the two map products, change analyses were conducted by 

comparing the land cover map from 2001 with that for the same location at 2004. A new dataset 

for each country, now referred to as land change data, was produced that showed how the 

original land cover categories within each state and country changed, if at all, and into what new 

category the change occurred—often referred to as a land cover change matrix. 

366 
Comparing two products directly is not the best way to analyze change in LU/LC, as 

errors in the interpretation of the first map can be compounded when compared to a second map. 

The ideal way is to conduct a change analysis directly and interpret the change. However, a 

direct change analysis requires a major effort to not only perform the change detection but to also 

interpret what the change is (from what to what). A comparison of the two LU/LC maps to 

obtain change is not the most desirable approach but it is the only approach available given the 

products that exist. Furthermore, very few countries have LU/LC products that have been 

prepared using change detection techniques for full change detection in all LU/LC classes. 

Even with the best available imaging technology, we found that the areas of some of the 

LU/LC classes and their changes are somewhat ambiguous. In an attempt to shed light on the 

causes of these ambiguities, we first compared the area of forest cover for the 2004 MODIS 

product with that given in the FAO FRA 2005 report (See Table 2.6-24.534 Several anomalies in 

the two data sets are evident: 

-- All countries report greater area of forest in the FRA 2005 report than we obtained 

from the MODIS product, except for the three Southeast Asian countries of Indonesia, Malaysia, 

and Philippines. 

-- The greater area of forest reported by FRA 2005 is to be expected as FAO requires 

countries to report area of all wooded lands with a canopy cover of 10% or higher, whereas the 

MODIS product defines forests with a canopy cover greater than 50-60%. For example, FRA 

2005 gives almost 478 million ha of forest for Brazil –this includes not only the Amazonian and 

Atlantic forests, but also a range of woody savanna/shrublands that have a canopy cover of 

>10%. In our analysis, these woody savannas and shrublands are purportedly reported as a 

separate class, resulting in an area of forest of about 406 million ha. The reasons for the greater 

forest cover reported under FRA 2005 versus the MODIS estimate for the other countries are 

likely to be the same as for Brazil. 

-- For Indonesia, Malaysia, and the Philippines, the MODIS product results in 

considerably greater forest area than reported by FRA 2005. This suggests that the large areas of 

plantation, perennial tree crops (e.g. rubber and palm oil plantations), and the woody formations 

are classed as forest under the MODIS algorithm. 

367 
 

 

Table 2.6-24. 

Country-Level MODIS Forest Area Cover Data and Forest Cover 

Reported in FAO FRA 2005 

Country MODIS 2004 Forest Area 

(ha) 

FAO FRA2005 Forest Area 

(ha) 

Argentina 23,566,147 33,021,000 

Brazil 402,472,52+ 477,698,000 

China 149,007,347 197,290,000 

India 31,807,808 67,701,000 

Indonesia 150,652,300 88,495,000 

Malaysia 28,309,936 20,890,000 

Philippines 15,952,945 7,162,000 

There are other ambiguities in the MODIS data. For some countries forest area appeared 

to increase (Brazil, China, Malaysia) or show little change (Indonesia, Philippines) in the period 

2001-2004, and the rest had a loss in forest cover as is often expected. However, Table 2.6-25 

shows the net change, and just because total area appears to change little or even increase it does 

not mean that forests are not being cleared. The value of the MODIS data is that transitions 

between all LU/LC classes can be estimated for the period 2001-2004. For example, Table 2.6­

25 shows that 341,186 hectares of land were converted from forest to cropland in Brazil from 

2001 to 2004. 

Table 2.6-25. 

Area of Main LU/LC Classes in Brazil in 2001 and 2004 Based on MODIS Data 

BRAZIL 2004 

2001 Cropland Forest Grassland Mixed Savanna Shrub 

Total 

Hectares 

2001 

Cropland 9,477,369 249,901 919,366 4,346,228 8,529,974 116,682 23,639,519 

Forest 341,186 379,059,490 1,408,111 1,500,199 15,947,827 1,136,045 399,392,858 

Grassland 1,472,851 1,453,441 9,152,627 2,576,107 22,384,406 1,456,720 38,496,152 

Mixed 4,918,777 1,813,684 2,064,084 21,433,207 25,956,386 211,126 56,397,265 

Savanna 6,004,819 18,614,978 12,295,754 21,595,617 214,505,969 4,698,914 277,716,052 

Shrub 304,374 1,281,032 2,190,966 440,100 16,752,860 7,296,200 28,265,531 

Total 

Hectares 

2004 22,519,377 402,472,526 28,030,907 51,891,458 304,077,422 14,915,687 823,907,377 

MODIS also provides intra-country LU/LC changes by state or administrative unit. For 

example, using MODIS data Table 2.6-26 shows where forest to cropland conversion took place 

in Brazil between 2001 and 2004. 

368 
 

Table 2.6-26. 

MODIS Forest to Crop Conversion in Brazil , 2001 to 2004 

Country State 

Share of Forest to Crop 

Conversion 

Brazil Acre 0.0% 

Alagoas 2.0% 

Amapa 0.6% 

Amazonas 0.1% 

Bahia 3.5% 

Ceara 0.2% 

Distrito Federal 0.0% 

Espirito Santo 0.7% 

Goias 4.1% 

Maranhao 1.1% 

Mato Grosso 3.2% 

Mato Grosso Do Sul 11.5% 

Minas Gerais 4.1% 

Para 1.6% 

Paraiba 0.3% 

Parana 31.2% 

Pernambuco 1.5% 

Piaui 0.1% 

Rio De Janeiro 0.2% 

Rio Grande Do Norte 0.1% 

Rio Grande Do Sul 15.4% 

Rondonia 0.0% 

Roraima 0.1% 

Santa Catarina 2.9% 

Sao Paulo 14.5% 

Sergipe 0.8% 

Tocantins 0.2% 

All 

Brazil 100.0% 

2.6.5.3.2.2 Calculating the Type and Location of Land Use Change 

We used the MODIS LU/LC data described above to estimate what types of land would 

be cleared to make room for cropland expansion, and where within countries that land 

conversion would occur. The steps in this calculation are described below, with Brazil as the 

primary example. 

2.6.5.3.2.2.1 What Type of Land is Converted to Cropland by Region 

Table 2.6-27 shows the percentage of land type converted to cropland according to the 

MODIS data. We used these percentages to calculate a weighted average of the types of land 

converted into cropland. For example, if FAPRI predicts that one additional hectare of cropland 

369 
will be brought into production in Brazil, we used the Winrock data to estimate that 4% on 

average of that hectare will come from forest, 18% of that hectare will come from grassland, 

74% of that land will come from Savanna, and 4% will come from shrubland. 

Table 2.6-27. 

MODIS Types of Land Converted to Cropland by Country 

COUNTRY Forest Grassland Savanna Shrub 

Argentina 8% 40% 45% 8% 

Brazil 4% 18% 74% 4% 

China 17% 38% 23% 21% 

EU 27% 16% 36% 21% 

India 7% 7% 33% 53% 

Indonesia 34% 5% 58% 4% 

Malaysia 74% 3% 19% 3% 

Nigeria 4% 56% 36% 4% 

Philippines 49% 5% 44% 3% 

South Africa 10% 22% 53% 15% 

2.6.5.3.2.2.2 In Which States or Administrative Regions Does the Land Conversion Occur 

We also used the MODIS data to estimate where the land conversions would occur within 

countries or regions. Table 2.6-24 shows where in Brazil cropland was added, and what type of 

land was cleared in each state. This is important information because an acre of forest in the 

State of Amazonas, for example, sequesters substantially more carbon than an acre of forest in 

Sao Paulo. As you can see in Table 2.6-28, recent forest to cropland conversion has been far 

more common in Sao Paulo than Amazonas. Therefore, an estimate of land use change 

emissions in Brazil that does not weight forest to cropland conversion by the States where it 

would likely occur would tend to overestimate emissions per acre of crop expansion. 

370 
 

 

 

 

 

 

 

Table 2.6-28. 

MODIS Land Conversion to Cropland in Brazil by Land Type and State, 2001 to 2004 

(percent of land conversion type by state) 

Start Category Forest Grassland Savanna Shrub 

End Category Crop Crop Crop Crop 

Country State 

Brazil Acre 0.0% 0.0% 0.0% 0.0% 

Alagoas 2.0% 2.3% 0.8% 1.1% 

Amapa 0.6% 0.0% 0.0% 0.1% 

Amazonas 0.1% 0.0% 0.0% 0.0% 

Bahia 3.5% 13.4% 7.6% 24.9% 

Ceara 0.2% 0.4% 0.3% 1.5% 

Distrito Federal 0.0% 0.2% 0.2% 0.2% 

Espirito Santo 0.7% 1.3% 1.2% 0.4% 

Goias 4.1% 7.5% 11.5% 6.6% 

Maranhao 1.1% 0.9% 0.6% 1.4% 

Mato Grosso 3.2% 12.0% 8.9% 10.2% 

Mato Grosso Do Sul 11.5% 11.6% 9.0% 3.6% 

Minas Gerais 4.1% 7.6% 15.7% 10.5% 

Para 1.6% 0.2% 0.2% 0.1% 

Paraiba 0.3% 2.3% 0.9% 3.9% 

Parana 31.2% 10.5% 8.4% 5.7% 

Pernambuco 1.5% 3.6% 1.6% 5.2% 

Piaui 0.1% 0.3% 0.3% 1.4% 

Rio De Janeiro 0.2% 0.8% 2.8% 2.6% 

Rio Grande Do Norte 0.1% 1.5% 0.6% 2.5% 

Rio Grande Do Sul 15.4% 6.9% 6.7% 2.7% 

Rondonia 0.0% 0.0% 0.0% 0.0% 

Roraima 0.1% 0.3% 0.1% 1.0% 

Santa Catarina 2.9% 0.7% 0.5% 0.9% 

Sao Paulo 14.5% 13.4% 21.0% 11.6% 

Sergipe 0.8% 1.7% 0.4% 1.1% 

Tocantins 0.2% 0.5% 0.6% 0.7% 

All 

Brazil 100.0% 100.0% 100.0% 100.0% 

We used the data summarized in Tables 2.6-27 and 2.6-28 to estimate where and what 

types of land in Brazil would be cleared per hectare of cropland expansion. This calculation can 

be summarized with the following formula: 

Land clearing per acre crop expansion by land-type and State = CEL * CELS, where: 

CEL = share of crop expansion from land-type L; 

CELS = share of crop expansion from land-type L in State S; 

L = forest, shrubland, savanna, or grassland 

S = one of the 26 Brazilian States 

371 
 

 

 

 

Using this calculation we estimated the land use changes per hectare of cropland 

expansion in Brazil shown in Table 2.6-29. For example, in Brazil 4% of crop expansion occurs 

on shrubland and 25% of shrub to crop conversion occurred in the state of Bahia. Therefore, for 

each hectare of crop expansion in Brazil, we projected that approximately 0.01 hectares of shrub 

would be converted to cropland in Bahia. We repeated this calculation for all land types and for 

each of the ten countries that we had MODIS data for. 

Table 2.6-29. 

Projected Crop Expansion in Brazil by Land Type and State 

(acres of conversion per acre of crop expansion) 

Start Category Forest Grassland Savanna Shrub 

End Category Crop Crop Crop Crop 

Country State 

Brazil Acre 0.00 0.00 0.00 0.00 

Alagoas 0.00 0.00 0.01 0.00 

Amapa 0.00 0.00 0.00 0.00 

Amazonas 0.00 0.00 0.00 0.00 

Bahia 0.00 0.02 0.06 0.01 

Ceara 0.00 0.00 0.00 0.00 

Distrito Federal 0.00 0.00 0.00 0.00 

Espirito Santo 0.00 0.00 0.01 0.00 

Goias 0.00 0.01 0.08 0.00 

Maranhao 0.00 0.00 0.00 0.00 

Mato Grosso 0.00 0.02 0.07 0.00 

Mato Grosso Do 

Sul 0.00 0.02 0.07 0.00 

Minas Gerais 0.00 0.01 0.12 0.00 

Para 0.00 0.00 0.00 0.00 

Paraiba 0.00 0.00 0.01 0.00 

Parana 0.01 0.02 0.06 0.00 

Pernambuco 0.00 0.01 0.01 0.00 

Piaui 0.00 0.00 0.00 0.00 

Rio De Janeiro 0.00 0.00 0.02 0.00 

Rio Grande Do 

Norte 0.00 0.00 0.00 0.00 

Rio Grande Do Sul 0.01 0.01 0.05 0.00 

Rondonia 0.00 0.00 0.00 0.00 

Roraima 0.00 0.00 0.00 0.00 

Santa Catarina 0.00 0.00 0.00 0.00 

Sao Paulo 0.01 0.02 0.16 0.00 

Sergipe 0.00 0.00 0.00 0.00 

Tocantins 0.00 0.00 0.00 0.00 

All 

Brazil 0.04 0.18 0.74 0.04 

372 
2.6.3.2.2.3. Land Use Change Beyond Cropland Expansion 

As described above, we used the FAPRI model to project how much cropland expansion 

would occur in each country, and MODIS satellite data provided by Winrock to estimate where 

and what types of land would be cleared within each country or region to make room for new 

cropland. Table 2.6-27 shows that in many countries cropland has been added in areas that were 

previously categorized as grassland or savanna. In consultation with Winrock we determined 

that lands categorized as grassland or savanna, according to IGPB the classification scheme, 

could be used as pasture for livestock grazing. Therefore, if we used the land use change 

estimates in Table 2.6-29 as our end point, we would project significant losses of actively 

managed pasture. However, it may be unreasonable to project pasture losses unless we also 

project comparable overall declines in livestock production and/or increases in pasture 

intensification. To resolve this issue and to estimate overall land use changes as accurately as 

possible, we added a certain amount of “pasture replacement” land use change to our total land 

use change estimates. 

We assumed that actively managed pasture converted to cropland would have to be 

replaced with new pasture acreage, thereby capturing some of the domino effects associated with 

converting fertile land into crop production. We used land cover information from the GTAP 

database to estimate the proportion of grassland and savanna that is actively managed as pasture 

in each country (see Table 2.6-30). According to the GTAP database 64% of grassland and 

savanna is Brazil is actively managed for livestock grazing. We applied this data to our land use 

change estimates, which implies that, on average, 64% of the grassland and savanna converted to 

crop production in Brazil would previously have been used for livestock grazing. Therefore, 

since recent trends indicate that 92% of Brazilian crop expansion would occur on grasslands or 

savanna (see Table 2.6-27), we projected that approximately 59% of crop expansion would occur 

on land previously used as pasture. 

Table 2.6-30. 

Grassland and Savanna Actively Managed for Livestock Grazing by Region, 

2000-2001 

COUNTRY 

Unmanaged Savanna and 

Grassland (hectares) 

Managed Pasture 

(hectares) 

Percent of Savanna and 

Grassland Managed for Pasture 

Argentina

Brazil 

China 

European Union 

India 

Indonesia 

Malaysia 

Nigeria 

Phillipines 

South Africa 

 77,716,560 

101,991,992 

42,534,708 

14,529,446 

12,806,170 

7,704,545 

0 

24716916 

0 

19132926 

96,452,176 

181,046,752 

286,370,272 

64,005,559 

11,798,180 

2,462,572 

292,900 

18762928 

131,755 

77293112 

55.4% 

64.0% 

87.1% 

81.5% 

48.0% 

24.2% 

100.0% 

43.2% 

100.0% 

80.2% 

SOURCE: GTAP Land Cover Data (2000-2001) 

Figure 2.6-18 is a graphical representation of our Brazil pasture replacement estimates. 

In order to replace pasture displaced by crop expansion, we assumed that forest and shrubland 

would be cleared to make room for new pasture areas. We used the MODIS satellite data to 

estimate the shares of forest and shrubland that would then be cleared and converted to pasture to 

373 
replace the pasture converted to crops. We used the state-by-state distribution of each of these 

conversions to estimate where in Brazil the pasture replacement would occur. For example, we 

used the MODIS data’s state-by-state breakdown of where forest was converted to savanna in 

Brazil to estimate where forest would likely be converted to savanna to replace some of the lost 

pasture. The per hectare emissions factors shown in Figure 2.6-18 are non-discounted emissions 

over 80 years for each type of land conversion. Notice that in Brazil, average GHG emissions 

are greater for projected forest to grassland conversion than projected forest to cropland 

projection, because recent trends suggest that forest to grassland conversion tends to occur in 

regions with very carbon-rich forests. These emissions factors are discussed in detail below. 

Figure 2.6-18. 

Brazil Land Use Change Flow Chart with Cropland Expansion and 

Managed Pasture Replacement 

Table 2.6-31 provides a complete summary of projected land use change in Brazil per 

hectare of crop expansion. Notice that the land use changes under step one (cropland expansion) 

are exactly the same as in Table 2.6-29. The difference is that the complete summary of land use 

change in Brazil includes the pasture replacement step. We used the same methodology to 

calculate land use changes for all ten countries for which MODIS satellite data was provided. 

374 
 

 

 

 

 

 

Table 2.6-31. 

Summary of Brazil Land Use Change with Managed Pasture Replacement 

(acres of land conversion per acre of crop expansion) 

Step One: Crop Expansion Step Two: Pasture Replacement 

Replace 

Grassland 

Replace 

Savanna 

Start Category Forest Grassland Savanna Shrub Forest Shrub Forest Shrub 

End Category Crop Crop Crop Crop Grassland Grassland Savanna Savanna 

Country State 

Brazil Acre 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 

Alagoas 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.00 

Amapa 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 

Amazonas 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 

Bahia 0.00 0.02 0.06 0.01 0.00 0.02 0.02 0.06 

Ceara 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.03 

Distrito Federal 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 

Espirito Santo 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.00 

Goias 0.00 0.01 0.08 0.00 0.00 0.00 0.00 0.01 

Maranhao 0.00 0.00 0.00 0.00 0.00 0.00 0.02 0.01 

Mato Grosso 0.00 0.02 0.07 0.00 0.01 0.00 0.04 0.01 

Mato Grosso Do 

Sul 0.00 0.02 0.07 0.00 0.00 0.00 0.01 0.00 

Minas Gerais 0.00 0.01 0.12 0.00 0.00 0.01 0.01 0.02 

Para 0.00 0.00 0.00 0.00 0.00 0.00 0.03 0.00 

Paraiba 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.02 

Parana 0.01 0.02 0.06 0.00 0.00 0.00 0.02 0.00 

Pernambuco 0.00 0.01 0.01 0.00 0.00 0.01 0.00 0.02 

Piaui 0.00 0.00 0.00 0.00 0.00 0.00 0.01 0.01 

Rio De Janeiro 0.00 0.00 0.02 0.00 0.00 0.00 0.00 0.00 

Rio Grande Do 

Norte 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.02 

Rio Grande Do Sul 0.01 0.01 0.05 0.00 0.01 0.00 0.01 0.00 

Rondonia 0.00 0.00 0.00 0.00 0.00 0.00 0.01 0.00 

Roraima 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.01 

Santa Catarina 0.00 0.00 0.00 0.00 0.00 0.00 0.01 0.00 

Sao Paulo 0.01 0.02 0.16 0.00 0.00 0.00 0.01 0.00 

Sergipe 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 

Tocantins 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.01 

All 

Brazil 0.04 0.18 0.74 0.04 0.05 0.07 0.23 0.24 

EPA is reviewing parameters used to estimate pasture replacement, including further 

research and peer-review of these issues. For example, we plan to look at studies about whether 

it is more or less likely for pasture to be converted to crop production than grassland or savanna 

that is not already used for grazing. Grazing tends to occur near agricultural activity, suggesting 

that crop expansion would be more likely to occur on pasture. On the other hand, there is an 

extra opportunity cost associated with converting pasture to crop production, so farmers may 

prefer to expand crop production onto lands not already used for grazing. More detailed regional 

land use studies and economic modeling will help to answer these questions. 

375 
Intensification of grazing lands also has the potential to change the impacts of crop 

expansion, and to reduce the overall land use footprint of agriculture. For example, in Brazil 

cattle per hectare increased by 10% from 2001-2005, and one estimate suggests almost 50 

million acres of pastureland could become available due to more efficient use of land for cattle. 

This could reduce economic pressures to expand livestock grazing into unused lands, such as 

forests. We also plan more research to distinguish between grazing intensification that would 

occur regardless of biofuel production, and intensification induced by biofuel production. 

The amount of lost pasture that would be replaced and the types of land that would be 

cleared to replace it are also important. Based on recent land use trends, we assumed that forest 

and shrubland would be cleared to replace lost pasture. We did not, therefore, include the 

possibility that grassland and savanna that is not currently used for pasture could be put into 

grazing activities. Section 2.8 includes sensitivity analysis of the pasture replacement 

assumptions used in our analysis, which indicates that this is an important factor in land use 

change projections for lifecycle GHG analysis. 

To calculate the total area of land use changes in Brazil, we simply took the product of 

the total area of crop expansion projected by FAPRI and the land use changes per hectare 

summarized in Table 2.6-31. For an increase in U.S. corn ethanol consumption from 12.4 to 15 

billion gallons in 2022 (i.e. the difference between our Corn Only and Control Case), FAPRI 

projected 747,000 hectares of crop expansion in Brazil. A summary of total 2022 Brazil land use 

changes associated with this corn ethanol scenario is provided in Table 2.6-32. Land use change 

summaries for all ten countries are available in spreadsheets on the public docket for this 

proposed rulemaking. 

376 
 

 

 

 

 

 

Table 2.6-32. 

Projected Brazil Land Use Changes in Corn Ethanol Only Scenario, 2022 

(acres) 

Step One: Crop Expansion Step Two: Pasture Replacement 

Replace 

Grassland 

Replace 

Savanna 

Start Category Forest Grassland Savanna Shrub Forest Shrub Forest Shrub 

End Category Crop Crop Crop Crop Grassland Grassland Savanna Savanna 

Country State 

Brazil Acre 0 8 39 0 74 4 2,407 5 

Alagoas 630 3,156 4,399 316 220 258 717 891 

Amapa 174 39 205 32 696 389 2,069 317 

Amazonas 16 24 16 8 2,539 781 2,088 256 

Bahia 1,107 18,206 41,789 6,966 2,877 13,174 16,595 44,016 

Ceara 55 607 1,563 418 49 2,789 755 19,584 

Distrito Federal 0 266 1,108 64 12 96 35 314 

Espirito Santo 217 1,770 6,839 104 90 44 1,456 411 

Goias 1,278 10,095 63,275 1,835 253 1,112 1,718 4,273 

Maranhao 338 1,230 3,548 397 737 1,163 18,568 4,969 

Mato Grosso 996 16,252 49,333 2,863 5,217 3,122 26,670 6,371 

Mato Grosso Do Sul 3,608 15,717 49,598 1,001 2,268 964 6,867 2,190 

Minas Gerais 1,296 10,269 86,582 2,926 1,514 3,990 7,921 14,424 

Para 505 284 1,182 32 2,597 1,211 24,164 928 

Paraiba 102 3,108 5,146 1,103 37 3,708 307 13,367 

Parana 9,786 14,225 46,476 1,598 1,648 253 12,628 1,463 

Pernambuco 486 4,834 8,689 1,444 237 4,204 1,763 18,257 

Piaui 39 391 1,880 402 149 1,802 4,810 10,111 

Rio De Janeiro 59 1,093 15,414 726 88 102 697 429 

Rio Grande Do 

Norte 31 2,091 3,205 698 12 4,137 57 16,006 

Rio Grande Do Sul 4,837 9,379 36,900 760 4,692 2,424 10,941 3,516 

Rondonia 8 54 124 8 1,301 313 9,243 93 

Roraima 24 422 670 268 1,751 2,568 1,735 6,962 

Santa Catarina 898 896 2,819 251 1,742 235 7,967 1,326 

Sao Paulo 4,559 18,143 115,807 3,256 984 444 6,097 2,288 

Sergipe 251 2,271 2,399 315 257 278 473 360 

Tocantins 78 613 3,189 201 1,853 3,177 3,509 7,829 

All 

Brazil 31,375 135,441 552,194 27,990 33,895 52,740 172,259 180,954 

It is important to note that our analysis for the proposed rule treats all acres of crop 

expansion the same in an individual country. This implies that an additional acre of corn in 

Brazil would result in the same land conversion as an additional acre of soybeans or sugarcane in 

Brazil. However, it is possible that different types of crop expansion would occur in different 

regions and thus have different impacts on land conversion. Current areas where corn and 

soybeans are grown in Brazil are largely in the same regions in the south, however, there are 

areas further north where production of soybeans occur as shown in Figures 2.6-19 and 2.6-20, 

377 
indicating that different types of crop production in Brazil would potentially have different 

impacts. 

Figure 2.6-19. Corn Production in Brazil 

378 
Figure 2.6-20. Soybean Production in Brazil 

The impact of this assumption on overall results is somewhat mitigated by the fact that 

each fuel scenario in the U.S., e.g., corn ethanol and soybean biodiesel will result in a mix of 

crop export changes and a mix of crop expansion internationally. For example, increased corn 

ethanol production in the U.S. results in reduced exports of not just corn, but other crops as well, 

due to crop shifting in the U.S. agricultural sector. Also the MODIS satellite data is based on a 

mix of crop expansion in different countries such that it is already reflecting crop expansion in a 

mix of different crops. However, this is an area that will be examined for the final rule analysis. 

2.6.5.3.3 GTAP Approach 

GTAP is an economy-wide general equilibrium model that was originally developed for 

addressing agricultural trade issues among countries. The databases and versions of the model 

are widely used internationally by a large modeling community.535 Since its inception in 1993, 

GTAP has rapidly become a common "language" for many of those conducting global economic 

analysis. For example, the WTO and the World Bank co-sponsored two conferences on the socalled Millennium Round of Multilateral Trade talks in Geneva. Here, virtually all of the 

quantitative, global economic analyses were based on the GTAP framework. Over the past few 

years, a version of the model was developed to explicitly model global competition among 

different land types (e.g., forest, agricultural land, pasture) and different qualities of land based 

on the relative value of the alternative land-uses. More recently, it was modified to include 

biofuel substitutes for gasoline and diesel. In simulating land use changes due to biofuels 

production, GTAP explicitly models land-use conversion decisions, as well as land management 

intensification. For example, it allows for price-induced yield changes (e.g., farmers can 

379 
 

reallocate inputs to increase yields when commodity prices are high) and considers the marginal 

productivity of additional land (e.g., expansion of crop land onto lower quality land as a result of 

the increased use of biofuels). Most importantly, in contrast to other models, GTAP is designed 

with the framework of predicting the amount and types of land needed in a region to meet 

demands for both food and fuel production. The GTAP framework also allows predictions to be 

made about the types of land available in the region to meet the needed demands, since it 

explicitly represents different land types within the model. 

The global modeling of land-use competition and land management decisions is 

relatively new, and evolving.536 GTAP is currently adding cellulosic biofuel feedstocks. In 

addition, GTAP does not currently contain unmanaged land, which could be a major factor 

driving current GTAP land use projections and is a significant potential source of GHG 

emissions. We will continue to consider using GTAP as it develops a more comprehensive 

treatment of biofuel pathways and land supply. 

Our proposal is therefore based on the FAPRI/Winrock estimates. Additional 

refinements will be made to the GTAP model between the proposal and final rule and we plan to 

include information about important developments in the docket as it becomes available. 

2.6.5.4 What Are the GHG Emissions Associated with Different Types of Land Conversion 

2.6.5.4.1 Domestic Land Use Change Emissions 

Domestic land use change GHG emissions are based on outputs of the FASOM model. 

As we are just using the agricultural portion of the FASOM model for this analysis the land use 

change GHG emissions are limited to changes in land use for existing crop and pasture land. 

Some of that crop land could currently be fallow and some of the pasture land could currently be 

unused. However, no new crop or pasture land (beyond some CRP land due to legislative 

changes in the program) are added compared to current levels. Thus FASOM only models shifts 

in the use of this land. 

Changes in the agricultural sector due to increased crops used for biofuels have impacts 

on land use change in a number of ways. FASOM explicitly models change in soil carbon from 

increased crop production acres and from different types of crop production. FASOM also 

models changes in soil carbon from converting non-crop land into crop production. Land 

converted to crop land could include pasture land. 

Land conversion GHG emissions in FASOM include above ground carbon and soil 

carbon changes from land conversion and crop pattern changes. The FASOM land conversion 

factors are based on factors for different crops, management practices, and land conversion 

effects, e.g., converting pasture to crop production. Therefore, FASOM soil carbon changes 

capture not only converting new land into crop but also changes from existing cropland due to 

changing management practices or cropping patterns. As part of the ongoing work with 

Colorado State University we are in the process of updating the soil and land conversion factors 

in FASOM based on new DAYCENT model runs. We plant to include these updates as part of 

the analysis for the final rule. 

380 
2.6.5.4.2 International Land Use Change Emissions 

Land use change emissions factors were calculated by the non-profit organization 

Winrock International following 2006 IPCC AFOLU Guidelines. Winrock’s staff is highly 

regarded for their years of experience and accomplishment in this field, including their work 

with the IPCC to develop the AFOLU Guidelines. For the proposed rule, emissions factors were 

estimated for ten countries including Argentina, Brazil, China, India, Indonesia, Malaysia, 

Mexico, Philippines, EU and South Africa. Emissions factors were based on the initial change in 

biomass stocks as well as changes in soil carbon stocks, non-CO2 emissions from biomass 

burning due to land clearing, and forgone forest sequestration. In general, emission factors for 

all land use types were highest in the Southeast Asian countries of Malaysia, Indonesia and 

Philippines and lowest in Argentina and Nigeria. This section describes the methods used to 

estimate GHG emissions from international land use change. 

2.6.5.4.2.1 Data sources used to estimate land use change GHG emissions factors 

Forest Carbon Stocks: To calculate changes in biomass carbon stocks due to land use 

change, data were compiled at the state level to estimate carbon stocks of various land use types. 

Average forest carbon stocks per administrative unit in each country were extracted from spatial 

data layers developed for various regions of the world. Estimates represent both above- and 

belowground biomass. Data sources for each region are summarized below: 

Argentina: A global map of forest carbon stocks developed by Gibbs et al. (2007) was 

used to estimate forest carbon stocks in Argentina. 

Asia: A map developed by Gibbs and Brown (2007) was used to estimate forest carbon 

stocks in the year 2000 in the Asian countries of Indonesia, Malaysia and Philippines. 

Mexico: A map developed by Harris and Brown (unpublished results) was used to 

estimate forest carbon stocks in Mexico. The map was developed using similar methods 

to the products developed for Asia and Africa by Gibbs and Brown (2007, 2008), where 

potential biomass maps were developed based on various climatic and biophysical factors 

and were then degraded based on population density for the year 2000 to estimate actual 

forest biomass. The biomass estimates were then expanded to account for roots based on 

factors given in Cairns et al. (1997) and then converted to carbon stocks (carbon = 

biomass*0.5). 

South America: A map of aboveground forest biomass was obtained from Saatchi et al. 

(200x), an example of which is shown in Figure 2.6-21. The biomass estimates were first 

expanded to account for roots based on factors given in Cairns et al (1997) and then 

converted to carbon stocks (carbon = biomass*0.5). 

381 
Figure 2.6-21. Example of a Spatial Data Base for Forest Carbon Stocks 

Soil Carbon Emissions: Soil carbon emissions associated with land use change in 

different regions around the world were estimated using global soil carbon maps. A digital soil 

carbon map of the world is available from the U.S. Department of Agriculture, Natural 

Resources Conservation Service, see Figure 2.6-22. This map is based on a reclassification of 

the FAO-UNESCO Soil Map of the World combined with a soil climate map. The map shows 

little variation for soil C in the tropics with most areas showing a range in soil carbon of 40-80 t 

C/ha (4-8 Kg C/m2). The soil organic carbon map shows the distribution of the soil organic 

carbon to 30 cm depth.537 This data layer was chosen because land use change (e.g., tilling for 

cropland conversion) typically affects only the upper layers of the soil profile. 

382 
 a The GIS data product has higher resolution than indicated here in the map (1 kg m-2 = 10 t C ha-1). 

Cropland Carbon Stocks: Carbon stocks on annual cropland were estimated as 5 metric 

Figure 2.6-22. Estimates of Soil Organic Carbon to 30cm Deptha 

tons of carbon per hectare (MT C ha-1), based on Table 5.9 of the IPCC AFOLU. In Malaysia, 

carbon stocks for oil palm and rubber were estimated using values from Table 5.3 of the IPCC 

AFOLU (68 and 89 MT C ha-1, respectively). 

Grassland, Savanna and Shrubland Carbon Stocks: Above- and belowground biomass 

values for grassland, savanna and shrublands were obtained from a variety of sources, see Table 

10-11. Biomass estimates were obtained from de Castro and Kauffman (1998) for the Brazilian 

vegetation gradient that spans campo limpo (pure grassland), campo sujo (a savanna with a 

sparse presence of shrubs), campo cerrado (a dominance of shrubs with scattered trees and a 

grass understory), cerrado sensu stricto (a dominance of trees with scattered shrubs and a grass 

understory) and cerradão (a closed canopy forest) (Coutinho 1978, Eiten 1972, Goodland & 

Pollard 1973). Shrubland carbon stocks were estimated from the average of biomass values 

reported for cerrado aberto and cerrado denso. Savanna carbon stocks were estimated from the 

biomass value reported for campo sujo. Grassland carbon stocks were estimated from the 

biomass value reported for campo limpo. 

Estimating carbon stocks in other countries for the grassland-savanna-shrubland 

continuum was slightly more problematic. For all countries except Brazil (explained in the 

paragraph above), grassland carbon stocks were estimated for each administrative unit as the 

default value given in Table 6.4 of the IPCC AFOLU, where values are given as a function of 

temperature and moisture regime. 

Very few carbon stock estimates were available for savanna and shrubland outside of 

Brazil. Therefore, carbon stocks of these land cover types were estimated using a proportional 

approach based on the Brazil dataset, which indicates an increasing trend in carbon stocks from 

grassland Æ savanna Æ shrubland of 10.9 to 19.7 to 37.3 MT C ha-1, respectively, translating 

into a ratio of 1 to 1.8 to 3.4. These ratios were applied to other countries for estimating carbon 

stocks in savanna and shrubland based on the estimated carbon stocks of grassland within each 

country. One exception to the ratio approach was for the Southeast Asian countries of Indonesia, 

Malaysia and Philippines, where a shrubland biomass value of 85 MT ha-1 (42 MT C ha-1) was 

383 
 

applied based on actual data reported in Grace et al. 2006 for a savanna woodland in Klong Hoi 

Khong, Thailand. 

Table 2.6-33. 

Estimated Carbon Stocks (MT C ha-1) for Grassland, Savanna and Shrubland 

in Each Country Analyzeda
 

Country Grassland Savanna Shrubland 

Brazil 10.9 19.7 37.3 

India 4.1 – 7.6 7.4 – 13.6 13.9 – 25.7 

Malaysia 7.6 13.6 42.0 

Indonesia 7.6 13.6 42.0 

Philippines 7.6 13.6 42.0 

China 7.6 13.6 25.7 

Argentina 2.7 – 6.4 5.1 – 11.5 9.7 – 21.7 

Mexico 4.1 - 7.6 7.4 – 13.6 13.9 – 25.7 

a

 ranges are reported for countries in which carbon stocks varied by state 

2.6.5.4.2.2 Methods for Land Use Change GHG Emissions Factors Estimation 

For each state in each country, emission factors were calculated for various land cover 

conversions using data tables and equations from the 2006 IPCC AFOLU Guidelines and from 

other global data sets. Emission factors account for changes in above- and belowground biomass 

carbon stocks, soil carbon stocks and lost forest sequestration. Non-CO2 emissions were also 

accounted for, including methane (CH4) and nitrous oxide (N2O) emissions resulting from land 

clearing with fire and CH4 emissions resulting from rice cultivation. 

Changes in biomass carbon stocks: Initial changes in biomass carbon stocks on land 

converted to another land category (e.g., from forest to cropland) were calculated based on 

Equation 2.16 in the IPCC AFOLU: 

384 
 

 

 

ΔCCONVERSION = ∑(BAFTER − BBEFORE ) •CF i i 

i 

where: 

ΔCCONVERSION = initial change in biomass carbon stocks on land converted to 

another land category, tonnes C ha-1 yr-1 

BAFTERi = biomass stocks on land type I immediately after the conversion, 

 tonnes d.m. ha-1 

BBEFOREi = biomass stocks on land type I before the conversion, tonnes d.m.

 ha-1 

CF = carbon fraction of dry matter, tonne C (tonnes d.m.)-1 

i = type of land use converted to another land-use category 

Initial changes in biomass carbon stocks reflect gross emissions rather than net emissions; 

harvested wood products, including long-term storage and retirement, were not considered in the 

analysis. Based on consultation with Winrock we determined that including IPCC default GHG 

credits for harvested wood products (HWPs) would have an insignificant impact on our estimates 

of land use change emissions, as there is limited evidence that trees cleared from converted 

forestland is converted to durable wood products. The 2006 IPCC Guidelines for National 

Greenhouse Gas Inventories also states that (p 12.8) the HWP contribution can be reported as 

zero if the annual change in carbon in HWP stocks is judged insignificant. Even if we assumed 

that forestland cleared from Brazil had 10m3 of timber/ha, which is likely an upper bound for 

many of the forests being cleared, this would translate to about 8tCO2/ha, or less than 2% of the 

total emissions from converting forest to cropland. However, we intend to analyze the impact of 

wood product credits for the final rule. 

Winrock provided emissions factors for land conversion to perennial crops, but only 

emissions factors for conversion to annual crops were used for the proposed rule analysis. We 

intend to differentiate between annual and perennial cropland expansion for the final rule. 

Changes in soil carbon stocks: Changes in soil carbon stocks on land converted to 

cropland were calculated based on Section 5.3.3.4 of the IPCC AFOLU. 

Soil carbon stocks after conversion to cropland were based on specific soil stock change 

factors for land use, management and inputs (FLU, FMG, FI, respectively) listed in Table 5.10 of 

the IPCC AFOLU. (Relevant factors are listed in Table 2.6-34 of this report). Stock change 

factors were selected for each land cover type (before and after conversion) and multiplied by 

reference soil carbon stocks. Following the IPCC AFOLU guidelines, the total difference in 

carbon stocks before and after conversion was averaged over 20 years. Thus the average annual 

change in soil carbon stocks due to land use conversion were calculated as: 

385 
 

 

 

(SOCRe f • FLU ,before • FMG,before • FI ,before ) − (SOCRe f • FLU ,after • FMG,after • FI ,after ) ΔSOC = 20 

where: 

ΔSOC = average annual change in carbon stocks in top 30 cm of soil; t C ha-1 yr-1 

SOCRe f = reference carbon stocks in top 30 cm of soil; t C ha-1
 

FLU = land use factor before or after conversion 

FMG = management factor before or after conversion 

FI = input factor before or after conversion 

As default values for stock change factors (FLU, FMG, FI) are all one for forest soils and 

non-degraded grassland soils, soil carbon stocks were assumed to remain unchanged for all 

conversion types (conversion to shrubland, savanna, perennial cropland) except conversion to 

cropland. Full tillage and medium inputs were assumed in all scenarios of cropland conversion. 

Consistent with IPPC default guidelines, soil carbon stock changes were spread equally over 20 

years. 

Table 2.6-34. 

Relative Stock Change Factors (FLU, FMG, FI) for Different Management Activities Based 

on Tables 5.5 and 5.10 in 2006 IPCC AFOLU 

Factor value 

type Level 

Temperature 

Regime 

Moisture 

Regime 

IPCC 

default 

Land use (FLU) 

Native forest or 

grassland (nondegraded) All All 1 

Dry 0.8

Temperate/Boreal Moist 0.69 

Land use (FLU) Long-term 

cultivated Tropical Dry 0.58 

Moist/Wet 0.48 

Tropical montane n/a 0.64 

Land use (FLU) Paddy rice All All 1.1 

Land use (FLU) Perennial/tree crop All All 1 

Tillage (FMG) Full All All 1 

Input (FI) Medium All All 1 

Peat soil drainage: Winrock provided emissions factors for peat drainage for countries 

where that is likely to occur, such as Indonesia, and Malaysia. However, emissions from peat 

soil were not included in our analysis for the proposed rule. Below is a description of the 

386 
methodology Winrock used to provide factors for peat drainage, which we intend to use for the 

final rule. 

For countries containing peat (organic) soils, emission factors were chosen that accounted 

for annual losses of CO2 due to peat drainage. Emission factors were based on a regional dataset 

from Southeast Asia that correlates peat drainage depth with annual peat CO2 emissions. 

Emission factors were estimated using this regional dataset rather than basing them on climate 

type (Table 5.6 of the IPCC AFOLU) because all countries included in the analysis that 

contained peat soils were located in Southeast Asia. Thus the use of regional data was 

appropriate. The emission factor for drained organic soils was estimated based on the following 

equation (from Hooijer et al. 2006): 

Y = 0.91X 

where: 

Y = CO2 emissions from drained peat, MT CO2 ha-1 yr-1 

X = drainage depth, cm 

Drainage depth was assumed as 80 centimeters, which is the minimum likely peat 

drainage estimate for conversion to croplands cited in Hooijer et al. (2006). Thus the annual 

emission factor from drained peat soils was estimated as 80 x 0.91 = 72.8 MT CO2 ha-1 yr-1. 

Emission factors for draining peat soils were estimated for land use conversions 

originating from forest and grassland only, based on the assumption that in Southeast Asia, the 

only land cover types on peat are intact or degraded peat swamp forest or already drained and 

deforested peatland that has revegetated to Imperata grasslands. 

Lost forest sequestration: Over time, trees sequester carbon dioxide from the atmosphere 

and accumulate carbon as biomass. When forests are converted to another land use, the trees that 

would have continued to grow are cut down and no longer act as carbon sinks. Therefore, each 

year after a land use conversion has occurred the carbon that would have been sequestered in the 

growing trees is “lost”. In an avoided emissions scenario, carbon benefits can be generated not 

only from preventing the immediate loss of biomass carbon stocks, but also from allowing 

carbon to accumulate over time in the vegetation that would have been cleared. 

Average annual biomass accumulation rates are given in Table 4.9 of the 2006 GL 

AFOLU and are specified according to ecological zone and continent. These values were used to 

estimate the lost biomass accumulation of forests that were converted to another land use (Table 

2.6-36). Average values were used where a range of values is listed. Lost carbon accumulation 

was then assumed equal to the biomass accumulation value multiplied by the carbon fraction in 

dry matter (IPCC default = 0.47). 

The area of forest in each state was stratified by FAO ecozone and continent, and 

appropriate values from Table 2.6-30 were applied to calculate an average area-weighted value. 

As biomass accumulation rates in Table 4.9 of the 2006 GL AFOLU are separated into rates for 

forests less than and greater than a 20 year threshold, in this analysis all forests that were being 

converted were assumed to be >20 years in age. The average annual foregone sequestration is 

calculated as: 

387 
 

 

 

 

ΔClostseq = ∑(Cseq LUbefore i , −Cseq LUafter i , )
 i
 

where: 

lostseq ΔC -1 = change in carbon sequestration in aboveground biomass; MT C ha-1 yr

Cseq LUbefore i , = annual sequestration in aboveground biomass before conversion; MT C ha1 -1 yr

Cseq LUafter i , = annual sequestration in aboveground biomass after conversion MT 

C ha-1 yr-1 

i = type of land use converted to another land use category. 

Studies have estimated that new forests grow for 90 years to over 120 years.UUUUUUU 

More recent estimates suggest that old growth forests accumulate carbon for up to 800 

VVVVVVV years. For this analysis we assumed that foregone sequestration would continue for 80 

years, which is within the range supported by the scientific literature and the 2006 IPCC 

guidelines. Section 2.8 presents a sensitivity analysis of the length of foregone sequestration 

assumed. 

UUUUUUU See Greenhouse Gas Mitigation Potential in U.S. Forestry and Agriculture, EPA Document 430-R-05-006 

for a discussion of the time required for forests to reach carbon saturation. VVVVVVV Luyassert, S et al., 2008. Old-growth forests as global carbon sinks. Nature 455: 213-215. 

Link: http://www.nature.com/nature/journal/v455/n7210/abs/nature07276.html 

388 
Table 2.6-35. 

Aboveground Net Biomass Growth in Natural Forests 

From Table 4.9 in IPCC AFOLU 

Aboveground biomass 

Ecological growth (tonnes d.m. 

Domain Zone Continent ha-1 yr-1) 

Africa 3.1 

South America 3.1 

Tropical rain Asia (continental) 2.2 

forest Asia (insular) 3.4 

Africa 1.3 

Tropical moist South America 2.0 

deciduous Asia (continental) 2.0 

forest Asia (insular) 3.0 

Africa 1.8 

Tropical Tropical dry 

South America 1.0 

Asia (continental) 1.5 

forest Asia (insular) 2.0 

Africa 0.9 

South America 1.0 

Tropical Asia (continental) 1.3 

shrubland Asia (insular) 1.0 

Africa 1.0 - 1.5 

Tropical South America 0.4 - 1.4 

mountain Asia (continental) 0.5 - 1.0 

systems Asia (insular) 1.0 - 3.0 

North and South America 2.0 

Subtropical Asia (continental) 2.0 

humid forest Asia (insular) 3.0 

Africa 1.8 

North and South America 1.0 

Subtropical dry Asia (continental) 1.5 

forest Asia (insular) 2.0 

Sub-tropical Africa 0.9 

North and South America 1.0 

Subtropical Asia (continental) 1.3 

steppe Asia (insular) 1.0 

Africa 0.2 - 1.6 

Subtropical North and South America 0.4 - 1.4 

mountain Asia (continental) 1.0 - 2.2 

systems Asia (insular) 1.0 

Temperate 

continental Asia, Europe, North 

forest America 0.5 - 7.5 

Temperate 

Temperate 

mountain 

systems 

Asia, Europe, North 

America 0.5 - 6.0 

Boreal 

coniferous Asia, Europe, North 

forest America 0.1 - 2.1 

Boreal tundra Asia, Europe, North 

woodland America 0.4 

Boreal Boreal 

mountain 

systems 

Asia, Europe, North 

America 1.0 - 1.1 

Non-CO2 emissions from land clearing: In countries where fire is used commonly as a 

land clearing practice for conversion to agriculture, non-CO2 emissions were estimated using 

389 
 

emission factors in Table 2.5 and Equation 2.27 of the IPCC AFOLU. Fire for land clearing was 

assumed to occur in all countries included in the analysis except China and Argentina. 

Non-CO2 emissions from land clearing with fire were estimated as: 

Lfire = A • M B •Cf • Gef •10−3 

Where: 

L fire = amount of greenhouse gas emissions from fire, MT of each GHG (i.e., 

CH4, N2O)
 

A = area burnt, ha 

M B
 = mass of fuel available for combustion, MT ha-1. 

Cf = combustion factor, dimensionless 

Gef = emission factor, g kg-1 dry matter burnt 

The mass of fuel available for combustion was conservatively assumed to be equal to the 

above- and belowground biomass only; dead wood and litter pools were not included in the fuel 

load estimates. 

IPCC defaults were used for the forest combustion factor. Values from de Castro and 

Kaufmann (1998) were used for clearing other land cover types (grassland, savanna, shrubland). 

Combustion factors and emission factors used in this analysis are summarized in Table 2.6-36 

and 2.6-37 respectively. 

Table 2.6-36. 

Combustion Factor Values (Proportion of Pre-Fire Fuel Biomass Consumed) 

for Fires in a Range of Vegetation Types 

Vegetation Type Subcategory Value 

Primary tropical 

forest (slash and 

burn) 

Primary tropical forest 0.32 

Primary open tropical 

forest 0.45 

Primary tropical moist 

forest 0.5 

Primary tropical dry 

forest -

All primary tropical forests 0.36 

Shrubland 0.43 

Savanna 0.84 

Grassland 0.92 

390 
 

 

Table 2.6-37. 

Emission Factors (g kg-1 Dry Matter Burnt) Used in This Analysis 

for Biomass Burning From Table 2.5 of IPCC AFOLU 

Category CO2 N2O 

Savanna and grassland 1613 0.21 

Tropical forest 1580 0.2 

Extra tropical forest 1569 0.26 

2.6.5.4.2.3 Integrated Emissions Factors for Land Use Change 

In summary, emissions factors were estimated for each state for each land use conversion 

as metric tonnes CO2 equivalent. All non-CO2 estimates were converted using IPCC SAR GWP 

factors: 

EF LUC biomass = ΔC ,LUC + ΔC soil ,LUC + ΔC lost _ seq + E + E ,LUC fire LUC , rice ,LUC

where: 

EFi = emission factor for converting one hectare of land to land use LUC; 

ΔCbiomass ,LUC = change in biomass carbon stocks as a result of land use change LUC; 

ΔCsoil ,LUC = change in soil carbon stocks (top 30 cm) as a result of land use change 

LUC; 

ΔClost _ seq , LUC = lost forest sequestration resulting from land use change (if applicable); 

E fire,LUC = non-CO2 GHG emission associated with land clearing with fire (if 

applicable); 

The per hectare emissions factors used for the proposed rule are presented in Table 2.6­

34. The emissions factors in Table 2.6-38 are weighted by where land conversions are likely to 

take place within each country, based on the MODIS satellite data discussed above. For 

example, the forest to cropland emissions factor for Brazil is weighted by where forest was 

converted to cropland in Brazil from 2001 to 2004. The MODIS satellite data suggests that in 

Brazil forest to grassland conversion tends to occur in regions with more carbon-rich forests than 

the areas that have more forest to cropland conversion. This explains why, for example, the 

Brazil per hectare emissions factor for forest to grassland conversion is greater than the factor for 

forest to cropland conversion. The emissions factors in Table 2.6-34 are undiscounted emissions 

over 80 years. 

As depicted in Figure 2.6-14 for Brazil, the per hectare emissions factors in Table 2.6-38 

were weighted by the shares of land types converted to cropland, and by the types of land cleared 

to replace pasture converted to cropland. With the weighting approach discussed above, we 

derived land use change emissions factors per hectare of cropland expansion. Table 2.6-39 

includes the country-level weighted average emissions factors (WAEFs) per hectare of cropland 

expansion that were used for the proposed rule central estimate. The WAEFs in Table 2.6-39 are 

undiscounted emissions over 80 years. 

391 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table 2.6-38. 

Regional Land Conversion GHG Emissions Factors 

Undiscounted Emissions Over 80 Years 

(MTCO2-eq. / acre)
 

Country / 

Region To 

From 

Forest Grassland Savanna Shrub 

Crop 115 16 17 33 

Argentina Grassland 136 15 

Savanna 129 9 

Crop 258 45 60 82 

Brazil Grassland 257 39 

Savanna 240 26 

Crop 237 23 34 49 

China Grassland 186 27 

Savanna 240 27 

Crop 318 28 38 47 

European Union Grassland 216 22 

Savanna 181 14 

Crop 247 26 26 38 

India Grassland 249 249 

Savanna 236 12 

Crop 432 43 51 94 

Indonesia Grassland 455 51 

Savanna 415 42 

Crop 473 50 57 103 

Malaysia Grassland 457 51 

Savanna 438 42 

Crop 96 18 23 78 

Nigeria Grassland 92 58 

Savanna 112 28 

Crop 402 34 44 88 

Philippines Grassland 371 51 

Savanna 359 42 

Crop 111 18 36 79 

South Africa Grassland 109 58 

Savanna 86 47 

392 
Table 2.6-39. 

Regional Weighted Average Emissions Factors (WAEF) 

(MTCO2-eq. per acre of crop expansion)
 

Country / 

Region 

Crop 

Expansion 

Pasture 

Replacement 

Total 

WAEF 

Argentina 25 34 60 

Brazil 66 76 142 

China 68 45 113 

European Union 106 41 147 

India 48 33 81 

Indonesia 182 60 242 

Malaysia 367 93 461 

Nigeria 25 31 56 

Philippines 219 170 389 

South Africa 47 32 79 

2.6.5.4.2.3.4 What Are the Total GHG Emissions Associated With International Land Use 

Change 

To determine the GHG impacts of the land use changes we applied GHG emissions 

factors based on data prepared by Winrock to the land use changes projected by the combination 

of FAPRI and satellite data. Table 2.6-39 shows our emissions factors for ten countries. The ten 

countries we have emissions factors for account for a majority of foreign cropland expansion 

projected by FAPRI. Table 2.6-40 shows the share of projected cropland expansion in these ten 

countries in the FAPRI fuel-specific scenarios. We are in the process of acquiring data for more 

countries to be used for the final rule. 

Table 2.6-40. 

Share of Projected Foreign Crop Expansion Covered by 

Proposed Rule Winrock/MODIS Data
 

Fuel-Specific Scenario Share of 2022 Crop Expansion Covered 

Corn Ethanol 63% 

Soy-Based Biodiesel 87% 

Imported Sugarcane Ethanol 53% 

Switchgrass Ethanol 57% 

Note: Winrock/MODIS data covers Argentina, Brazil, China, EU, India, Indonesia, Malaysia, Nigeria, Philippines 

and South Africa 

We used a weighted average emissions factor (WAEF) from the ten countries we have 

Winrock data for to estimate the GHG emissions from cropland expansion in countries not 

covered by Winrock data. The country-level shares of crop expansion varied by fuel-specific 

scenario, so the WAEF applied to missing countries also varied by scenario. Table 2.6-41 shows 

the WAEF used for missing countries for each scenario. The WAEF for missing countries is 

highest for the soy biodiesel scenario because FAPRI projects that U.S. soy biodiesel 

consumption encourages crop expansion in tropical countries with very large emissions factors 

for crop expansion, such as Malaysia and Philippines. Crop expansion in these South East Asian 

393 
 

 

 

oil palm exporting countries is large in the soy biodiesel scenario, because oil palm is a substitute 

for soy oil. 

Table 2.6-41. 

Weighted Average Emissions Factors (WAEFs) Applied to Countries without 

Winrock/MODIS Data 

Fuel-Specific Scenario 

Regions Covered by 

Winrock/MODIS 

Corn 

Ethanol 

Soy-Based 

Biodiesel 

Sugarcane 

Ethanol 

Switchgrass 

Ethanol 

Share of 

crop 

expansion 

by region 

Argentina 4% 2% 13% 7% 

Brazil 27% 64% 33% 17% 

China 10% 2% 7% 13% 

E.U. 6% 1% -3% 5% 

India 24% 5% 24% 31% 

Indonesia 5% 1% 6% 3% 

Malaysia 0% 0% 6% 0% 

Nigeria 20% 27% 12% 21% 

Philippines 3% 0% 2% 2% 

South Africa 3% -1% 1% 1% 

WAEF applied to missing 

regions (MTCO2-eq. / acre 

crop expansion) 114 117 132 104 

Figure 2.6-23 shows results for 2022 total undiscounted land use change GHG emissions 

over 80 years per million Btu of renewable fuel. 

Figure 2.6-23. Total Land Use Change GHG Emissions by Scenario 

Undiscounted GHG Emissions Over 80 Years 

(MTCO2-eq. / mmBtu) 

2.53 

3.25 

2.26 

0.56 

0.00 

0.50 

1.00 

1.50 

2.00 

2.50 

3.00 

3.50 

GHG Emissions (MTCO2-eq. / mmBtu) 

Corn Ethanol Soy-Based Biodiesel Sugarcane Ethanol Switchgrass Ethanol 

394 
2.6.5.5 Timing of GHG Emissions 

When comparing the lifecycle GHG emissions associated with biofuels to those 

associated with gasoline or diesel emissions, it is critical to take into consideration the time 

profile associated with each fuel’s GHG’s emissions stream. With gasoline, a majority of the 

GHG emissions associated with extraction, conversion, and combustion are likely to be released 

over a short period of time (i.e., annually) as crude oil is converted into gasoline or diesel fuel 

which quickly pass to market. 

In contrast, the GHG emissions from the production of a typical biofuel (e.g., corn-based 

ethanol) may continue to occur over a long period of time. As with petroleum based fuels, GHG 

emissions are associated with the conversion and combustion of biofuels in every year they are 

produced. In addition, GHG emissions could be released through time if new acres are needed to 

produce corn or other crops for biofuels. The GHG emissions associated with converting land 

into crop production would accumulate over time with the largest release occurring in the first 

few years due to clearing with fire or biomass decay. After the land is converted, moderate 

amounts of soil carbon would continue to be released for approximately 20 years. Furthermore, 

there would be foregone sequestration associated with the fact that the forest would have 

continued to sequester carbon had it not been cleared for approximately 80 years (See Figure 2.6­

24). 

Figure 2.6-24. 

Timing of International Land Use Change Emissions in Corn Ethanol Scenario 

(gCO2-eq. / mmBtu) 

International Land Use Change Emissions
 1,200,000
 

1,000,000 

GHG Emissions (gCO2-eq / mmBtu) 

800,000 

600,000 

400,000 

200,000 

0 

Year 0 Emissions: 

- Clearing with fire 

- Biomass decay 

- Soil carbon emissions 

- Foregone 

sequestration 

Year 1-19 Emissions: 

- Soil carbon emissions 

- Foregone 

sequestration Year 20-79 Emissions: 

- Foregone sequestration 

2022203020402050 

While biomass feedstocks grown each year on new cropland can be converted to biofuels 

that offer an annual GHG benefit relative to the petroleum product they replace, these benefits 

may be small compared to the upfront release of GHG emission. Depending on the specific 

395 
biofuel in question, it can take many years for the benefits of the biofuel to make up for the large 

initial releases of carbon that result from land conversion (e.g., the payback period). 

As required by EISA, our analysis must demonstrate whether biofuels reduce GHG 

emissions by the required amount relative to the 2005 petroleum baseline. A payback period 

alone cannot answer that question. Since the payback period is not sufficient for our analysis, we 

have developed methods for capturing the stream of emissions and benefits over time. For our 

analytical purposes, it is important for us to determine how the time profiles of emission releases 

of different fuels compare. It is useful to have a unitary metric that allows for a direct 

comparison of biofuels compared to gasoline or diesel, which requires an accounting system for 

GHG emissions over time. When considering the time profile of GHG emissions, the two 

assumptions that have a significant impact on the determination of whether a biofuel meets the 

emissions reduction threshold include: 1) the time period considered and 2) the discount rate we 

apply to future emissions. The preamble to the proposed rule presents results using a 100-year 

time horizon and a 2% discount rate, as well as results with a 30-year time horizon and a 0% 

discount rate. The preamble includes a discussion of the important factors to consider when 

choosing a time horizon and discount rate. In Section 2.8, we present lifecycle GHG results 

using a variety of time horizons and discount rates. 

2.6.6 Feedstock Transport 

The GHG impacts of transporting biofuel feedstock from the field to the biofuel facility 

and transporting co-products from the biofuel facility to the point of use were included in this 

analysis. The GREET default of truck transportation of 50 miles was used to represent corn and 

soybean transportation from farm to plant. This includes 10 miles from farm to stacks and 40 

miles from stacks to plant. Transportation assumptions for DGs transport were 14% shipped by 

rail 800 miles, 2% shipped by barge 520 miles, and 86% shipped by truck 50 miles. The percent 

shipped by mode was from data provided by USDA and based on Association of American 

Railroads, Army Corps of Engineers, Commodity Freight Statistics, and industry estimates. The 

distances DGs were shipped were based on GREET defaults for other commodities shipped by 

those transportation modes. Default GREET assumptions were also used for cellulosic ethanol 

feedstock transport. Crop residues, switchgrass and forest wastes were all assumed to be shipped 

by truck from point of production to plant. Crop residue distance shipped was 30 miles, 

switchgrass distance was 40 miles, and forest waste was 75 miles. 

The GHG emissions from transport of feedstock and co-product are based on GREET 

default emission factors for each type of vehicle including capacity, fuel economy, and type of 

fuel used. 

As part of this rulemaking analysis we have conducted a more detailed analysis of biofuel 

production locations and transportation distances and modes of transport used in the criteria 

pollutant emissions inventory calculations described in DRIA Chapter 1.6 and for the cost 

analysis of this rule described in DRIA Chapter 4.2. Given the timing of when the current 

analysis was completed we were not able to incorporate this updated transportation information 

into our lifecycle analysis but plan to do that for the final rule. 

396 
Furthermore, the transportation modes and distances assumed for corn and DGs do not 

account for the secondary or indirect transportation impacts. For example, decreases in exports 

will reduce overall domestic agricultural commodity transport and emissions but will increase 

transportation of commodities internationally. We plan to consider these secondary 

transportation impacts in our final rule analysis. 

2.6.7 Biofuel Production 

The GHG emissions associated with the processing of renewable fuels is dependent on a 

number of assumptions and varies significantly based on a number of key variables. For 

example, for corn ethanol the ethanol yield impacts the total amount of corn used and associated 

agricultural sector GHG emissions. The amount of DGs and other co-products produced will 

also impact the agricultural sector emissions in terms of being used as a feed replacement. 

Finally the energy used by the ethanol plant will result in GHG emissions, both from producing 

the fuel used and through direct combustion emissions. The following sections outline the 

assumptions used to model biofuel production for different feedstocks and fuel pathways. 

In each case, the GHG emissions from renewable fuel production are calculated by 

multiplying the Btus of the different types of energy inputs by emissions factors for combustion 

of those fuel sources. The emission factors for the different fuel types are from GREET and are 

based primarily on assumed carbon contents of the different process fuels. The emissions from 

producing electricity are also taken from GREET and represent average U.S. grid electricity 

production emissions. The emissions from combustion of biomass fuel source are not assumed 

to increase net atmospheric CO2 levels. Therefore, CO2 emissions from biomass combustion as a 

process fuel source are not included in the lifecycle GHG inventory of the biofuel production 

plant. 

2.6.7.1 Corn Ethanol 

The two basic methods for producing ethanol from corn are dry milling and wet milling. 

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). 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. 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. 

For this analysis the amount of corn used for ethanol production as modeled by the 

FASOM and FAPRI models was based on yield assumptions built into those two models. 

Assumptions were ethanol yields of 2.71 gallons per bushel for dry mill plants and 2.5 gallons 

per bushel for wet mill plants (yields represents pure ethanol). 

As mentioned above, in traditional lifecycle analyses, the energy consumed and 

emissions generated by a renewable fuel plant must be allocated not only to the renewable, but 

also to each of the by-products. However, for corn ethanol production, this analysis accounts for 

397 
 

the DGs and other co-products use directly in the FASOM and FAPRI agricultural sector 

modeling described above. DGs are considered a partial replacement for corn and other animal 

feed and thus reduce the need to make up for the corn production that went into ethanol 

production. Since FASOM takes the production and use of DGs into account, no further 

allocation was needed at the ethanol plant and all plant emissions are accounted for here. 

In terms of the energy used at renewable fuel facilities, there is a lot of variation between 

plants based on the process type (e.g., wet vs. dry milling) and the type of fuel used (e.g., coal vs. 

natural gas). There can also be variation between the same type of plants using the same fuel 

source based on the age of the plant and types of processes included, etc. For our analysis we 

considered different pathways for corn ethanol production. Our focus was to differentiate 

between facilities based on the key differences between plants, namely the type of plant and the 

type of fuel used. One other key difference we modeled between plants was the treatment of the 

co-products DGs. One of the main energy drivers of ethanol production is drying of the DGs. 

Plants that are co-located with feedlots have the ability to provide the co-product without drying. 

This has a big enough impact on overall results that we defined a specific category for wet vs. 

dry co-product. One additional factor that appears to have a significant impact on GHG 

emissions is corn oil fractionation from DGs. Therefore, this category is also broken out as a 

separate category in the following section. See DRIA Chapter 1.4 for a discussion of corn oil 

fractionation. 

Furthermore, as our analysis was based on a future timeframe, we modeled future plant 

energy use to represent plants that would be built to meet requirements of increased ethanol 

production, as opposed to current or historic data on energy used in ethanol production. The 

energy use at dry mill plants was based on ASPEN models developed by USDA and updated to 

reflect changes in technology out to 2022 as described in DRIA Chapter 4.1. The modeling 

provided energy use for the different types of dry mill ethanol plants as shown in Table 2.6-41. 

398 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table 2.6-41. Energy Use at Ethanol Plants (Btu/gal) 

Type Technology NG Use Coal Use Biomass Use 

Purchased 

Elec 

Corn Ethanol – Dry 

Mill NG Near Term Technology (dry DDGS) 33,032 2,660 

2022 Base Plant (dry DDGS) 28,660 2,251 

2022 Base Plant w/ CHP (dry DDGS) 30,898 512 

2022 Base Plant w/ CHP and Fractionation (dry DDGS) 22,014 714 

2022 Base Plant w/ CHP, Fractionation and Membrane 

Seperation (dry DDGS) 17,994 714 

2022 Base Plant w/ CHP, Fractionation, Membrane 

Seperation, and Raw Starch Hydrolysis (dry DDGS) 13,408 714 

2022 Base Plant (wet DGS) 17,081 2,251 

2022 Base Plant w/ CHP (wet DGS) 19,320 512 

2022 Base Plant w/ CHP and Fractionation (wet DGS) 15,594 714 

2022 Base Plant w/ CHP, Fractionation and Membrane 

Seperation (wet DGS) 11,574 714 

2022 Base Plant w/ CHP, Fractionation, Membrane 

Seperation, and Raw Starch Hydrolysis (wet DGS) 8,841 714 

Corn Ethanol – Dry 

Mill Coal 2022 Base Plant (dry DDGS) 35,824 2,694 

2022 Base Plant w/ CHP (dry DDGS) 39,407 205 

2022 Base Plant w/ CHP and Fractionation (dry DDGS) 28,301 447 

2022 Base Plant w/ CHP, Fractionation and Membrane 

Seperation (dry DDGS) 23,276 447 

2022 Base Plant w/ CHP, Fractionation, Membrane 

Seperation, and Raw Starch Hydrolysis (dry DDGS) 17,545 447 

2022 Base Plant (wet DGS) 21,351 2,694 

2022 Base Plant w/ CHP (wet DGS) 24,934 205 

2022 Base Plant w/ CHP and Fractionation (wet DGS) 20,277 447 

2022 Base Plant w/ CHP, Fractionation and Membrane 

Seperation (wet DGS) 15,252 447 

2022 Base Plant w/ CHP, Fractionation, Membrane 

Seperation, and Raw Starch Hydrolysis (wet DGS) 11,836 447 

Corn Ethanol – Dry 

Mill Biomass 2022 Base Plant (dry DDGS) 35,824 2,694 

2022 Base Plant w/ CHP (dry DDGS) 39,407 205 

2022 Base Plant w/ CHP and Fractionation (dry DDGS) 28,301 447 

2022 Base Plant w/ CHP, Fractionation and Membrane 

Seperation (dry DDGS) 23,276 447 

2022 Base Plant w/ CHP, Fractionation, Membrane 

Seperation, and Raw Starch Hydrolysis (dry DDGS) 17,545 447 

2022 Base Plant (wet DGS) 21,351 2,694 

2022 Base Plant w/ CHP (wet DGS) 24,934 205 

2022 Base Plant w/ CHP and Fractionation (wet DGS) 20,277 447 

2022 Base Plant w/ CHP, Fractionation and Membrane 

Seperation (wet DGS) 15,252 447 

2022 Base Plant w/ CHP, Fractionation, Membrane 

Seperation, and Raw Starch Hydrolysis (wet DGS) 11,836 447 

Corn Ethanol – Wet 

Mill Plant with NG 45,950 

Plant with coal 45,950 

Plant with biomass 45,950 

399 
2.6.7.2 Biodiesel 

Two scenarios for biodiesel production were considered, one utilizing soybean oil as a 

feedstock and one using yellow grease. 

For the soybean oil scenario, the energy use and inputs for the biodiesel production 

process were based on a model developed by USDA and used by EPA in the cost modeling of 

soybean oil biodiesel including crushing, as discussed in Chapter 4. Soybean crushing was 

modeled assuming yields of 11.2 lbs soybean oil/bu soybeans and energy use of 14,532 Btu of 

natural gas and 2,740 Btu of purchased electricity per gallon of biodiesel produced. 

Similar to the case with corn ethanol co-products, we analyze the aggregate GHG 

emissions from soybean crushing and transesterification that occur as a result of increased 

demand for a particular biofuel. Therefore, any increase in soybean meal or soybean oil 

produced as a result of larger biodiesel volumes would take into account GHG emissions 

reductions from a decrease in the production of other feed and vegetable oil substitutes from our 

FASOM modeling. 

Biodiesel is produced through the transesterification process where vegetable oil 

(triglyceride) is reacted with an alcohol (e.g., methanol) and a catalyst (e.g., sodium hydroxide) 

to produce biodiesel and glycerin. Soybean biodiesel transesterification was modeled assuming 

yields of one kilogram of biodiesel from a kilogram of soybean oil and energy use of 5,559 Btu 

of natural gas and 340 Btu of purchased electricity per gallon of biodiesel produced. 

For the yellow grease case, no soybean agriculture emissions or energy use was included. 

Soybean crushing natural gas use was included as a surrogate for yellow grease processing 

(purification, water removal, etc.). Also, due to additional processing requirements, the energy 

use associated with producing biodiesel from yellow grease is higher than for soybean oil 

biodiesel production. The energy use for yellow grease biodiesel production was assumed to be 

1.7 times the energy used for soybean oil biodiesel and yields of 0.94 kilograms of biodiesel 

from a kilogram of yellow grease. 

GHG emissions from other biodiesel production raw material inputs were also included 

in the analysis. HCl, methanol, NaOCH3 and sodium hydroxide are used in the production of 

biodiesel and GHG emissions from producing the raw material inputs were also added to the 

model. Table 2.6-42 shows the values that were used to convert raw material inputs into GHG 

emissions used in the anlaysis. 

Table 2.6-42. 

Lifecycle Factors for Biodiesel Raw Material Production 

Factor Unit Methanol 

Sodium 

Methoxide 

Sodium 

Hydroxide HCl 

CO2 g/g 0.401 0.966 0.923 1.011 

CH4 g/g 0.003 0.002 0 0 

N2O g/g 3.9E-06 2.5E-06 0 0 

Total Energy Btu/g 19.05 24.10 9.67 9.35 

400 
2.6.7.3 Cellulosic Ethanol 

Cellulosic ethanol can be produced through two main types of production processes, 

either fermentation or gasification. The fermentation option is mainly used for homogeneous 

feedstock sources like farmed trees, switchgrass and corn stover whereas the gasification option 

is recommended for more heterogeneous sources like forestry waste. 

As discussed in Chapter 1, we have worked with NREL to generate models of cellulosic 

ethanol production. NREL has estimates for plants that were assumed to be in operation in the 

near-future (2010) and future (2015 and 2022). Currently NREL has generated results for a corn 

stover ethanol fermentation plant. We have used this to represent both corn stover and 

switchgrass ethanol production. The modeling assumes 78,378 Btu of biomass and 118 Btu of 

diesel fuel is required per gallon of ethanol produced. Process energy is assumed to be generated 

through the unfermentable portion (mainly lignin) of incoming biomass being burned for 

electricity production. The process is assumed to generate 8,053 Btu of excess electricity per 

gallon of ethanol produced. 

The benefit of electricity generation is the possibility of lowering greenhouse gas 

emissions by offsetting other forms of electricity production. This is captured in our analysis by 

assuming that the excess electricity produced by the ethanol plant will offset U.S. grid electricity 

production. Therefore, GHG emissions from U.S. grid electricity are calculated for the amount 

of excess electricity produced based on GREET defaults for electricity production and subtracted 

from the lifecycle results of cellulosic ethanol production. 

We are also examining ways to incorporate this excess electricity co-product offset 

evaluation in our secondary energy sector modeling with the NEMS model. This would be more 

consistent with our treatment of corn ethanol and biodiesel co-products where we expand the 

system boundaries to include the specific use of the co-products in an economic sector model. 

We will be examining this approach for or final rule analysis. 

2.6.7.4 Brazilian Sugarcane Ethanol 

Processing energy use for sugarcane ethanol was modeled similar to cellulosic ethanol in 

that it can produce excess electricity from burning bagasse. The assumption was that Brazilian 

sugarcane ethanol would produce 1.78 kWh of excess electricity per gallon of ethanol produced. 

The excess electricity from ethanol production was assumed to offset Brazilian grid electricity to 

calculate GHG emissions savings. 

2.6.8 Fuel Transport 

The default values in GREET for ethanol transportation and modes were used to 

represent transport of ethanol from the plant to the retail location. These default values are 

shown in Table 2.6-42. 

401 
Table 2.6-42. GREET Ethanol Transportation Input Data 

Mode Plant to Terminal Terminal to Station 

% Distance 

(miles) 

% Distance 

(miles) 

Barge 8% 520 0% 

Pipeline 63% 400 0% 

Rail 29% 800 0% 

Truck 0% 100% 30 

Typically if ethanol facilities are located within 100-200 miles of a terminal, trucking is 

preferred. Rail and barge are used for longer distances. Pipelines are not currently used to 

transport ethanol and are not projected to play a role in ethanol transport in the future time frame 

considered. 

For biodiesel transport, the values assumed in the RFS1 analysis were used to represent 

biodiesel transport. The assumptions were 22% of biodiesel shipped by barge and 78% shipped 

by rail. The GREET default distances for biodiesel rail and barge transport as well as terminal to 

station assumptions are consistent with ethanol transportation and distribution assumptions and 

were used in this analysis. 

As with feedstock transport we have conducted a more detailed analysis of fuel transport 

and distribution impacts for use in criteria pollutant inventories (see DRIA Chapter 1.6) and for 

our cost analysis described in DRIA Chapter 4.2. Due to the timing of this analysis we were not 

able to incorporate the results in our lifecycle calculation but plan to do that for the final rule. 

2.7 Tailpipe Combustion 

Combustion CO2 emissions for ethanol, biomass-based diesel, petroleum diesel and 

gasoline were based on the carbon content of the fuel. However, over the full lifecycle of the 

fuel, the CO2 emitted from 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. Net carbon fluxes from changes 

in biogenic carbon reservoirs in wooded or crop lands are accounted for separately in the land 

use change analysis as outlined in the agricultural sector modeling above. 

When calculating combustion GHG emissions, however, the CH4 and N2O emitted 

during biomass-based fuels combustion are included in the analysis. Unlike CO2 emissions, the 

combustion of biomass-based fuels does result in net additions of CH4 and N2O to the 

atmosphere. Therefore, combustion CH4 and N2O emissions are included in the lifecycle GHG 

emissions results for biomass-based fuels. 

Combustion related CH4 and N2O emissions for both biomass-based fuels and petroleumbased fuels are based on EPA MOVES model results. The values used are shown in Table 2.7-1. 

CO2 emissions from biofuels are shown for illustrative reasons, but as mentioned above are not 

402 
 

included in the analysis because they are assumed to be offset by carbon uptake from plant 

growth. 

Table 2.7-1. 

Tailpipe Combustion Emissions for Bio and Petroleum Based Fuels 

CO2 CH4 N2O 

Fuel Type (g/mmBtu) (g/mmBtu) (g/mmBtu) 

Ethanol 75,250 269 611 

Biodiesel 81,044 11 689 

Gasoline 77,567 67 1,659 

Diesel Fuel 78,761 11 689 

2.8 Fuel-Specific Lifecycle Greenhouse Gas Emissions Results 

2.8.1 Renewable Fuel Payback Periods and Lifecycle GHG Emissions Results 

In this section we present detailed lifecycle GHG analysis results, including the results of 

sensitivity and scenario analyses on key assumptions. As discussed above, to implement the 

EISA the crucial result that determines which renewable fuel pathways qualify for RFS2 credits 

is the percent reduction in lifecycle GHG emissions compared to the average lifecycle 

greenhouse gas emissions for gasoline or diesel sold or distributed as transportation fuel in 2005. 

To compare lifecycle GHG emissions from renewable fuels and petroleum, we present the grams 

of CO2-equivalent emissions per Btu of fuel produced (gCO2eq/mmBtu). The previous sections 

in this Chapter discussed our methodology for calculating lifecycle GHG emissions for each 

component of the renewable fuel lifecycle, and for the 2005 petroleum baseline. In this Section 

we present and compare the GHG emissions results for each of these components in the fuel 

lifecycle. We also discuss how key assumptions can change the GHG emissions from each 

component of the fuel lifecycle, and how they influence the final GHG percent reduction 

estimates. 

In addition to estimating GHG emissions at every stage of the fuel lifecycle, EPA’s task 

in this rulemaking is to integrate the GHG emissions estimates from all stages of the lifecycle in 

order to estimate lifecycle GHG percent reductions for each renewable fuel pathway. We have 

considered a number of ways to meet this challenge, and have identified several key 

methodological issues that can influence whether a particular renewable fuel pathway meets the 

thresholds set forth in the EISA. For example, one issue that deserves attention is the timing of 

lifecycle GHG emissions. 

Section 2.6.5.5 explained that the lifecycle GHG emissions associated with biofuels can 

vary over time. Clearing forests, grasslands, and other types of land that sequester carbon, for 

crop production can results in GHG emissions for many years. As depicted in Figure 2.6-19, this 

type of land conversion produces large immediate GHG emissions, followed by a lesser stream 

of emissions that can last for many years. Biomass feedstocks grown annually on new cropland 

can be converted to biofuels that offer a GHG benefit relative to the petroleum product they 

403 
2005 Gasoline Baseline

Corn Ethanol Lifecycle GHG Emissions (2022 NG Dry Mill)

Cumulative Net Corn Ethanol Life Cycle GHG Emissions (2002 NG Dry Mill)

Year 0 Land Use

•Clearing with fire

•Biomass decay

•Soil carbon emissions

•Foregone forest sequestration

replace, but these benefits may be small compared to the upfront GHG emissions associated with 

land clearing to expand crop production. Depending on the specific biofuel in question, it can 

take many years for the benefits of the biofuel to make up for the large initial releases of carbon 

that result from land conversion (e.g., the payback period). 

The payback period calculation, presented graphically in Figure 2.8-1, represents the time 

it takes for the emissions savings from the production of biofuels to equal the potentially large 

initial emissions from land use changes. Although we do not believe it is appropriate to use the 

payback period for RFS2 compliance purposes, this calculation helps to illustrate the importance 

of the time dimension of renewable fuel lifecycle GHG emissions. 

Figure 2.8-1. Corn Ethanol Payback Period 

-200,000

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

2022203020402050

GHG Emissions (gCO2-eq / mmBtu)

Years 1-19 Land Use

•Soil carbon emissions

•Foregone forest sequestration

Years 20-79 Land Use

•Foregone forest sequestration

Payback ~33 years -200,000 

0 

200,000 

400,000 

600,000 

800,000 

1,000,000 

1,200,000 

2022203020402050 

GHG Emissions (gCO2-eq / mmBtu) 

2005 Gasoline Baseline 

Corn Ethanol Lifecycle GHG Emissions (2022 NG Dry Mill) 

Cumulative Net Corn Ethanol Life Cycle GHG Emissions (2002 NG Dry Mill) 

Year 0 Land Use 

•Clearing with fire 

•Biomass decay 

•Soil carbon emissions 

•Foregone forest sequestration 

Years 1-19 Land Use 

•Soil carbon emissions 

•Foregone forest sequestration 

Years 20-79 Land Use 

•Foregone forest sequestration 

Payback ~33 years 

Figure 2.8-1 shows the lifecycle GHG emissions from corn ethanol produced with a 2022 

technology natural gas fired dry mill, and from the 2005 gasoline baseline. In the first year, in 

this case 2022, corn ethanol lifecycle GHG emissions are more than ten times greater than the 

gasoline it replaces. However, corn ethanol has ongoing GHG benefits in every subsequent year. 

It takes approximately 33 years for the annual GHG benefits of corn ethanol compared to 

gasoline to pay back the initial GHG releases from land clearing. This tells us that unless we 

analyze the lifecycle GHG emissions of corn ethanol over more than 33 years, corn ethanol from 

this pathway will not achieve a reduction compared to gasoline. As we extend our analysis 

beyond 33 years we will see increasing GHG reductions associated with the use of corn ethanol. 

As discussed in Section 2.6.5.5, economic theory suggests that in general consumers have 

a time preference for benefits received today versus receiving them in the future. Therefore, 

future benefits are often valued at a discounted rate. If we apply this concept to GHG emissions, 

the GHG reduction benefits achieved by corn ethanol in future years carries less weight than 

earlier emissions. Figure 2.8-2 illustrates that the payback period is significantly longer if we 

use a two percent or three percent discount rate. 

404 
2005 Gasoline Baseline

Corn Ethanol Lifecycle GHG Emissions (2022 NG Dry Mill)

Cumulative Net Corn Ethanol Life Cycle GHG Emissions (2002 NG Dry Mill), r=0%

Cumulative Net Corn Ethanol Lifecycle GHG Emissions (2022 NG Dry Mill), r 2%

Cumulative Net Corn Ethanol Lifecycle GHG Emissions (2022 NG Dry Mill), r 3%

 

Figure 2.8-2. Corn Ethanol Payback Period with Different Discount Rates 

-100,000

100,000

300,000

500,000

700,000

900,000

1,100,000

202220302040205020602070208020902100

GHG Emissions (gCO2-eq / mmBtu)

=

=

Note: Annual emissions 

discounted 3%

-100,000 

100,000 

300,000 

500,000 

700,000 

900,000 

1,100,000 

202220302040205020602070208020902100 

GHG Emissions (gCO2-eq / mmBtu) 

2005 Gasoline Baseline 

Corn Ethanol Lifecycle GHG Emissions (2022 NG Dry Mill) 

Cumulative Net Corn Ethanol Life Cycle GHG Emissions (2002 NG Dry Mill), r=0% 

Cumulative Net Corn Ethanol Lifecycle GHG Emissions (2022 NG Dry Mill), r=2% 

Cumulative Net Corn Ethanol Lifecycle GHG Emissions (2022 NG Dry Mill), r=3% 

Note: Annual emissions 

discounted 3% 

r=0%Payback ~33 years r=2%Payback ~47 years r=3%Payback ~69 years 

The payback period concept helps to demonstrate the importance of the choice of a 

discount rate and time horizon for this analysis. These factors are so important because of the 

variation in GHG emissions from renewable fuels over time, and the contrasting steady annual 

emissions from the petroleum baseline. It is difficult to compare these two very different 

emissions profiles unless we put them on an equal footing. To do this, we compared the net 

present value (NPV) of renewable fuels emissions and the NPV of emissions from the petroleum 

baseline. Using NPVs to compare streams of costs and benefits is a well established practice for 

cost-benefit analysis. Similarly, a net present value approach is commonly used to assess GHG 

emissions.WWWWWWW The NPV of lifecycle GHG emissions is the sum of all terms: 

GHGt / (1 + r)^t, where 

t = the year, where year 0 is the first year of analysis 

r = the discount rate 

GHGt = the net flow of GHG emissions in year t 

In the preamble for the proposed rule, we highlight results that use a discount rate of two 

percent (i.e., r=2%), with a 100 year time horizon (i.e. T=100), and a 0% discount rate (i.e., 

r=0%) with a 30 year time horizon (T=30). Figure 2.8-3 includes lifecycle GHG results using a 

100-year time horizon and a 2% discount rate for a typical dry mill corn ethanol facility fired 

with natural gas. 

WWWWWWW See for example The Stern Review of the Economics of Climate Change, October 2006, 

http://www.occ.gov.uk/activities/stern.htm 

405 
Figure 2.8-3. Corn Ethanol Lifecycle GHG Results 

(NPV, r=2%, T=100 years) 

GHG Emissions (gCO2-eq / mmBtu) 

5,000,000 

4,000,000 

3,000,000 

2,000,000 

1,000,000 

0 

-1,000,000 

-16% 

2005 Gasoline Baseline 2022 Base Dry Mill NG 

Fuel Production 

International Land Use Change 

International Farm Inputs and Fert N2O 

Other (fuel and feedstock transport) 

Domestic Soil Carbon 

International Livestock 

International Rice Methane 

Tailpipe 

Domestic Rice Methane 

Domestic Farm Inputs and Fert N2O 

Domestic Livestock 

Net Emissions 

The NPV of gasoline GHG emissions over 100 years is presented on the left side of 

Figure 2.8-3. The chart shows that with a 2 percent discount rate the 100-year NPV of gasoline 

lifecycle GHG emissions is 4,240,674 gCO2eq/mmBtu. Tailpipe emissions make up over 80% 

of the lifecycle GHG emissions from gasoline. The rest of gasoline’s lifecycle GHG emissions 

occur during the fuel production process, which includes both upstream and downstream 

production processes. 

The lifecycle GHG emissions from corn ethanol appear on the right-hand side of Figure 

2.8-3. With a 2 percent discount rate the 100 year net present value of lifecycle GHG emissions 

from corn produced in a typical natural gas fired dry mill is 3,563,294 gCO2eq/mmBtu. This 

represents a 677,379 gCO2eq/mmBtu benefit compared to the gasoline baseline, or a 16 percent 

lifecycle GHG reduction. 

As discussed above in Section 2.7, tailpipe emissions are almost negligible for corn 

ethanol, because the carbon emitted upon ethanol combustion was sequestered when the corn 

was growing in the field. The result is a net carbon emission of zero, and small emissions of 

non-CO2 GHGs. 

406 
Fuel production accounts for almost 40% of the net emissions from corn ethanol. The 

fuel production emissions presented in Figure 2.8-3 correspond with a typical dry mill corn 

ethanol production facility that uses natural gas and electricity for energy, and produces dried 

DGs. The ethanol production facility in this example has the projected efficiency of a typical dry 

mill in 2022. Emissions associated with transportation and distribution of feedstocks to the 

ethanol plant, and ethanol to the end consumer, account for almost 5 percent of corn ethanol’s 

net lifecycle GHG emissions. 

As discussed in detail above, corn production requires land, fertilizer, pesticides, energy 

use, and other inputs that produce GHG emissions. However, using more corn for ethanol has 

other significant indirect impacts that ripple through the domestic agricultural sector. Many of 

the secondary agricultural sector impacts have significant GHG emissions implications. For 

example, as corn prices increase, corn-intensive livestock production tends to decrease and 

methane emissions from cattle also drop. As Figure 2.8-3 shows, we estimated that using more 

corn for ethanol results in net reductions of GHG emissions from domestic livestock, domestic 

farm inputs and nitrous oxide, and domestic rice methane emissions. Domestic soil carbon 

emissions increase modestly, but the net effect is a reduction in GHG emissions from domestic 

agriculture. Foreign agriculture is also a significant source of GHG emissions. As a result of 

using more U.S. corn for ethanol, we project that crop and livestock production will increase in 

foreign countries, with corresponding GHG emissions.. 

Figure 2.8-4 includes NPV lifecycle GHG results for four types of corn ethanol 

production facilities, and for ethanol made from other types of feedstocks. 

Figure 2.8-4. Ethanol Lifecycle GHG Results 

(NPV, r=2%, T=100 years) 6,000,000 

-115% 

-128% 

-44% 

-39% 

13% 

-39%* 

-16% 

2005 

Gasoline 

Baseline 

2022 Base 

Dry Mill NG 

2022 Best 

Case Dry 

Mill NG 

2022 Base 

Dry Mill 

Coal 

2022 Base 

Dry Mill 

Biomass 

Sugarcane 

Ethanol 

Switchgrass 

Ethanol 

Corn Stover 

Ethanol 

CORN ETHANOL ADVANCED ETHANOL CELLULOSIC ETHANOL 

Fuel Production 

International Land Use Change 

5,000,000 

International Farm Inputs and 

Fert N2O 

Other (fuel and feedstock 4,000,000 transport) 

Domestic Soil Carbon 

3,000,000 International Livestock 

International Rice Methane 

2,000,000
 

Tailpipe
 

Domestic Rice Methane 1,000,000 

Domestic Farm Inputs and 

Fert N2O 

0 Domestic Livestock 

20% Reduction Threshold 

-1,000,000 

50% Reduction Threshold 

60% Reduction Threshold 

-2,000,000 

Net Emissions 

GHG Emissions (gCO2-eq / mmBtu) 

Note: “Best case” plants include CHP, fractionation, membrane separation and raw starch hydrolysis technologies 

407 
 

A “best case” corn ethanol plant fired with natural gas achieves a 39% reduction 

compared to gasoline. The best case plant is equipped with advanced technologies that can be 

deployed in tandem: combined heat and power (CHP), fractionation, membrane separation and 

raw starch hydrolysis. Details about these fuel production technologies are discussed in Section 

2.6.7. The results in Figure 2.8-4 suggest that the energy efficiency of future corn production 

facilities could be an important determinant of which production pathways meet the thresholds 

specified in the EISA. 

Figure 2.8-4 shows that imported sugarcane ethanol achieves a 44 percent reduction 

compared to the gasoline baseline, which is close to the 50 percent reduction threshold for 

advanced renewable fuels and exceeds the minimum adjusted threshold of 40 percent. 

Sugarcane ethanol has lower lifecycle GHG emissions than corn ethanol for a number of reasons. 

Converting sugarcane to ethanol is less energy intensive than the conversion process with corn. 

Standard sugarcane ethanol production facilities burn bagasseXXXXXXX for energy, which shrinks 

their carbon footprints. International land use change emissions associated with sugarcane 

ethanol production are about 10 percent less than international land use change emissions from 

corn ethanol. Sugarcane ethanol also has benefits compared to corn ethanol in the international 

rice methane, international livestock, and other emissions categories. 

The cellulosic ethanol pathways presented in Figure 2.8-4, corn stover and switchgrass 

ethanol, both achieve greater than 100 percent lifecycle GHG reductions compared to gasoline. 

In fact, as the figure shows, producing ethanol from these pathways creates a net abatement of 

GHG emissions. A major source of the emissions mitigation in the cellulosic ethanol lifecycle 

occurs at the fuel production stage. The cellulose and lignin in switchgrass and corn residue are 

separated with an enzymatic process. The cellulose is fermented to produce ethanol, leaving 

lignin as a by-product which can be burned for heat and electricity. Our process modeling 

suggests that by burning lignin, cellulosic ethanol production facilities utilizing an enzymatic 

conversion process will generate more electricity than they need. These facilities will be net 

exporters of electricity to the grid, offsetting an average mix of grid electricity. Switchgrass 

ethanol has modest impacts on international land use and crop production, because it competes 

with other crops for land. 

In our results ethanol from switchgrass achieves the largest lifecycle GHG reductions 

compared to petroleum. The results include a large decrease in foreign livestock emissions as a 

result of switchgrass ethanol production. However, this result may be an artifact of the imperfect 

way that switchgrass was represented in the FAPRI model.YYYYYYY As we refine this estimate 

for the final rule, we might see a different outcome for international livestock emissions. 

Switchgrass land use change emissions are roughly one-fifth as large as land use change 

emissions from corn ethanol because switchgrass can be produced on less fertile lands, thus 

displacing less commodity crop production. However, this estimate is also subject to change as 

we refine our modeling of switchgrass with the FAPRI model. 

XXXXXXX Bagasse is the biomass remaining after sugarcane stalks are crushed. YYYYYYY When we conducted our analysis for the proposed rule the FAPRI model did not explicitly include
 

switchgrass cultivation. As a proxy for switchgrass we modeled an increase in domestic land enrolled in the 

Conservation Reserve Program (CRP). 

408 
Biodiesel Lifecycle GHG Results 

(NPV, r=2%, T=100 years) 

5,000,000 Fuel Production 

International Land Use Change 

3,000,000 

4,000,000 

mmBtu) 

-22% 

International Farm Inputs and Fert 

N2O 

Other (fuel and feedstock transport) 

Domestic Soil Carbon 

O2-eq / 

International Livestock 

2,000,000 

s (gC

International Rice Methane 

Tailpipe 

0 

1,000,000 

GHG Emission

-80% 

Domestic Rice Methane 

Domestic Farm Inputs and Fert 

N2O 

Domestic Livestock 

50% Reduction Threshold 

-1,000,000 Net Emissions 

Corn stover is a waste product that does not displace land from commodity crop 

production. In fact, using stover for ethanol creates a market for corn residue, making corn 

farming a more profitable enterprise. Corn residue is a source of nitrogen, so removing it from 

the field requires additional fertilizer application, which is why we see a modest increase in 

emissions from domestic farm inputs. On the other hand, farmers must employ no-till farming 

practices in order to harvest stover and sell it to ethanol. The spread of no-till farming has soil 

carbon benefits that show-up in Figure 2.8-4. 

Biodiesel lifecycle GHG emissions results are presented in Figure 2.8-5. Over a 100-year 

time horizon soy-based biodiesel achieves a 22% lifecycle GHG reduction, and biodiesel derived 

from waste grease achieves a larger lifecycle GHG reduction. We did not include upstream or 

indirect impacts in the waste grease biodiesel lifecycle. Upstream emissions were fully 

attributed to the first use of the oil; not to the residual waste grease. Although indirect impacts 

are not included in the results presented here, we intend to conduct a closer study of the potential 

for indirect impacts from using waste grease for biodiesel, instead of using it for other purposes. 

This will include further review of waste grease supply and demand projections. 

Figure 2.8-5. 

2005 Diesel Baseline Soy Biodiesel Waste Grease 

Figure 2.8-6 illustrates the effect of the choice of discount rate on lifecycle GHG results. 

As the discount rate increases, the NPV of non-land use change emissions decrease. This 

happens because a higher discount rate diminishes the relative valuation of emissions that occur 

409 
 

in the future. On the other hand, the NPV of emissions from of land use changes are less 

affected by the choice of discount rate. This is because, as displayed in Figure 2.8-1, a large 

share of international land use change emissions occur in the first year. Therefore, for renewable 

fuels that include international land use change emissions, increasing the discount rate will 

reduce their lifecycle GHG percent reduction compared to petroleum. In Figure 2.8-6, going 

from a 0% to 7% discount rate changes the lifecycle GHG emissions of biodiesel compared to 

average diesel from a 48% reduction to a 51% increase. 

Figure 2.8-6 

Biodiesel Lifecycle GHG Results with Different Discount Rates 

(NPV, r=0%, 2%, 3%, 7%, T=100 years) 

GHG Emissions (gCO2-eq / mmBtu) 

12,000,000 

10,000,000 

8,000,000 

6,000,000 

4,000,000 

2,000,000 

0 

Non-Land Use Change Land Use Change Net Emissions 

-48% 

2005 Diesel 

Baseline 

Soy-Based 

Biodiesel 

0% DISCOUNT RATE 

-22% 

2005 Diesel 

Baseline 

Soy-Based 

Biodiesel 

2% DISCOUNT RATE 

-7% 

2005 Diesel 

Baseline 

Soy-Based 

Biodiesel 

3% DISCOUNT RATE 

51% 

2005 Diesel 

Baseline 

Soy-Based 

Biodiesel 

7% DISCOUNT RATE 

When lifecycle emissions vary over time—as they do for biofuels that induce indirect 

land use change—the choice of time horizon is essential. Figure 2.8-7 includes corn ethanol 

lifecycle GHG results using a 30-year time horizon and a 0% discount rate. This figure is similar 

to Figure 2.8-4 except for the time horizon. For corn ethanol produced in a typical natural gas 

fired dry mill, decreasing the time horizon from 100 to 30 years and shifting the discount rate 

from 2% to 0% changes the lifecycle GHG results from a 16 percent decrease to an 5 percent 

increase compared to gasoline. 

410 
 

-18% 

+34% 

-18% 

+5% 

-1,000,000 

0 

1,000,000 

2,000,000 

3,000,000 

4,000,000 

5,000,000 

GHG Emissions (gCO2-eq / mmBtu) 

Figure 2.8-7. 

Corn Ethanol Lifecycle GHG Results 

(NPV, r=0%, T=30 years) 

Fuel Production 

International Land Use Change 

International Farm Inputs and Fert 

N2O 

Other (fuel and feedstock 

transport) 

Domestic Soil Carbon 

International Livestock 

International Rice Methane 

Tailpipe 

Domestic Rice Methane 

Domestic Farm Inputs and Fert 

N2O 

Domestic Livestock 

20% Reduction Threshold 

Net Emissions 

2005 Gasoline 2022 Base Dry Mill 2022 Best Case Dry 2022 Dry Mill Coal 2022 Dry Mill 

Baseline NG Mill NG Biomass 

Figure 2.8-8 includes lifecycle GHG results for corn ethanol produced in a natural gasfired dry mill over a continuum of time horizons. The horizontal axis is the choice of time 

horizon. As discussed above, our results indicate that the payback period for a standard corn 

ethanol pathway is approximately 33 years. With a zero percent discount (the blue line in Figure 

2.8-8) corn ethanol increases GHG emissions by 5 percent over 30 years, and reduces emissions 

by 17 percent and 36 percent over 50 and 100 years respectively. With higher discount rates, it 

takes longer for the future benefits of corn ethanol production to payback earlier land clearing 

emissions. When we use a discount rate greater than zero, future benefits are discounted, 

causing the curves in Figure 10-8 to flatten out over time. 

411 
 

 

Figure 2.8-8. 

Lifecycle GHG Results for Corn Ethanol Produced in a Natural Gas Dry Mill 

(Percent Change from Gasoline with Different Discount Rates and Time Horizons) 

-36% 

18% 

7% 

-17% 

5% 

-2% 

-16% 

25% 

-5% 

-40% 

-20% 

0% 

20% 

40% 

60% 

80% 

100% 

Lifecycle GHG Percent Change From Gasoline Baseline 

Corn Ethanol Base Plant, 0% Discount Rate 

Corn Ethanol Base Plant, 2% Discount Rate 

Corn Ethanol Base Plant, 3% Discount Rate 

30, 50 & 100 Year Results, r=0% 

30, 50 & 100 Year Results, r=2% 

30, 50 & 100 Year Results, r=3% 

2022204020702100 

2.8.2 Land Use Change Sensitivity Results 

In our results, emissions from land use changes are a significant source of the lifecycle 

GHG emissions for renewable fuels produced with feedstocks that can be used in food products 

or grown on fertile land. As discussed above, we used a number of agricultural and economic 

models to estimate the land use impacts of these fuels. We used the FASOM model to estimate 

GHG emissions from land use changes in response to renewable fuel production. With the 

FAPRI model we projected which foreign countries would expand crop production as a result of 

the RFS2 program. We then used satellite data from 2001 to 2004 to project where cropland is 

likely to be added within foreign countries, and which types of land are cleared to make room for 

new crop areas. Emissions factors developed by the non-profit Winrock International, using 

2006 IPPC guidelines, were applied to estimate the GHG emissions associated with foreign land 

use change. This approach for estimating land use change GHG emissions used the best 

available tools. However, even with the best available tools, projecting how a U.S. policy will 

effect international land use change is a task with inherent uncertainty. For this reason we 

identified key parameters within our land use change projections and conducted selective 

sensitivity analysis. 

2.8.2.1 Types of Land Converted to Cropland Sensitivity Analyses 

One of the most important questions that determine the magnitude of land use change 

GHG emissions is what types of land are cleared when new cropland is added. This question is 

significant because clearing forest to expand cropland produces more GHG emissions per acre 

412 
 

than clearing grassland, or other types of land that sequester less carbon. For example, we 

estimate that in Brazil an average acre of forest contains almost 10 times more carbon than an 

average acre of grassland. To address uncertainty, we conducted sensitivity analyses where we 

varied the types of land that are cleared internationally as a result of biofuel production. 

A common input from stakeholders has been their belief that in many countries, such as 

Brazil, there is ample abandoned cropland, idle grassland and degraded pasture to accommodate 

crop expansion induced by biofuel production. The MODIS satellite data suggests that if recent 

trends persist, crop expansion would occur on land previously inhabited by a variety of 

ecosystem types. However, future economic conditions or government policies could dictate that 

cropland expansion would occur exclusively on idle grassland. We did a sensitivity analysis that 

assumes that all new cropland occurs on idle grassland, which also implies no pasture 

replacement is necessary.ZZZZZZZ Figure 2.8-9 shows that the assumption that all cropland 

expansion occurs on idle grassland has a dramatic impact on GHG emissions per acre. This 

assumption has a particularly large impact on the weighted average emissions factors for South 

East Asian countries that have a large portion of forest to cropland conversion in our central 

estimates for the proposed rule. 

Figure 2.8-9. 

GHG Emissions per Acre of Cropland Expansion 

(NPV, r=2%, T=100 years) 

Primary Estimate Forest Only Grassland Only 

500 

GHG Emissions per Acre (MTCO2eq / mmBtu) 450 

400 

350 

300 

250 

200 

150 

100 

50 

0 

Argentina Brazil China E.U. India Indonesia Malaysia Nigeria Philippines	 South 

Africa 

Tables 2.8-1 and 2.8-2 show how EPA’s lifecycle GHG emission estimates vary by 

renewable fuel. Table 2.8-1 includes results using a 100-year time horizon and a 2% discount 

rate. Table 2.8-2 includes results using a 30-year time horizon and a 0% discount rate. Our 

primary estimates include GHG emissions from forest and grassland clearing (proportionally 

estimated based on MODIS satellite data) resulting from the use of agricultural products for 

ZZZZZZZ See Section 2.6 for a discussion of pasture replacement 

413 
 

 

 

biofuel production.AAAAAAAA The tables also show how the percent reduction estimates would 

vary if we assumed that all new cropland would come from forest, or all from grasslands. 

Table 2.8-1. Lifecycle GHG Results 

100-Year Time Horizon with 2% Discount Rate 

GHG Emissions Reductions Relative to the 2005 Petroleum Baseline 

Land Use Change Forest Only Primary Estimate Grassland Only 

Corn Ethanol (Natural Gas 

Dry Mill) +20% -16% -48% 

Corn Ethanol (Coal Dry 

Mill) +48% +13% -19% 

Corn Ethanol (Biomass Dry 

Mill) -4% -39% -71% 

Soy-Based Biodiesel +15% -22% -65% 

Waste Grease Biodiesel -80% -80% -80% 

Sugarcane Ethanol -23% -44% -70% 

Swtichgrass Ethanol -118% -128% -135% 

Corn Stover Ethanol -115% -115% -115% 

Table 2.8-2. Lifecycle GHG Results 

30-Year Time Horizon with0% Discount Rate
 

GHG Emissions Reductions Relative to the 2005 Petroleum Baseline 

Land Use Change Forest Only Primary Estimate Grassland Only 

Corn Ethanol (Natural Gas 

Dry Mill) +49% +5% -38% 

Corn Ethanol (Coal Dry Mill) +78% +34% -9% 

Corn Ethanol (Biomass Dry 

Mill) +26% -18% -61% 

Soy-Based Biodiesel +49% +4% -54% 

Waste Grease Biodiesel -80% -80% -80% 

Sugarcane Ethanol -4% -26% -60% 

Swtichgrass Ethanol -113% -124% -134% 

Corn Stover Ethanol -116% -116% -116% 

As discussed in the preamble, in the case of sugarcane production in Brazil, a number of 

researchers argue that expanded sugarcane production is likely to occur in significant part 

through the use of degraded or abandoned pasture land without additional land use impact in 

Brazil.BBBBBBBB If these researchers are correct, then we estimate that sugarcane ethanol 

produced in Brazil would produce a 64% lifecycle GHG emissions reduction compared to 

gasoline with a 100-year time horizon and a 2% discount rate, or a 52% lifecycle GHG reduction 

with a 30-year time horizon and a 0% discount rate. 

AAAAAAAA Per acre land use change emissions factors were estimated by Winrock International Inc., following 2006 

Intergovernmental Panel on Climate Change guidelines 

BBBBBBBB See for example “Mitigation of GHG emissions using sugarcane bio-ethanol - Working Paper” by Isaias 

C. Macedo and Joaquim E. A. Seabra, and “Prospects of the Sugarcane Expansion in Brazil: Impacts on Direct and 

Indirect Land Use Changes – Working Paper” by Andre Nassar et al, both received by EPA October 13, 2008 

414 
 

 

 

2.8.2.2 Foregone Forest Sequestration Sensitivity Analysis 

Section 2.6 discussed our primary approach for estimating foregone forest sequestration 

when forests are converted to cropland. As discussed in that section, foregone sequestration was 

estimated using average annual biomass accumulation rates for forests greater than 20 years old 

given in Table 4.9 of the 2006 GL AFOLU according to ecological zone and continent. These 

values were used to estimate the lost biomass accumulation of forests that were converted to 

another land use. Foregone sequestration was assumed to continue at a constant rate for 80 

years. Studies have estimated that new forests grow for 90 years to over 120 years.CCCCCCCC 

More recent estimates suggest that old growth forests accumulate carbon for up to 800 years.538 

Our proposed estimate that foregone sequestration continues for 80 years is within the range 

supported by the scientific literature and the 2006 IPCC guidelines. However, there are other 

reasonable approaches that could have been used to estimate foregone sequestration. 

Given the wide range of estimates about how long forests continue to accumulate carbon 

it would not be unreasonable to assume that we should account for more than 80 years of lost 

sequestration. On the other hand, if we expect that very old forests would be converted to 

cropland, it would also be reasonable to assume a shorter timeframe for lost sequestration, or no 

lost sequestration at all. Figure 2.8-10 shows how using different assumptions about the length 

of foregone sequestration affects weighted average emissions factors for forest to cropland 

conversion in Brazil. 

CCCCCCCC See Greenhouse Gas Mitigation Potential in U.S. Forestry and Agriculture, EPA Document 430-R-05-006 

for a discussion of the time required for forests to reach carbon saturation. 

415 
 

Figure 2.8-10. 

Weighted Average Emissions per Acre of Forest to Cropland Conversion in Brazil 

Different Lengths of Foregone Sequestration
 

(NPV, r=2%, T=100 years) 

157 

165 

103 

65 

0 

20 

40 

60 

80 

100 

120 

140 

160 

180 

MTCO2-eq / Acre Forest to Cropland Conversion 

80 Years of Foregone 100 Years of Foregone 20 Years of Foregone No Foregone 

Sequestration Sequestration Sequestration Sequestration 

Figure 2.8-11 includes lifecycle GHG results for soy-based biodiesel with different 

assumptions about the length of foregone forest sequestration. The length of foregone 

sequestration is an important part of international land use change emissions, but even if we 

assume no foregone sequestration, our results suggest that soy-based biodiesel does not achieve a 

40 percent lifecycle GHG reduction compared to average diesel fuel. 

416 
 

 

Figure 2.8-11. 

Soy Biodiesel Lifecycle GHG Results – Foregone Sequestration Length Sensitivity (NPV, 

r=2%, T=100 years) 

GHG Emissions (gCO2-eq / mmBtu) 

5,000,000 

4,000,000 

3,000,000 

2,000,000 

1,000,000 

0 

-1,000,000 

-37% 

-31% 

-21% -22% 

2005 Diesel 

Baseline 

80 Years 

Foregone 

Sequestration 

100 Years 

Foregone 

Sequestration 

20 Years 

Foregone 

Sequestration 

No Foregone 

Sequestration 

SOY-BASED BIODIESEL 

Fuel Production 

International Land Use Change 

International Farm Inputs and Fert N2O 

Other (fuel and feedstock transport) 

Domestic Soil Carbon 

International Livestock 

International Rice Methane 

Tailpipe 

Domestic Rice Methane 

Domestic Farm Inputs and Fert N2O 

Domestic Livestock 

50% Reduction Threshold 

Net Emissions 

As discussed in detail in Section 2.6.5, annual foregone sequestration was calculated as: 

ΔClostseq = , ( ∑ Cseq LUbefore i , ) −Cseq LUafter i 

i 

where: 

ΔC lostseq = change in carbon sequestration in aboveground biomass t C ha-1 yr-1 

-1 Cseq = annual sequestration in aboveground biomass before conversion t C ha-1 yr LUbefore i ,

Cseq = annual sequestration in aboveground biomass after conversion t C ha-1 yr-1 

LUafter i ,

i = type of land use converted to another land use category. 

Table 4.9 of the 2006 GL AFOLU was used to estimate the annual sequestration in 

aboveground forest biomass. The 2006 GL AFOLU provides a sequestration range for typical 

forest types by continent and ecological zone. The area of forest in each state was stratified by 

FAO ecozone and continent. This calculation is consistent with 2006 IPCC guidelines, but there 

are other reasonable methodologies available to estimate foregone sequestration. For example, 

foregone sequestration could be estimated as a percentage of a forest’s initial aboveground 

biomass. As explained in Section 2.6, we used regional biomass maps to estimate forest carbon 

stocks in each state. Instead of using Table 4.9 of the 2006 GL AFOLU to estimate annual 

foregone sequestration, other approaches that were recommended by Winrock included 

calculating annual lost sequestration as one or two percent of the initial biomass in cleared 

forests. Figure 2.8-12 compares lifecycle GHG results for soy-based biodiesel using our primary 

estimate of foregone sequestration, and two other estimates that use one percent and two percent 

of initial forest biomass. 

417 
GHG Emissions (gCO2-eq / mmBtu) 

5,000,000 

4,000,000 

3,000,000 

2,000,000 

1,000,000 

0 

-1,000,000 

Figure 2.8-12 

Soy-Based Biodiesel Results 

Different Foregone Sequestration Calculation Methods 

(NPV, r=2%, T=100 years) 

-37% 

-18% 

-27% -22% 

2005 Diesel 

Baseline 

Primary Foregone 

Sequestration 

Method 

Foregone 

Seuqestration = 

1% of Initial 

Aboveground 

Biomass 

Foregone 

Seuqestration = 

2% of Initial 

Aboveground 

Biomass 

No Foregone 

Sequestration 

SOY-BASED BIODIESEL 

Fuel Production 

International Land Use Change 

International Farm Inputs and Fert N2O 

Other (fuel and feedstock transport) 

Domestic Soil Carbon 

International Livestock 

International Rice Methane 

Tailpipe 

Domestic Rice Methane 

Domestic Farm Inputs and Fert N2O 

Domestic Livestock 

50% Reduction Threshold 

Net Emissions 

2.8.2.3 Soil Carbon Emissions Sensitivity Analysis 

Land in annual crop production holds less soil carbon than lands with undisturbed root 

systems. A digital soil carbon map of the world available from USDA was used to estimate soil 

carbon by region.539 Carbon stocks on annual cropland were estimated as 5 metric tons of 

carbon per hectare based on Table 5.9 of the IPCC AFOLU. Changes in soil carbon stocks on 

land converted to cropland were calculated based on Section 5.3.3.4 of the IPCC AFOLU. 

Following the IPCC guidelines, the total difference in soil carbon stocks before and after 

conversion was averaged over 20 years. (See Section 2.6 for details about methods used to 

estimate changes in soil carbon stocks). 

During the proposed rule making process, EPA received feedback from stakeholders that 

soil carbon emissions could occur more rapidly than 20 years. To gauge the importance of the 

timing of soil carbon emissions on our lifecycle, we calculated results assuming that soil carbon 

emissions occur immediately when land is plowed in preparation for crop production. The 

timing of soil carbon emissions could influence overall lifecycle GHG results, because, using a 

NPV approach, near term emissions are weighted more heavily than emissions further into the 

future. Figure 2.8-13 shows that the timing of soil carbon emissions has a modest impact on 

lifecycle GHG results for sugarcane ethanol. 

418 
4,500,000 

Figure 2.8-13. 

Sugarcane Ethanol Results 

Soil Carbon Emissions Sensitivity 

(NPV, r=2%, T=100 years) 

Fuel Production 

4,000,000 

International Land Use Change 

3,500,000 

International Farm Inputs and Fert 

N2O 

3,000,000 

Other (fuel and feedstock 

transport) 

Domestic Soil Carbon 

2,500,000 

International Livestock 

2,000,000 International Rice Methane 

1,500,000 Tailpipe 

1,000,000 Domestic Rice Methane 

500,000 Domestic Farm Inputs and Fert 

N2O 

0 

Domestic Livestock 

-500,000 

50% Reduction Threshold 

Net Emissions 

GHG Emissions (gCO2-eq / mmBtu) 

-44% -42% 

2005 Gasoline Baseline Immediate Soil C Emissions Soil C Emissions Over 20 Years 

SUGARCANE ETHANOL 

2.8.2.4 Pasture Replacement Sensitivity Analysis 

We used a two step methodology to project biofuel induced land use change (See Section 

2.6 for a detailed description). The first step includes land use changes associated with cropland 

expansion. The second step includes land shifting to replace managed pastures that were 

converted to cropland during the first step. To illustrate the importance of the pasture 

replacement concept, Figures 2.8-14 and 2.8-15 bound our primary corn ethanol lifecycle GHG 

results with results that do not include pasture replacement, and results that replace all grassland 

and savanna (not just managed pastureland) converted to cropland. It is clear that interactions 

between crop expansion and pasturelands can have a substantial impact on overall lifecycle GHG 

estimates. For the final rule we intend to conduct additional analysis of the secondary land use 

effects of converting pasture to crop production. 

419 
GHG Emissions (gCO2-eq / mmBtu) 

Figure 2.8-14. 

Corn Ethanol Results 

Pasture Replacement Sensitivity 

(NPV, r=2%, T=100 years) 

5,000,000 

4,000,000 

3,000,000 

2,000,000 

1,000,000 

0 

-1,000,000 

-16% 

-2% 

-34% 

2005 Gasoline Baseline Managed Pasture 

Replacement 

100% Pasture 

Replacement 

No Pasture Replacement 

CORN ETHANOL - 2022 NG DRY MILL 

Fuel Production 

International Land Use Change 

International Farm Inputs and Fert 

N2O 

Other (fuel and feedstock 

transport) 

Domestic Soil Carbon 

International Livestock 

International Rice Methane 

Tailpipe 

Domestic Rice Methane 

Domestic Farm Inputs and Fert 

N2O 

Domestic Livestock 

20% Reduction Threshold 

Net Emissions 

420 
 

 

GHG Emissions (gCO2-eq / mmBtu) 

Figure 2.8-15. 

Corn Ethanol Results 

Pasture Replacement Sensitivity 

(NPV, r=0%, T=30 years) 

4,500,000 

-19% 

+24% 

+5% 

2005 Gasoline Baseline Managed Pasture 

Replacement 

100% Pasture 

Replacement 

No Pasture Replacement 

CORN ETHANOL - 2022 NG DRY MILL 

Fuel Production 

4,000,000 International Land Use Change 

3,500,000 International Farm Inputs and Fert 

N2O 

3,000,000 Other (fuel and feedstock 

transport) 

2,500,000 Domestic Soil Carbon 

2,000,000 International Livestock 

1,500,000 International Rice Methane 

1,000,000 Tailpipe 

Domestic Rice Methane 500,000 

Domestic Farm Inputs and Fert 0 N2O 

Domestic Livestock -500,000 

20% Reduction Threshold -1,000,000 

Net Emissions 

2.8.2.5 Year of Analysis Sensitivity Results 

The EISA mandates increasing volumes of U.S. renewable fuel volumes, culminating in 

36 billion gallons renewable fuel use in 2022. To estimate the full fuel-specific GHG impacts of 

the EISA mandates we used 2022 as the primary year for our analysis. To address whether the 

GHG emissions vary significantly over time, we also analyzed GHG emissions estimates in 2012 

and 2017. As shown in Table VI.C.2-3, the GHG emissions reductions are fairly consistent over 

the time period of our analysis. There may be countervailing forces that stabilize land use 

change emissions over this period. Crop yields increase over time (therefore reducing land use 

pressure), but there is also more production of other renewable fuels that require land for 

feedstock production (therefore increasing land use pressure). The results for 2012 and 2017 

used 2022 domestic soil carbon emissions impacts, because of issues with FASOM’s 

methodology for soil carbon projections.DDDDDDDD 

DDDDDDDD As discussed in Section 2.6, we are updating FASOM’s domestic soil emissions estimates for the final 

rule, which should allow for distinct soil carbon estimates in 2012, 2017 and 2022. 

421 
GHG Emissions (gCO2-eq / mmBtu) 

Figure 2.8-16. 

Corn Ethanol Results – Year of Analysis Sensitivity 

(NPV, r=2%, T=100 years) 

-16% -13% -16% 

2005 Gasoline Baseline 2022 2017 2012 

CORN ETHANOL - NG DRY MILL 

Fuel Production 

International Land Use Change 

4,000,000 

5,000,000 

International Farm Inputs and Fert 

N2O 

Other (fuel and feedstock 

transport) 

3,000,000 Domestic Soil Carbon 

International Livestock 

2,000,000 International Rice Methane 

Tailpipe 

1,000,000 Domestic Rice Methane 

Domestic Farm Inputs and Fert 

N2O 0 

Domestic Livestock 

20% Reduction Threshold 

-1,000,000 

Net Emissions 

2.8.2.6 Fuel Volumes Modeled Sensitivity Analysis 

The renewable fuel volume scenarios used for the proposed rule analysis are described 

above in Section 2.3.2. We modeled the difference between domestic fuel consumption without 

EISA and domestic fuel consumption with EISA. For corn ethanol, this meant modeling the 

difference between 12.4 and 15 billion gallons of domestic corn ethanol consumption in 2022. 

This approach allowed us to isolate the incremental impacts of the revisions to the RFS program. 

For the reasons discussed in the preamble for the proposed rule, we believe this is the most 

relevant analytical approach for RFS2 implementation. However, we also tested the lifecycle 

GHG impacts of a larger change in corn ethanol volumes. For this sensitivity analysis we 

estimated lifecycle GHG impacts for an increase in ethanol consumption from 8.7 to 15 billion 

gallons in 2022. 

Figure 2.8-176 includes lifecycle GHG estimates with a lower corn ethanol volume in the 

reference case. The international land use emissions were very close between the two volume 

scenarios. In the lower volume reference case (i.e., 8.7 billion gallons in 2022), GHG emissions 

from domestic farm inputs such as fertilizer did not decrease as much as they did in our primary 

reference case. The largest difference between the scenarios is that overall livestock GHG 

emissions increased when we used a lower reference case volume, which is counter to the overall 

livestock response in our primary estimate. We intend to explore the sensitivity of the fuel 

volumes modeled in more depth for the final rule. 

422 
 

 

GHG Emissions (gCO2-eq / mmBtu) 

Figure 2.8-17. 

Corn Ethanol Results 

Fuel Volumes Modeled Sensitivity 

(NPV, r=2%, T=100 years) 

5,000,000 

-16% 

-6% 

Fuel Production 

International Land Use Change 

4,000,000 International Farm Inputs and Fert 

N2O 

Other (fuel and feedstock
 

transport)
 

3,000,000
 Domestic Soil Carbon 

International Livestock 

2,000,000
 

International Rice Methane
 

Tailpipe 

1,000,000 

Domestic Rice Methane 

Domestic Farm Inputs and Fert 

N2O 0 

Domestic Livestock 

20% Reduction Threshold 

-1,000,000
 

2005 Gasoline Baseline
 12.4 to 15 Bgal in 2022 8.7 to 15 Bgal in 2022 Net Emissions 

CORN ETHANOL - NG DRY MILL 

2.8.3 Fuel-Specific Results Conclusions 

In addition to providing lifecycle GHG emissions estimates, EPA’s lifecycle analysis for 

the proposed rule highlights the importance of several key elements: 

• The time horizon for analysis; 

• The choice of discount rate; 

• The types of land cleared to make room for cropland expansion; 

• Interactions between cropland expansion and pasture area; and 

• The size of renewable fuel volume increases. 

The proposed rule is an important opportunity for EPA to solicit feedback on these and other 

issues that will improve and solidify our analysis before final rulemaking. For more information 

about our lifecycle GHG analysis, we have placed spreadsheets with all of our calculations and 

results on the docket for this rulemaking. 

423 
2.9 Overall Lifecycle Greenhouse Gas Emissions Results of Rulemaking 

Volume 

Our analysis of the overall GHG emission impacts of this proposed rulemaking was 

performed in parallel with the lifecycle analysis performed to develop the individual fuel 

thresholds described in previous sections. The same system boundaries apply such that this 

analysis includes the effects of three main areas: a) emissions related to the production of 

biofuels, including the growing of feedstock (corn, soybeans, etc.) with associated domestic and 

international land use change impacts, transport of feedstock to fuel production plants, fuel 

production, and distribution of finished fuel; b) emissions related to the extraction, production 

and distribution of petroleum gasoline and diesel fuel that is replaced by use of biofuels; and c) 

difference in tailpipe combustion of the renewable and petroleum based fuels. As discussed in 

the previous section we will be updating our lifecycle approach for the final rule and there are 

some areas that we were not able to quantify at this time, such as secondary impacts in the 

energy sector. We are working to include this for our final rule analysis. 

Consistent with the fuel volume feasibility analysis and criteria pollutant emissions 

evaluation, our analysis of the GHG impacts of this proposed rulemaking was conducted by 

comparing the difference between a 2022 reference case and a 2022 control case with volumes of 

renewable fuels meeting the RFS2 mandate. Similar to what was done to calculate lifecycle 

thresholds for individual fuels we considered the change in 2022 of these two volume scenarios 

of renewable fuels to determine overall GHG impacts of the rule. The reference case for the 

GHG emission comparisons was taken from the AEO 2007 projected renewable fuel production 

levels for 2022 prior to enactment of EISA. This scenario provided a point of comparison for 

assessing the impacts of the RFS2 standard volumes on GHG emissions. We ran these multi fuel 

scenarios through our FASOM and FAPRI models and applied the Winrock land use change 

assumptions to determine to overall GHG impacts of producing this increase in renewable fuels. 

The main differences between this overall impacts analysis and the analysis conducted to 

develop the threshold values for the individual fuels were that we analyzed the total change in 

renewable fuels in one scenario as opposed to looking at individual fuel impacts. When 

analyzing the impact of the total 36 billion gallons of renewable fuel, we also took into account 

the agricultural sector interactions necessary to produce the full complement of feedstock. 

Figure 2.9-1 shows the different scenarios considered in this analysis. 

424 
Figure 2.9-1. 

Fuel Volume Scenario Considered to Determine GHG Impact of 

Proposed Rulemaking 

Biofuel Volumes in 2022 

0 

5 

10 

15 

20 

25 

30 

35 

40 

Reference Case Primary Volume 

Scenario 

Reference Case Primary Volume 

Scenario 

FASOM FAPRI 

Billions of Gallons (Ethanol Equivalent) 

Imports FAPRI 

Imports FASOM 

Forestry 

MSW 

Cellulosic FAPRI 

Cellulosic FASOM 

Other Fats / Oils 

Soybean Oil 

Other Grains 

Corn 

As discussed in Chapter 5, certain types of fuels and feedstocks are not specifically 

captured in the models, for example MSW and forestry feedstocks are not explicitly modeled in 

FASOM while cellulosic ethanol in general is not explicitly modeled in FAPRI. Also, imports 

are not explicitly modeled in FASOM but are included in FAPRI modeling. 

We also considered a mix of plant types and configurations for the 2022 renewable fuel 

production representing the mix of plants we project to be in operation in 2022. The following 

table shows the types of plants considered in the analysis for the references and control cases. 

425 
 

Table 2.9-1. Types of Plants Considered in 2022 

Plant Type Technology 

Volu

Reference 

Case 

me of Fuel (

Control 

Case 

Bgal) 

Difference 

Corn Ethanol – Dry 

Mill 

Plant with NG (dry DG) 

Plant with NG (wet DG) 

Plant with coal (dry DG) 

Plant with coal (wet DG) 

Plant with biomass(dry DG) 

Plant with biomass (wet DG) 

7.19 

2.62 

1.11 

0.11 

0.09 

0.12 

8.77 

3.25 

1.17 

0.10 

0.19 

0.14 

1.58 

0.63 

0.06 

-0.01 

0.09 

0.01 

Corn Ethanol – Wet 

Mill 

Plant with NG 

Plant with coal 

0.00 

1.30 

0.16 

1.23 

0.16 

-0.06 

Cellulosic Ethanol – 

Enzymatic 

Switchgrass feedstock & lignin used as fuel 

Corn stover feedstock & lignin used as fuel 

0.00 

0.25 

1.28 

8.80 

1.28 

8.55 

Cellulosic Ethanol – 

Thermochemical Forest waste feedstock 0.00 5.92 5.92 

Biodiesel Soybean oil feedstock 

Yellow grease / tallow feedstock 

0.37 

0.01 

0.79 

0.02 

0.41 

0.01 

Renewable Diesel Yellow grease / tallow feedstock 0.00 0.38 0.38 

Imports Brazilian Sugarcane Ethanol 0.64 3.14 2.50 

The upstream feedstock production and processing impacts for each of the different fuel 

technologies were modeled based on the same assumptions used in determining the per fuel 

lifecycle GHG results described in previous sections. 

For this overall impacts analysis we also used a different petroleum baseline fuel that is 

offset from renewable fuel use. The lifecycle threshold values are required by EISA to be based 

on a 2005 petroleum fuel baseline. For this analysis of the overall impacts of the rule we 

considered the crude oil and finished product that would be replaced in 2022. 

Displaced petroleum product analysis was consistent with work performed for the energy 

security analysis described in Chapter 15. For this analysis we consider that 25% of displaced 

gasoline will be imported gasoline and 0% of displaced diesel fuel will be imported diesel fuel. 

For the types of gasoline displaced we assume 65% of the displaced gasoline will be 

conventional gasoline and 35% will be RFG blendstock gasoline. We assume 100% of the 

displaced diesel fuel will be low sulfur diesel fuel. 

In order to come up with GHG emissions for average crude oil used in producing 

gasoline and diesel fuel in 2022 we assumed 7.6% would be from tar sands and 3.8% would be 

from Venezuelan heavy crude. The basis for this was EIA projections for 2022540. EIA projects 

that roughly 64% of total Canadian crude oil production will be oil sand production in 2022, and 

that roughly 40% of total Venezuelan crude oil production will be heavy crude production in 

2022. EIA also has assumptions on how much crude oil will be imported into the U.S. from 

426 
Canada and Venezuela in 2022. We assumed the percentage of this imported Canadian and 

Venezuelan crude oil that would be oil sands and heavy oil was the same percentage of total 

production that is unconventional crude in those countries (~64% for Canada and ~41% for 

Venezuela). Based on the percent of Canadian and Venezuelan imports to total crude oil 

projected in 2022, oil sands represented 7.6% and heavy oil represented 3.8% of total crude oil 

use. 

For this analysis we did not assume any efficiency improvements at the petroleum 

refining portion of the gasoline and diesel fuel lifecycle. Therefore the same refining energy use 

and emissions was assumed that was used to represent the 2005 petroleum fuel baseline. One the 

one hand this may be overestimating energy use and emission from petroleum refining, however, 

this also does not factor in recent regulations that might increase energy use and emissions, such 

as increased desulfurization of both gasoline and diesel fuel. 

Furthermore, the tailpipe emissions changes were determined based on the specific 

volumes and blends of fuel considered as opposed to looking at only the difference between the 

renewable fuel and petroleum fuel replaced. For highway vehicles, the impact of this rule on 

Methane (CH4) and Nitrous Oxide (N2O) emissions is primarily due to vehicles switching from 

gasoline to E85 fuel. Based on available data, we projected no change in N2O or CH4 emissions 

from highway vehicles that switched from conventional gasoline to E10. For diesel highway 

vehicles, emissions of N20 and CH4 are almost one hundred times less than emissions from 

gasoline vehicles,541 thus diesels were omitted from this analysis. 

E85 effects for this analysis based on available emission data from EPA’s certification 

program, testing performed by EPA as part of the Mobile Source Air Toxic (MSAT) rulemaking, 

and a recent study performed by Environment Canada [insert reference]. This analysis found 

that on a per-vehicle basis using E85 resulted in a 56 percent decrease in N2O emissions and a 

123 percent increase in CH4 emissions. 

To estimate the inventory-wide impact, we used MOVES to model CH4 and N20 for 

highway gasoline vehicles using reference case fuels. Because MOVES does not vary CH4 and 

N20 emissions by temperature or by gasoline fuel properties, the model was run at the annual, 

national level. The control case was modeled by computing an E85 factor for each model year 

and vehicle type that was the product of the proportion of FFV fuel that is E85 and the 

proportion of FFVS in that model year, as described in Chapter 1. FFV use was assumed to be 

limited to light duty cars and light duty trucks. We multiplied the appropriate E85 factor by the 

emissions for that model year and then computed a weighted average of E85 and E10 emissions 

for both CH4 and N2O. In order to compare the results in a meaningful way, we also computed 

the CO2 equivalent by multiplying the tons for each pollutant by the Global Warming Potential 

(310 for N2O, 21 for CH4542) and summing the products. The results are summarized in Table 

2.21 below. 

427 
Table 2.9-2. Tailpipe Nitrous Oxide and Methane Emissions in 2022 

 Pollutant Reference 

Case Tons 

Control 

Case Tons 

Percent 

Change 

LDGV & N2O 31,447 29,191 -7% 

LDGT CH4 50,683 61,853 22% 

CO2 equiv. 10,812,803 10,348,003 -4% 

All Gasoline N2O 33,997 31,741 -7% 

Highway CH4 55,277 66,447 20% 

Vehicles CO2 equiv. 11,699,809 11,235,009 -4% 

Given these many differences, it is clearly not possible to simply add up the individual 

lifecycle results determined in Section 2.8 multiplied by their respective volumes to assess the 

overall rule impacts. The two analyses are separate in that the overall rule impacts capture 

interactions between the different fuels but can not be broken out into per fuels impacts, while 

the threshold values represent impacts of specific fuels but do not account for all the interactions. 

For example, when we consider the combined impact of the different fuel volumes the 

overall land use change is greater than when considering fuel independently, as shown in Table 

2.9-3. 

Table 2.9-3. 

Comparison of International Land Use Change (‘000 Acres) 

 Considering Only 

Change in Soybean 

Based Biodiesel 

Fuel Volumes 

Considering Only 

Change in Corn 

Ethanol Fuel 

Volumes 

Considering Only 

Change in Brazilian 

Sugarcane Ethanol 

Fuel Volumes 

Considering 

Change of all 

Fuel Volumes 

Combined 

Land 

Use 

Change 

880 4,400 3,684 9,867 

The primary reason for the difference in acre change between the sum of the individual 

fuel scenarios and the combined fuel scenarios is that when looking at individual fuels there is 

some interaction between different crops (e.g., corn replacing soybeans), but with combined 

volume scenario when all mandates need to be met there is less opportunity for crop replacement 

(e.g., both corn and soybean acres needed) and therefore more land is required. 

Overall rule impacts were determined for the different components of the lifecycle 

analysis as described in previous sections. The domestic agricultural sector impacts include 

changes in energy use GHG emissions and fertilizer / soil N2O emissions as well as changes in 

livestock and rice production GHG emissions. 

Our analysis indicates that overall domestic agriculture emissions would increase. There 

is a relatively small increase in total domestic crop acres however, there are additional inputs 

required due to the removal of crop residues. The assumption is that removal will require more 

inputs to make up for lost residue nutrients. These additional inputs result in GHG emissions 

428 
from production and from N2O releases from application. This effect is somewhat offset by 

reductions due to lower livestock production. These results are dependent on our agricultural 

sector input and emission assumptions that are being updated for the final rule (e.g., N2O 

emission factor work). 

As with domestic agriculture impacts, the international agricultural sector impacts 

include changes in energy use GHG emissions and fertilizer / soil N2O emissions as well as 

changes in livestock and rice production GHG emissions. 

Increased crop production internationally resulted in increased fertilizer and fuel use 

emissions, however, these are offset by reductions in livestock GHG emissions. Higher 

commodity crop prices internationally are resulting in lower livestock production internationally. 

We estimate the largest overall agricultural sector impact is an increase in land use 

change impacts, reflecting the shift of crop production both domestically and internationally to 

meet the biofuel demand in the U.S., and land use change emissions associated with converting 

land into crop production. 

Domestic soil carbon change impacts are negative reflecting the soil carbon changes 

associated with crop shifting and production. There are several factors impacting this result, 

switchgrass has a large benefit in terms of soil carbon and carbon sequestration. Residue 

removal is greater on low and no till cropping management practices, and larger removal rates 

shift to some of these practices and result in increased soil carbon sequestration. However, land 

use change impacts are dominated by the international acreage and land use change increase. 

Other portions of the biofuel lifecycle include fuel production and feedstock and fuel 

transport. We project reductions in GHG emissions from the renewable fuel production portion 

of the lifecycle due to the generation of electricity along with the increased production of 

cellulosic ethanol. A large portion of the cellulosic ethanol production is assumed to be 

produced through the enzymatic process which also produces excess electricity to be sold to the 

grid. This excess electricity is offsetting grid electricity production and results in GHG benefits. 

Cellulosic biofuels contribute by far the most to the total emission reductions due to both their 

superior per gallon emission reductions and the large volume of these fuels anticipated to be used 

by 2022. Process emission reductions are partially offset by both feedstock and fuel 

transportation emissions. 

CO2 produced in the combustion of biofuels is offset by the uptake of CO2 in the 

biomass crop used to produce the fuel, resulting in a significant net reduction of CO2 compared 

to fossil fuel tailpipe combustion. Net carbon fluxes from changes in biogenic carbon reservoirs 

in wooded or crop lands associated with land use change are accounted for in the domestic and 

international agriculture impacts shown in upstream impacts. In addition we assume biofuel use 

is offsetting petroleum fuel production which also results in GHG emissions reductions from 

reduced upstream emissions of petroleum fuel production (crude oil extraction and transport, 

refining, transport). 

429 
The results of the individual lifecycle stage results can be summed to determine the 

overall GHG impact of the proposed rulemaking. As discussed in previous sections on lifecycle 

GHG thresholds there is an initial one time release from land conversion and smaller ongoing 

releases but there are also ongoing benefits of using renewable fuels over time replacing 

petroleum fuel use. Figure 2.9-2 shows the GHG emissions impact of the change in fuel 

volumes considered over time. 

Figure 2.9-2. GHG Impacts over time 

-4,500,000,000 

-4,000,000,000 

-3,500,000,000 

-3,000,000,000 

-2,500,000,000 

-2,000,000,000 

-1,500,000,000 

-1,000,000,000 

-500,000,000 

0 

500,000,000 

1,000,000,000 

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 

Time Since Initial Land Use Change (years) 

Net Total GHG Impacts (MT CO2-eq.)

Land Use Change Impacts 

Ongoing Benefits (w/o Land Use Change) 

Net Cumulative Total Emissions Over Time 

Based on the volume scenario considered the one time land use change impact results in 

448 million metric tons of CO2-eq. emissions. There are however, based on the biofuel use 

replacing petroleum fuels, annual reduction benefits of 161 million metric tons of CO2-eq. 

emissions. This results in a less than two year payback period before the ongoing benefits of the 

biofuels use offsets the initial land use impacts. 

The timing of the impact of land use change and ongoing renewable fuels benefits were 

discussed in the previous lifecycle results section. The issue is slightly different for this analysis 

since we are considering absolute tons of emissions and not determining a threshold comparison 

to petroleum fuels. However the results can be presented in a similar manner to our individual 

fuels analysis in that we can determine net benefits over time with different discount rates and 

over a different time frame for consideration. 

430 
 

 

If we consider a 2% discount rate and 100 years of benefits (i.e., 161 million tons of 

GHG emissions reductions per year) we get an estimated discounted NPV reduction in GHG 

emissions of 6.8 billion tons of GHG emissions. Assuming a 0% discount rate over 30 years 

would result in an estimate of 4.5 billion tons of discounted GHG emission reductions. 

Furthermore, for the calculations of the monetized GHG benefits we calculate an 

annualized NPV GHG reduction. This annualized value is based on converting a lump sum 

present value into its annualized equivalent. For this analysis we convert the NPV results for the 

100 year 2% discount rate into an annualized stream such that the NPV of the annualized 

emissions will equal the NPV of the emission stream over 100 years with a 2% discount rate. 

This results in an annualized emission reduction of 160 million metric tons of CO2-eq. 

emissions. With a 30 year time horizon and 0% discount rate the annualized emission reduction 

is 150 million metric tons CO2-eq. 

2.10 Effects of GHG Emission Reductions and Changes in Global 

Temperature and Sea Level 

2.10.1 Introduction 

The reductions in CO2 and other GHGs associated with the proposal will affect climate 

change projections. Because GHGs mix well in the atmosphere and have long atmospheric 

lifetimes, changes in GHG emissions will affect future climate for decades to centuries. One 

common indicator of climate change is global mean surface temperature. This section estimates 

the response in global mean surface temperature and sea level rise projections to the estimated 

net global GHG emissions reductions associated with the Proposed Rulemaking (See Section 

2.9) for the estimated net reductions in global emissions over time by GHG). 

2.10.2 Estimated Projected Reductions in Global Mean Surface Temperatures 

EPA estimated changes in projected global mean surface temperatures to 2100 using the 

MiniCAM (Mini Climate Assessment Model) integrated assessment modelEEEEEEEE coupled with 

the MAGICC (Model for the Assessment of Greenhouse-gas Induced Climate Change) simple 

EEEEEEEE MiniCAM is a long-term, global integrated assessment model of energy, economy, agriculture and land use, 

that considers the sources of emissions of a suite of greenhouse gases (GHG's), emitted in 14 globally disaggregated 

global regions (i.e., U.S., Western Europe, China), the fate of emissions to the atmosphere, and the consequences of 

changing concentrations of greenhouse related gases for climate change. MiniCAM begins with a representation of 

demographic and economic developments in each region and combines these with assumptions about technology 

development to describe an internally consistent representation of energy, agriculture, land-use, and economic 

developments that in turn shape global emissions. Brenkert A, S. Smith, S. Kim, and H. Pitcher, 2003: Model 

Documentation for the MiniCAM. PNNL-14337, Pacific Northwest National Laboratory, Richland, Washington. 

For a recent report and detailed description and discussion of MiniCAM, see Clarke, L., J. Edmonds, H. Jacoby, H. 

Pitcher, J. Reilly, R. Richels, 2007. Scenarios of Greenhouse Gas Emissions and Atmospheric Concentrations. Subreport 2.1A of Synthesis and Assessment Product 2.1 by the U.S. Climate Change Science Program and the 

Subcommittee on Global Change Research. Department of Energy, Office of Biological & Environmental Research, 

Washington, DC., USA, 154 pp. 

431 
 

 

climate model.FFFFFFFF MiniCAM was used to create the globally and temporally consistent set 

of climate relevant variables required for running MAGICC. MAGICC was then used to 

estimate the change in the global mean surface temperature over time. Given the magnitude of 

the estimated emissions reductions associated with the proposed rule, a simple climate model 

such as MAGICC is reasonable for estimating the climate response. 

EPA applied the estimated annual GHG emissions changes for the proposal to the 

MiniCAM U.S. Climate Change Science Program (CCSP) Synthesis and Assessment Product 

baseline emissions. Specifically, the CO2, N2O, and CH4 annual emission changes from 2022­

2121 from Section 2.9 were applied as net reductions to the MiniCAM CCSP global baseline net 

emissions for each GHG. Post-2121, we assumed no change in emissions from the baseline. 

This assumption is more conservative than allowing the emissions reductions to continue. 

Table 2.10-1 provides our estimated reductions in projected global mean surface 

temperatures and sea level associated with the proposed increase in renewable fuels in 2022. To 

capture some of the uncertainty in the climate system, we estimated the changes in projected 

temperatures and sea level across the most current Intergovernmental Panel on Climate Change 

(IPCC) range of climate sensitivities, 1.5°C to 6.0°C.GGGGGGGG To illustrate the time profile of 

the estimated reductions in projected global mean surface temperatures and sea level, we have 

also provided Figures 2.10-1 and 2.10-2. 

FFFFFFFF MAGICC consists of a suite of coupled gas-cycle, climate and ice-melt models integrated into a single 

framework. The framework allows the user to determine changes in GHG concentrations, global-mean surface air 

temperature and sea-level resulting from anthropogenic emissions of carbon dioxide (CO2), methane (CH4), nitrous 

oxide (N2O), reactive gases (e.g., CO, NOx, VOCs), the halocarbons (e.g. HCFCs, HFCs, PFCs) and sulfur dioxide 

(SO2). MAGICC emulates the global-mean temperature responses of more sophisticated coupled 

Atmosphere/Ocean General Circulation Models (AOGCMs) with high accuracy. Wigley, T.M.L. and Raper, S.C.B. 

1992. Implications for Climate and Sea-Level of Revised IPCC Emissions Scenarios Nature 357, 293-300. Raper, 

S.C.B., Wigley T.M.L. and Warrick R.A. 1996. in Sea-Level Rise and Coastal Subsidence: Causes, Consequences 

and Strategies J.D. Milliman, B.U. Haq, Eds., Kluwer Academic Publishers, Dordrecht, The Netherlands, pp. 11-45. 

Wigley, T.M.L. and Raper, S.C.B. 2002. Reasons for larger warming projections in the IPCC Third Assessment 

Report J. Climate 15, 2945-2952. 

GGGGGGGG In IPCC reports, equilibrium climate sensitivity refers to the equilibrium change in the annual mean global 

surface temperature following a doubling of the atmospheric equivalent carbon dioxide concentration. The IPCC 

states that climate sensitivity is “likely” to be in the range of 2°C to 4.5°C and described 3°C as a "best estimate." 

The IPCC goes on to note that climate sensitivity is “very unlikely” to be less than 1.5°C and “values substantially 

higher than 4.5°C cannot be excluded.” IPCC WGI, 2007, Climate Change 2007 - The Physical Science Basis, 

Contribution of Working Group I to the Fourth Assessment Report of the IPCC, http://www.ipcc.ch/. 

432 
 

 

 

 

Table 2.10-1. 

 Estimated Reductions in Projected Global Mean Surface Temperature and Global Mean 

Sea Level from Baseline in 2030, 2050, 2100, and 2200 for the Proposed Standard in 2022
 

Climate sensitivity 

1.5 2 3 4.5 6 

Change in global mean surface temperatures (degrees Celsius) 

2030 0.000 0.000 -0.001 -0.001 -0.001

2050 -0.001 -0.002 -0.002 -0.002 -0.003

2100 -0.003 -0.004 -0.005 -0.006 -0.007

2200 -0.003 -0.004 -0.006 -0.008 -0.009

Change in global mean sea level rise (centimeters) 

2030 -0.002 -0.002 -0.003 -0.003 -0.003

2050 -0.012 -0.014 -0.017 -0.020 -0.022

2100 -0.045 -0.052 -0.063 -0.074 -0.082

2200 -0.077 -0.091 -0.114 -0.143 -0.172

The results in Table 2.10-1 and Figures 2.10-1 and 2.10-2 show small, but detectable 

reductions in the global mean surface temperature and sea level rise projections across all climate 

sensitivities. Overall, the reductions are small relative to the IPCC’s “best estimate” temperature 

increases by 2100 of 1.8oC to 4.0oC.HHHHHHHH Although IPCC does not issue “best estimate” sea 

level rise projections, the model-based range across SRES scenarios is 18 to 59 cm by 2099.IIIIIIII 

Both figures illustrate that the overall emissions reductions can decrease projected annual 

temperature and sea level for all climate senstitivities. This means that the distribution of 

potential temperatures in any particular year is shifting down. However, the shift is not uniform. 

The magnitude of the decrease is larger for higher climate sensitivities. Thus, the probability of a 

higher temperature or sea level in any year is lowered more than the probability of a lower 

temperature or sea level. For instance, in 2100, the reduction in projected temperature for climate 

sensitivities of 3 and 6 is approximately 65% and 140% greater than the reduction for a climate 

sensitivity of 1.5. This difference grows over time, to approximately 80% and 185% by 2200. 

The same pattern appears in the reductions in the sea level rise projections.JJJJJJJJ Also 

noteworthy in Figures 2.10-1 and 2.10-2, is that the size of the decreases grows over time due to 

the cumulative effect of a lower stock of GHGs in the atmosphere (i.e., concentrations).KKKKKKKK 

HHHHHHHH IPCC WGI, 2007. The baseline increases by 2100 from our MiniCAM-MAGICC runs are 2°C to 5°C for 

global mean surface temperature and 35 to 74 centimeters for global mean sea level. IIIIIIII “Because understanding of some important effects driving sea level rise is too limited, this report does not 

assess the likelihood, nor provide a best estimate or an upper bound for sea level rise.” IPCC Synthesis Report, p. 45

JJJJJJJJ In 2100, the reduction in projected sea level rise for climate sensitivities of 3 and 6 is approximately 40% and 

80% greater than the reduction for a climate sensitivity of 1.5. This difference grows over time, to approximately 

50% and 120% by 2200. 

KKKKKKKK For global average temperature after 2100, the growth in the size of the decrease noticeable slows. This is 

because the emissions changes associated with the policy were only estimated for 100 years. Note that even with 

emissions reductions stopping after 100 years, there continues to be a decrease in projected temperatures due to 

reduced inertia in the climate system from the earlier emissions reductions. However, unlike temperature, after 2100, 

433 
 

 

 Degrees Celsius 

The bottom line is that the risk of climate change is being lowered, as the probabilities of 

any level of temperature increase and sea level rise are reduced and the probabilities of the 

largest temperature increases and sea level rise are reduced even more. For the Final 

Rulemaking, we hope to more explicitly estimate the shapes of the distributions and the 

estimated shifts in the shapes in response to the Rulemakings. 

Figure 2.10-1 

Estimated Projected Reductions in Global Mean Surface Temperatures across 

Climate Sensitivities (CS) for the Proposed Standard in 2022 

0.000 

199020002010202020302040205020602070208020902100211021202130214021502160217021802190220022102220223022402250 

-0.002 

-0.004 

-0.006 

-0.012 

-0.010 

-0.008 CS = 1.5 

CS = 2.0 

CS = 3.0 

CS = 4.5 

CS = 6.0 

the size of the decrease in sea level rise increases as the projected reduction in warming has a continued effect on ice 

melt and ocean thermal expansion. 

434 
Figure 2.10-2
 

Estimated Projected Reductions in Global Mean Sea Level across Climate Sensitivities 

(CS) for the Proposed Standard in 2022 

0.000 

199020002010202020302040205020602070208020902100211021202130214021502160217021802190220022102220223022402250 

Centimeters 

-0.050 

-0.100 

-0.150 

-0.200 

-0.250 

CS = 1.5 

CS = 2.0 

CS = 3.0 

CS = 4.5 

CS = 6.0 

435 
Chapter 3: Impacts of the Program on Non-GHG Pollutants 

In addition to the GHG impacts laid out in Chapter 2, we project that today’s proposal 

will affect emissions of “criteria” pollutants (those pollutants for which a National Ambient Air 

Quality Standard has been established), criteria pollutant precursors, and air toxics. Changes in 

these emissions would derive from the direct effect of renewable fuels on the tailpipe and 

evaporative emissions of vehicles and off-road equipment; and increased renewable fuel 

production and distribution including the effect of decreases in the production and distribution of 

gasoline and diesel displaced by renewable fuel. For today’s proposal we have focused on 

estimating the change in mass emissions for these pollutants across the entire U.S. in 2022, when 

the program is fully implemented; for the final rule we plan to conduct full-scale air quality 

modeling and health impact assessment as well. This chapter presents national emission impacts 

for nitrogen oxides (NOx), volatile organic compounds (VOC), carbon monoxide (CO), 

particulate matter 10 microns in diameter and less (PM10), particulate matter 2.5 microns in 

diameter and less (PM2.5), sulfur dioxide (SO2), ammonia (NH3),, benzene, 1,3-butadiene, 

acrolein, formaldehyde, acetaldehyde, naphthalene, and ethanol. This chapter also presents the 

methodology for developing these estimates and discusses air quality and health impacts 

qualitatively. 

3.1 Methodology for Calculating Non-GHG Emission Impacts 

Our analysis focused on the projected impact of today’s proposed action in 2022, the first 

full year of implementation. The impacts of the program were quantified as the difference in 

mass emissions between the proposed volumes and several reference cases, as presented in 

Section 3.2. In order to allow assessment of total emission impacts of mandated renewable 

volumes, the main reference case presented in this analysis was the RFS1 mandate volume of 7.5 

billion gallons of renewable fuel (6.7 billion gallons ethanol). We are also presenting impacts 

relative to the roughly 14 billion gallons of renewable fuels projected by the Department of 

Energy (DOE) Annual Energy Outlook (AEO) 2007 (summarized in Table V.A.1-1 of the 

Preamble to today's proposal) to show the impact of today’s action incremental to the projected 

renewable market pre-EISA. Finally, we also present impacts relative to the pre-RFS1 baseline 

of roughly 4 billion gallons renewable fuel. Due to time constraints, for the proposed rule we did 

not perform separate modeling runs for each reference case. Rather, we focused our modeling 

on the impacts between the AEO reference case and control case, and scaled our estimates of 

national emissions based on the volumes of ethanol. For the final rule inventories and air quality 

work we intend to model two of these reference cases - RFS1 mandate and AEO. 

Our analysis of non-GHG emissions impacts was comprised of a) an analysis of direct 

impacts on motor vehicles, off-road equipment and other sources from burning (or evaporating) 

renewable fuels in place of petroleum-based fuels; and b) the emissions impacts from the 

production and distribution of renewable fuels. These analyses are discussed separately in 

Sections 3.1.1 and 3.1.2. 

436 
3.1.1 Impact on Non-GHG Emissions from Motor Vehicles and Equipment 

Today’s proposed volumes of renewable fuel will directly affect emissions from most 

mobile source categories, and for this analysis we have quantified the effects on exhaust and 

evaporative emissions of gasoline-fueled vehicles and equipment including passenger cars, light 

trucks, heavy trucks, motorcycles and off-road sources such as lawn mowers, recreational boats 

and all-terrain vehicles. We have also estimated the impact of ethanol on emissions from 

portable fuel containers, and increased refueling emissions due to higher volatility of ethanolblended fuel and increased refueling events due to lower energy content of biofuels. The 

emissions impacts of biodiesel were also estimated on heavy-duty diesel vehicles, assuming 

additional biodiesel would be burned by on-road sources. 

A considerable source of uncertainty in estimating the emission impacts of renewable 

fuels is the effect ethanol blends will have on emissions of cars and light trucks. Under today’s 

proposed action every gasoline vehicle and piece of equipment would be fueled on at least E10, 

and with the volumes of E85 projected necessary to meet today’s mandate, we estimate that, on 

average, flexible fueled vehicles with access to E85 would need to be using E85 about 74 

percent of the time. The impacts of E10 emissions have been studied for years, but current data 

on newer technology vehicles is not definitive on its impact on NOx and exhaust VOC 

emissions. Data on E85 is limited, and the results show large variability of emission effects in 

some pollutants. EPA is in the midst of a large-scale emission testing program to improve our 

understanding of fuel effects on Tier 2 cars and trucks, and we expect our analysis for the final 

rule to reflect the results of this program.543 In the meantime, in order to help bound the 

uncertainty of exhaust fuel effects, we calculated emissions impacts for two vehicle fuel effects 

scenarios as detailed in Section 3.1.1.2. 

EPA is in the process of updating its mobile source emission platform to the Motor 

Vehicle Emissions Simulator (MOVES). For the analysis of gasoline-fueled highway vehicles, a 

pre-draft version of MOVES was used to generate national inventories based on the fuel supply 

scenarios determined for the RFS2. Although the model is not complete, we decided to use a 

pre-release version of MOVES for this analysis to begin to reflect significant updates in 

emissions from MOBILE6. As the other mobile source categories in MOVES were still under 

development at the time of this analysis, onroad diesel vehicles and all off-road equipment 

emissions were calculated with the National Mobile Inventory Model (NMIM) model, a platform 

which generates emission inventories based on EPA’s MOBILE6 and NONROAD models. 

The development of vehicle and equipment emission impact estimates for today’s 

proposal required: a) developing fuel supply inputs at the county level for the 2005 base year 

and 2022 reference and control cases which accounted for the projected change in fuel properties 

due to today’s proposed action; b) developing individual vehicle fuel effects; and c) running 

MOVES and NMIM to produce raw inventory estimates and post-processing these results as 

needed to account for different baselines, to apply “off model” corrections, or to estimate 

impacts not accounted for in the models. Each of these steps are detailed in the following 

sections 

437 
3.1.1.1 Fuel Inputs 

As inputs to our emissions modeling, we developed a detailed profile of fuels for each 

modeling case. We prepared county-level databases of fuel properties and fuel market shares for 

the 2005 base case and the 2022 AEO reference case and 2022 control case. These county-level 

databases were applied in both NMIM and MOVES for consistency in fuel inputs across the 

different mobile source categories. 

The 2005 base case fuel properties were derived from 2005 historical data. These data 

included national summer and winter fuels surveys, studies that tracked the total amount of 

ethanol produced for use in gasoline each year, and Reformulated Gasoline (RFG) 

measurements. Additional data were available on the fuel properties of all gasoline produced 

and imported annually by refiners, and on the distribution of gasoline to and from Petroleum 

Administration for Defense Districts (PADDs). Where survey data was available, it was used to 

determine a county's fuel properties for summer and winter. Where survey data was not 

available, fuel properties were set to equal the average fuel properties in that PADD. Special 

adjustments were made to some counties to account for local gasoline volatility control programs 

and winter oxygenated gasoline programs. 

For the 2022 reference and control cases, the 2005 base case fuel properties were 

adjusted to account for implementation of other fuel regulations and to account for increased 

ethanol use. There is a greater percentage of ethanol in the 2022 AEO reference case than in the 

2005 base case because methyl tert-butyl ether (MTBE) has been replaced with ethanol and 

because of AEO projected growth in ethanol production for 2022. For this analysis, ethanol was 

allocated to the state and county level based on the economics of distribution and blending, as 

well as other factors. Refer to Section 1.7.1 of this document for details. The 2022 control case 

models the requirements of EISA, in which approximately 34 bgal of ethanol are present in the 

fuel supply for 2022. The control case models this by assigning E10 gasoline to all U.S. 

counties, and E85 based on the economics of distribution, blending and other factors. 

In general, future fuel properties in both the reference and control cases were adjusted to 

account for widespread increases in ethanol under the assumption that, while historically ethanol 

has been splash blended in conventional gasoline (CG), it will be match-blended (i.e., the 

changes associated with ethanol addition will be accounted for by refiners when producing the 

base gasoline) by 2022. We believe this is reasonable given that there will be a large (and thus 

more geographically predictable) volume of ethanol used in gasoline, and that certain property 

changes that take place when ethanol is blended (such as octane increase) could be financially 

beneficial to refiners if able to be assumed when producing the base gasoline. Thus, we adjusted 

aromatics, olefins, T50, and T90 fuel parameters by first backing out the effects of any existing 

oxygenate (by reverse dilution), and then re-adjusting the properties for ethanol blends based on 

refinery modeling done for the RFS1 rulemaking that projected how gasoline properties were 

likely to change given widespread use of ethanol. Table 3.1-1 shows the adjustment factors used 

per volume percent ethanol blended. Reid Vapor Pressure (RVP) was increased 1.0 psi wherever 

ethanol was present in conventional gasoline unless there was a state constraint. 

438 
Table 3.1-1. 2022 Adjustments for Ethanol Added to Conventional Gasoline 

 Aromatics 

(vol%) 

Olefins 

(vol%) 

E200 

(vol%) 

E300 

(vol%) 

Additive change per 

vol% ethanol added -0.464 0.019 0.909 0.063 

For Reformulated Gasoline (RFG) areas, refiners already account for the blending of 

ethanol when producing the base gasoline, and therefore the properties are not predicted to 

change in the same ways as for conventional gasoline (CG). We used refinery modeling results 

for each PADD (produced along with those above for CG) to project the properties of fuel in 

RFG areas accounting for increased ethanol in the national gasoline pool. RFG properties used 

in the reference and control cases in 2022 are shown here in Table 3.1-2. The 2022 reference 

and control cases also incorporate reductions in gasoline sulfur resulting from Tier 2 regulations. 

It should be noted that fuel benzene levels presented in this table are higher than what they 

should be, given impacts of the 2007 mobile source air toxics (MSAT) rule, which mandates a 

0.62% fuel benzene standard.544 For the final rule, we will use more recent refinery modeling, 

which provides better estimates of benzene levels with implementation of the MSAT rule. 

Table 3.1-2. 2022 Reformulated Gasoline Properties by PADD 

PADD RVP 

(psi) 

Aromatics 

(vol%) 

Benzene 

(vol%) 

Olefins 

(vol%) 

E200 E300 

Summer 

1 7.0 20.1 0.70 13.9 56.0 83.5 

2 7.1 17.9 0.76 17.3 54.1 81.8 

3 7.0 20.0 0.76 14.1 52.0 87.5 

5 6.8 22.5 0.61 5.7 54.5 86.2 

Winter 

1 12.8 19.6 0.71 15.3 60.8 83.2 

2 13.0 17.8 0.64 12.3 63.9 79.5 

3 11.8 21.2 0.64 12.6 53.4 87.5 

5 12.6 23.7 0.61 5.7 58.2 86.2 

For the control case, we also modeled flexible-fueled vehicles running on E85. For most 

emissions, these effects were modeled using fuel adjustments as described in Section 3.1.1.2, 

below. However, in MOVES, vapor venting emissions and sulfate emissions are calculated 

directly from the RVP and sulfur level of the fuel. These properties were derived for E85 fuels 

from the properties of the same county's E10 fuel in the control case, with the RVP adjusted to 

account for the lower vapor pressure of E85.545 and the sulfur level adjusted to 15% of that of the 

original E10 fuel in that county. The predicted sulfur adjustment underestimates the actual sulfur 

content of the fuel because it neglects the sulfur content of ethanol (about 1.5 ppm) and it does 

not account for any refinery increases in sulfur in the base gasoline; thus the benefit attributed to 

sulfate reductions in the E85 case may be overestimated. 

For each of the modeled scenarios, fuel information was input into an NMIM database 

and used for NMIM runs. For MOVES runs, the NMIM databases were converted into MOVES 

439 
 

databases using a conversion program. To reduce time needed for MOVES runs, we reduced the 

size of the MOVES fuel database by processing the database with a "binner" program that 

grouped fuels with similar properties and assigned each group to a single fuel formulation 

identification number and a single set of fuel properties. 

3.1.1.2 Effect of Fuels on Non-GHG Emissions from Vehicles & Equipment 

The average effect of renewable fuels on an individual vehicle basis, based on available 

research, are the foundation of the emission impact assessment. This section contains discussion 

of the effects used in the emission impact assessment for E10 on gasoline vehicles and 

equipment, for E85 on gasoline vehicles, and for biodiesel. 

3.1.1.2.1 On-road Gasoline Vehicle E10 Effects 

3.1.1.2.1.1 Exhaust Emissions 

A 10 percent ethanol blend can affect exhaust emissions from vehicles and off-road 

equipment. A comprehensive analysis of E10 impacts on exhaust emissions was undertaken for 

the RFS1 rule, as documented in Chapter 3 of the RFS1 Regulatory Impact Analysis.546 This 

analysis considered previous EPA work in coming up with a so-called “Predictive Model” to 

assess California’s request for an oxygenate waiver in 2000, as well as test data from several test 

programs conducted by the auto trade associations (AAM/AIAM), ExxonMobil, Toyota, and the 

Mexican Petroleum Institute. This assessment concluded that for Tier 1 and later vehicles 

(nominally model year 1996 and later, comprising the majority of the fleet in 2022) there was not 

enough consistency across these studies to confidently predict the impact of oxygenated fuel on 

exhaust HC and NOx emissions. As a result the RFS1 analysis carried forward two sets of fuel 

effects: a “primary” analysis assuming no effect of oxygen on non-methane hydrocarbon 

(NMHC) and NOx emissions from Tier 1 and later vehicles, and a “sensitivity” analysis which 

applied EPA’s Predictive Model effects to Tier 1 and later vehicles. 

We are the midst of a large scale testing effort, scheduled for completion in 2009, aimed 

at quantifying the effects of several fuel parameters, including ethanol and other fuel properties 

impacted by the blending of ethanol into gasoline, on exhaust and evaporative emissions from 

Tier 2 vehicles.547 It is our expectation that data from this program will be used in our analysis 

for the final rule. For this proposal we are analyzing two ethanol effect scenarios: “less 

sensitive” based on the “primary” case used in RFS1, and “more sensitive” based on the RFS1 

“sensitivity” case. While the effects of E10 on individual vehicles will vary depending on 

properties of the fuel (e.g., RVP, distillation, and aromatic content), Table 3.1-3 demonstrates 

the effects used for conventional and reformulated gasoline based on the fuel properties derived 

from Tables 3.1-1 and 3.1-2. The effects shown for NOx, HC and toxics were applied to only 

Tier 0 vehicles (mid 1990’s and older) in the “less sensitive” case, and to all vehicles in the 

“more sensitive” case. 

440 
 

 

Table 3.1-3. Exhaust Effect of E10 Relative to E0 a 

Pollutant Source CG RFG 

Exhaust HC (VOC) EPA Predictive -7.4% -9.7% 

NOx Models 7.7% 7.3% 

COb

 MOBILE6.2 -11% / -19% -36% 

Exhaust Benzene EPA Predictive -24.9% -38.9% 

Formaldehyde and Complex 6.7% 2.3% 

Acetaldehyde Models 156.8% 173.7% 

1,3-Butadiene -13.2% 6.1% a

Assumes summer (July) conditions 

b

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

3.1.1.2.1.2 Evaporative Emissions 

3.1.1.2.1.2.1 Permeation 

E10 affects evaporative emissions from gasoline vehicles due to the increased volatility 

of E10 blends, the increased permeation of fuel vapors through tanks and hoses, and the 

increased vapor emissions due to the lower molecular weight of E10. Each of these effects were 

modeled using the draft MOVES model, which separates permeation emissions from vapor 

venting emissions to allow better accounting for these different processes. 

Permeation effects were developed from Coordinating Research Council's (CRC) E-65 

program548, which measured evaporative emissions from ten fuel systems that were removed 

from the vehicles on E0 and E5.7 fuels; fuel systems were removed to ensure that all evaporative 

emissions measured were from permeation of the fuel through the different components of the 

fuel system. For this analysis, we estimated the effect by calculating the percent increase in 

average emissions from all vehicles between E0 and E5.7 fuels over the 65 to 105 degree 

Fahrenheit diurnal test. This value was 46 percent. In order to estimate the effect at E10 we 

simply multiplied this result by 1.75 (10/5.7), resulting in a 79 percent increase applied to cars 

and light trucks from all model years. 

This approach heavily weights the emission contribution of older vehicles in the test 

program, and, in conjunction with lower emission rates for vehicles certified to Enhanced 

Evaporative and later standards in MOVES, may underestimate the impact of E10 on permeation 

from newer vehicles. The limited data on vehicles certified to Enhanced Evaporative standards 

showed an increase of 232 percent, versus 46 percent for all vehicles. We expect CRC to 

release a significant body of new E-77 program permeation data on later model vehicles before 

the end of 2008. We plan to revisit our permeation emissions estimates when these results are 

available. 

3.1.1.2.1.2.2 Tank Vapor Venting 

In MOVES, tank vapor venting (TVV) emissions from controlled vehicles are modeled 

as a function of uncontrolled vapor generation (TVG), which is affected by both ethanol content 

and RVP according to the formula (Reddy, 1989): 

441 
 

 

 

 

B*RVP CTx CT2 TVG = Ae (e − e ) 

where A, B, and C are coefficient dependent on ethanol level as described in the table 3.1-4, and 

Tx and T2 are the temperatures at the start and end point of the vapor generation period. 

Table 3.1-4. Tank Vapor Venting Coefficients (at sea level)

 E0 E10 

Constant 

A 0.0082 0.0088 

B 0.2357 0.2056 

C 0.0409 0.0430 

In MOVES, the relationship between TVV and TVG is a function of vehicle model year, 

temperature rise, and whether RVP is held constant or increased with the additional of ethanol. 

For example, for the 1978-1995 model year group over a temperature rise of 65 to 105 degrees F, 

the increase in tank vapor venting emissions is 6 percent for E10 relative to E0 with no change in 

RVP. However, the same scenario a 1.0 psi increase results in an increase in tank vapor venting 

emissions of 46 percent. The national impacts presented in this analysis reflect a composite 

effect of the mix of vehicle model years in 2022, hourly temperature differentials by county, and 

county-specific fuel property changes with the addition of ethanol. 

3.1.1.2.2 On-road Gasoline vehicle E85 effects 

As discussed in Section 1.7.1, because ethanol blended into E10 everywhere in the U.S. 

would account for less than half of the mandated ethanol volumes, we project that nearly 30 

billion gallons of E85 will be required to fulfill the mandate. E85 is by no means a new fuel - 

automakers have been producing flex fuel vehicles (FFVs) capable of operating on E85 since the 

early 1990s. Nonetheless, there are relatively few sources of data available comparing the 

emissions of non-oxygenated (E0) and high-level (E85) ethanol blended fuels either for older 

(Tier 0 and 1), and particularly for current technology (i.e. Tier 2) vehicles. Understanding the 

emissions effects of E85 on the latter group of vehicles is of particular importance since Tier 2 

FFVs will dominate the FFV fleet in future years. For this reason, we focused our analysis for 

this proposed rulemaking on newer technology (i.e. LEV and later) vehiclesLLLLLLLL. 

For this analysis we identified three recent data sources that investigate the effects of E85 

549, 550, 551 on current technology (i.e. Tier 2 and similar) vehiclesMMMMMMMM. Two of these 

sources are test programs conducted by Southwest Research Institute and Environment Canada, 

and the third is EPA certification data. This section briefly describes each data source and 

highlights the key findings, and explains how these data were used to generate E85 effects. 

In 2006, Southwest Research Institute (SwRI) conducted a study for EPA on three model 

year 2005 Tier 2 FFVs (bins 5 and 8) operating on several gasoline and ethanol blends. This 

LLLLLLLL For a discussion of the effect of E85 on older technology vehicles, see Chapter 3 of the RFS RIA available 

here: http://www.epa.gov/otaq/renewablefuels/420r07004chap3.pdf MMMMMMMM EPA is aware of several test programs, either planned or underway, by CRC and others that may provide 

additional test data for future fuel effects modeling and rulemaking support. 

442 
study was primarily focused on the impacts of fuel ethanol content and reduced ambient test 

temperature (tests were conducted at 75oF and 20oF) on VOC and PM emissions. Multiple fuel 

blends were evaluated in this program, although for this analysis we will focus only on E0 and 

E85 emissions at 75o F. At this test temperature, Tier 2 certification fuel was used as the nonoxygenated test fuel (E0) as well as the base gasoline for the splash-blended E10 and E85 fuels. 

Additionally, EPA certification “cold CO” wintertime gasoline was used for reduced ambient 

temperature (20 oF) testing – used alone (E0) and as the base fuel for wintertime E10 and E70 

blends. This base gasoline has a higher RVP than its summertime equivalent, which is necessary 

to ensure proper fuel vaporization at lower ambient temperatures. Repeat tests were conducted 

for the 20oF tests on the winter fuel blends, but no repeats were run for 75oF testing. In addition 

to the regulated pollutants, SwRI measured CO2, CH4, benzene, 1,3-butadiene, naphthalene, 

acetaldehyde, acrolein, and ethanol. This study saw reductions in PM 2.5, benzene, and 1,3­

butadiene of 55% - 70% with E85 relative to E0. HC emissions increased while NOx and CO 

decreased. Emissions of methane, formaldehyde, and acetaldehyde were found to increase 

significantly with E85 use. Table 3.1-6 summarizes the average percent change in emissions 

with E85 vs. E0. This table also compares the findings of this dataset with the other two 

programs described below. 

Environment Canada released a report in 2005 in which an NLEV and an interim nonTier 2 vehicle were tested on Tier 2 certification fuel and a commercially available E85 blend. 

Repeat tests were conducted in this study so that each vehicle was tested three times on each 

fuel. The pollutants measured include NMOG, NMHC, CO, NOx, CO2, CH4, N20, benzene, 

1,3-butadiene, acetaldehyde, formaldehyde, acrolein, and ethanol, among others. The results, 

summarized in Table 3.1-6 showed statistically significant reductions in CO and NOx (-48% 

and -40%, respectively) when switching from E0 to E85. E85 caused non-methane organic gases 

(NMOG) emissions to increase in one vehicle and decrease in the other. Toxics reductions were 

of a similar order of magnitude as the vehicles tested in the SwRI study discussed above 

EPA’s Certification and Fuel Economy Information System (CFEIS) database was 

accessed to identify data from five model year 2006 Tier 2 vehicles (bins 5, 8, and 9) tested on 

both E85 and Tier 2 certification gasoline. The E85 blend tested here was 85% denatured 

ethanol splash blended with 15% Tier 2 certification gasoline. Each vehicle was only tested once 

on each fuel. Weighted FTP results were reported for the regulated pollutants (except PM) as 

well as CO2, acetaldehyde, and ethanol (formaldehyde, acetaldehyde, and ethanol were only 

measured for tests where E85 was used; therefore these are expressed as fractions of NMOG 

here). This data indicates that E85 causes a slight increase in NMOG emissions, a slight 

decrease in NOx and CO2, and significant reductions in CO. The average percent change in 

each pollutant for these vehicles when operated on E85 is shown in Table 3.1-5, below. 

443 
 

Table 3.1-5. 

Effect of E85 on LEV and Later Per-mile Exhaust Emissions Relative to
 

Conventional Gasoline: Percent change separated by data source 

EPA - CFEIS EPA - SwRI Env. Canada 

NMOG 10% 87% 5% 

CO -34% -15% -48% 

NOx -3% -42% -40% 

Benzene NA -61% -65% 

1,3 Butadiene NA -66% -74% 

Acetaldehyde 12% of NMOG 5600% 3121% 

Formaldehyde 2% of NMOG 116% 98% 

Acrolein 

(E85 mg/mile 

emissions) NA 0.023 0.010 

Unburned Ethanol 

(E85 mg/mile 

emissions) 

28.3 (55% of 

NMOG) 

25.4 (33% of 

NMOG) 

34.6 (48% of 

NMOG) 

PM 2.5 NA -68% NA 

Viewed independently, each study provides only limited insight on the effects of E85 on 

emissions relative to E0. Table 3.1-6 shows that while changes in some pollutants compare 

reasonably well between studies, others can vary widely. This makes it difficult to determine 

quantitative trends in emissions, since calculating an average percent change in emissions across 

all three studies does nothing to address the variability of the test data. Without this assessment 

of variability there is no way to estimate the statistical significance of the reported values. Only 

the Environment Canada conducted the repeat tests necessary to assess the test-to-test variability 

of a given vehicle, and none of the studies tested enough vehicles to confidently state that their 

findings can be applied to the Tier 2 FFV fleet as a whole. In this case it is desirable to combine 

the test data into a single dataset and apply a statistical modeling technique that allows one to 

estimate the average effect of E85 observed across the vehicles tested and to assess whether 

those changes are statistically significant. 

Combining the data from these three studies results in a dataset that is still quite small 

(only 26 unique tests) and is by no means ideal. This clearly illustrates the need for additional 

testing in this area. In the absence of such data, we feel that combining the data is warranted 

since the majority of the vehicles employ similar emissions control technology and the base 

gasoline used in each study was Tier 2 certification fuel. In the SwRI and EPA CFEIS datasets, 

the E85 fuels were splash blended from denatured ethanol and Tier 2 gasoline. In the case of 

Environment Canada, their E85 was purchased from a commercial distributor, so its physical 

properties are slightly different than the splash blended E85 fuels. However, when 

approximately 82% of the fuel is a single compound (ethanol), the variability in the remaining 

fuel properties is small enough to consider the E85 fuels from all three data sources to be 

substantially similar for the purposes of this analysis. In other words, no distinction was made 

between the E0 and E85 fuels used in study A vs. the E0 and E85 fuels used in study B. 

444 
 

The fact that Environment Canada tested non-Tier 2 vehicles is noteworthy. The 2004 

Chrysler Sebring was an interim non-Tier 2 bin 8 vehicle. Despite its name, however, the 

standard is equivalent to the final Tier 2 bin 8 FTP standards in all areas but the full useful life 

(120K miles vs. 100K miles). In fact this vehicle was cleaner than required by the standard, with 

observed emissions on E0 at the level of a Tier 2 bin 7 vehicle. The second vehicle tested by 

Environment Canada was a 2002 Dodge Caravan certified to the NLEV LEV LDT level. The 

standards at this certification level are considerably more relaxed than Tier 2 levels for some 

pollutants but not others. While these vehicles share the same NMOG certification standard 

(0.100 g/mi), the CO standard is roughly 30% higher and the NOx standard nearly 4 times higher 

than the Tier 2 bin 8 level. As a result of this difference in standards, the Caravan emitted about 

20% more CO and 2.5 times more NOx than the Sebring. NMOG emissions were nearly the 

same for both vehicles with non-oxygenated gasoline. On a relative scale, both vehicles 

experienced similar percent changes in emissions between E0 and E85. The Sebring emitted 

more ethanol with E85 than did the Caravan, resulting in a higher E85 NMOG emissions factor 

for that vehicle. For the purposes of this analysis, we did not differentiate either of these 

vehicles from the Tier 2 vehicles tested in the other studies. 

The fact that tests were conducted in different laboratories is of little consequence since 

we are attempting to quantify the average effect of E85 across individual vehicles, not 

necessarily comparing the results (in absolute terms) of one vehicle to another. Therefore any 

laboratory bias is implicitly included in an individual vehicle’s test results and does not confound 

the relative effects of fuel on emissions for that vehicle. 

The statistical software package SPSS (version 9.0.1) was used to create a univariate 

linear model using the natural log of a given pollutant (CO2, NOX, etc) as the dependent variable, 

the fuel terms as a fixed variable, and the vehicle term as a random variable. This is a so-called 

mixed model since it includes both fixed and random variablesNNNNNNNN. Only the first order 

(linear) fuel and vehicle terms were considered in this model since three fuel levels would have 

been needed to assess nonlinear fuel effects. The model also excluded the vehicle by fuel 

interaction term. This approach was taken since our primary focus is to identify the main effect 

of fuel on the natural log of emissions (the dependent variable). Including the vehicle by fuel 

interaction would have told us something about the sensitivity of each individual vehicle to 

changes in fuel, but for this analysis we are more concerned with the average effect of fuel across 

all vehicles in the dataset. Therefore we removed the interaction from the model since including 

it on such a small dataset would confound the main fuel effect and inappropriately constrain the 

model. 

The results of the statistical analysis are summarized in Table 3.1-6. Statistically 

significant results are shown in bold. 

NNNNNNNN A sensitivity analysis was performed designating the vehicle term as a fixed variable (a fixed-effect 

model) but the results were identical to those with the mixed model so only these results are presented here. 

445 
 

 

 

 

 

 

Table 3.1-6: Combined E85 Effects over 3 Programs 

Pollutant E85 change from E0 

NMOG 8.6% 

CO -38.7% 

NOx -20.9% 

Toxics (mg/mile) 

Benzene -59.6% 

1,3 Butadiene -61.2% 

Acetaldehyde 3739.8% 

Formaldehyde 62.3% 

Acrolein (mg/mile emission w/ E85) 

Unburned Ethanol (mg/mile emission w/ E85) 

PM 2.5 -68.2% 

Bold = statistically significant at 95% CI 

As shown in the table above, the effect of E85 on emissions was significant for all 

pollutants of interest except for NOx and NMOG. For NOx, the p-value is 0.83 and for NMOG 

the p-value is 0.55, meaning these results are only significant at the 17% and 45% confidence 

levels (respectively). While relatively speaking, NOx is more statistically significant than 

NMOG, for our purposes they both can only be used qualitatively. Directionally, the NMOG 

increase and NOx decrease are consistent with the observations of each individual study and 

agree with basic engineering judgment. The variability in the magnitude of these changes, 

however, is what weakens the statistical significance. Had additional observations been made, 

these results may have become more statistically significant. For our “more sensitive” fuel 

effects case, only those effects shown to be statistically significant were applied in the analysis. 

No E85 effects were applied for the “less sensitive” case. 

The “more sensitive” case also included a 50 percent reduction in evaporative emissions 

with use of E85 based on results from one vehicle from CRC’s E-65 evaporative permeation 

program. For the final rule we expect to verify the change in evaporative emissions with E85 

based on results from ongoing EPA and CRC testing. 

Data from the analyses discussed above, and an additional dataset from a 1995 test 

program conducted by EPA’s Office of Research and Development, were used to develop inputs 

for MOVES, in order to model E85 impacts on air toxics inventories. Since MOBILE6 does not 

model air toxics for E85, ratios were developed to apply to E85 hydrocarbon or PM mass (Table 

3.1-7). The exhaust ratios for all pollutants except naphthalene were obtained from data on 

seven vehicles from the 1995 test program in EPA’s Office of Research and Development, along 

with the previously discussed 2007 test program at Southwest Research Institute,552 and the 

2005 test program at Environment Canada.553, 554 The data from the ORD test program is 

unpublished, but is available in the docket for this rule. Naphthalene inputs for were derived 

from estimates from E10 values based on dilution of fuel with ethanol. The only source of data 

on evaporative emissions were results of hot soak tests from the Auto/Oil Air Quality 

Improvement Research Program.555 

446 
 

Table 3.1-7. Toxic to THC/PM Ratios used for E85 Fuel in MOVES 

Pollutant Exhaust/Ratio Type Evaporative/Ratio Type 

Benzene 0.0036/THC 0.0054/THC 

1,3-Butadiene 0.0005/THC N.A. 

Acetaldehyde 0.0673/THC N.A. 

Formaldehyde 0.0093/THC N.A. 

Acrolein 0.0002/THC N.A. 

Ethanol 0.3316/THC 0.6123/THC 

Naphthalene 0.0126/PM 0.00006/THC 

3.1.1.2.2 Spark-Ignited Off-Road Engines 

Effects of E10 relative to E0 on exhaust as well as fuel tank and hose permeation 

emissions from gasoline-fueled off-road engines are contained in EPA’s NONROAD model, 

based on limited data. The effects on exhaust HC, NOx, and CO are shown in Table 3.1-8. 

Effects on tank and hose permeation emissions vary by equipment type and were recently 

updated to reflect new information on uncontrolled emissions and their control due to recently 

finalized new standards.556 For most small spark-ignition engines and recreational marine 

engines in 2022 E10 is estimated to double the tank and hose permeation emissions. There can 

also be increases in diurnal and refueling emissions with E10 if the fuel volatility of the blend is 

allowed to be greater than E0. These volatility effects are accounted for in the NMIM model that 

has the county-specific fuel properties that were used to generate the emission inventory impacts 

for this proposal presented below in Section 3.2. 

Table 3.1-8. 

Exhaust Effect of Ethanol (E10) on Spark-Ignited Gasoline Emissions 

4 stroke 2 stroke 

HC exhaust -15.75% -2.1% 

NOx +40.25% +65.1% 

CO -21.7% -22.75% 

EPA, DOE and the California Air Resources Board (ARB) are in the midst of additional 

testing of off-road engines that will be used to update our analysis for the final rule. 

3.1.1.2.4 Biodiesel Effects on Diesel Emissions 

As discussed in Appendix A to this RIA, we investigated the emission impacts on NOx, 

PM, HC, and CO of 20 volume percent biodiesel fuels on emissions from heavy-duty diesel 

vehicles.557 Average NOx emissions were found to increase 2.2 percent, while PM, HC, and CO 

were found to decrease 15.6 percent, 13.8 percent, and 14.1 percent, respectively, for all test 

cycles run on 20 volume percent soybean-based biodiesel fuel (Table 3.1-9). These results are 

generally consistent with the exhaust emission impacts for heavy-duty, in-use diesel engines 

447 
 

found in our previous work on this subject.558 For our estimate of biodiesel impacts on toxics 

we applied the HC emission change from Table 3.1-9 to toxic emissions. 

Table 3.1-9. BD20 Emission Impacts 

Percent change in emissions 

NOx 

PM 

HC 

CO 

+2.2% 

-15.6% 

-13.8% 

-14.1% 

3.1.1.3 Non-GHG Emission Impact Scenarios Analyzed 

As discussed in Section 3.1.1.2.1, two sets of fuel effects scenarios were analyzed in the 

RFS1 rule in order to bound the uncertainty in ethanol effects on on-road gasoline engines. For 

today’s proposal we have carried forward these scenarios, but have expanded the sensitivity case 

to consider the impacts of E85 as well. Fuel effects cases differ only in how on-road gasoline 

exhaust emissions are modeled. For all other sources discussed above – on-road gasoline 

evaporative and refueling emissions, off-road spark ignition (SI), portable fuel containers, and 

heavy-duty diesel emissions – the same fuel effects, as summarized in the preceding sections, 

were used. The differences between the fuel effect cases are summarized below: 

1) “Less Sensitive”: No exhaust VOC or NOx emission impact on Tier 1 and later vehicles 

due to E10, and no impact due to E85. This was the “primary” case analyzed in the RFS1 

rule, and results in only pre-Tier 1 vehicles having an effect from E10. 

2) “More Sensitive”: VOC and NOx E10 emission impacts based on test data on newer 

technology vehicles, as presented in Table 3.1-3, and the statistically significant E85 

effects that were presented in Table 3.1-6. 

3.1.1.4 Non-GHG Emission Impact Calculation Methodology 

3.1.1.4.1 On-Road Gasoline 

Emissions from gasoline highway vehicles were generated with a preliminary draft 

version of EPA's new MOVES model. This model is currently being prepared for release in 

draft form in early 2009. Although we applied a preliminary pre-draft version of the model and 

we anticipate changes between the version used for the NPRM analysis and the version to be 

released publicly (and the final rule version), our analysis does reflect significant updates in 

gasoline vehicle emissions from MOBILE6. Exhaust emission rates for HC, CO and NOx were 

developed based on an analysis of state inspection/maintenance and roadside remote sensing data 

from millions of vehicles.559 Emissions of particulate matter are based on EPA's recent Kansas 

City gasoline PM study.560,561 Evaporative emission rates have been updated based on extensive 

evaporative testing conducted by EPA and the Coordinating Research Council (CRC) since the 

release of MOBILE6, including investigations quantifying the effects of ethanol on permeation 

448 
 

emissions.562 For this assessment of toxics, MOVES applies toxic ratios from the MOBILE6.2 

model to updated MOVES HC estimates within the model.563 

Details of how MOVES was configured and run are documented in a report contained in 

the docket.564 To summarize, a separate MOVES run was configured for each year (2005 and 

2022) and fuel effect case (“less sensitive” and “more sensitive”) for the reference case (AEO 

reference) and control case. Each of these runs required a unique “run specification” file and 

bundle of input databases to allow modeling of differences in analysis year, fuel supplies, and 

fuel effects. For example, for the 2005 base year run, MOVES was configured to run with the 

estimates of fuel formulations and market shares by county in 2005, using the inputs developed 

as discussed in Section 3.1.1.1, and two sets of fuel effects to reflect the “less sensitive” and 

“more sensitive” cases. Reference and control case runs in 2022 were run with estimates of fuel 

formulations and market shares for both cases by county as we project in 2022, again with the 

two fuel effects cases. MOVES was only run for the AEO reference case, so results relative to 

other reference cases (i.e. RFS1 mandate or baseline) were based on scaling the differences 

between the AEO reference and control cases. VMT used to model onroad emissions was that 

developed for the Office of Air Quality Planning and Standards's 2002 Version 3 Modeling 

Platform565 and used in the recently published Locomotive-Marine Rule.566

 MOVES allows different levels of pre-aggregation depending on the level of resolution 

needed. For regional inventory applications, the finest level of aggregation the model can run is 

by county for each hour of the day, which maximizes the influence of inputs such as county-level 

fuel effects, hourly temperatures and activity patterns; however, since running the model at this 

level for the entire nation over multiple years and scenarios would be time prohibitive, the model 

was run at a higher level of aggregation to reduce run time. Exhaust emissions were run at the 

state/month aggregation for all cases, meaning that county-level inputs were aggregated to a 

single state average before being processed into MOVES, and hourly inputs were aggregated into 

an average monthly value. Likewise evaporative emissions were run at the state/hour level of 

aggregation, since evaporative emissions are required to be run at the hourly level. For further 

time savings runs were performed in January and July only and weighted to approximate an 

entire year – for most pollutants we simply used the number of days in each month to extrapolate 

to the full year (approximately 50/50), however due to the higher temperature sensitivity of PM, 

care was taken to develop weighting factors that better approximated a yearly total based on a 

month-by-month run (January/July weightings of approximately 30/70). While aggregation does 

lose some resolution in the overall emission results, test runs indicated that emissions differences 

are within a few percent of fully disaggregated runs and acceptable for estimating the emission 

impacts of the control programs. 

MOVES categorizes vehicles according to use type; for this analysis the majority of the 

focus was on light vehicles, which would include the MOVES use types Passenger Car, 

Passenger Truck and Light Commercial Truck. To account for larger gasoline vehicles which 

will also have emissions affected by the change in gasoline formulations, we also ran additional 

MOVES use types: school buses, single-unit trucks, and motor homes. For the purposes of this 

rulemaking, the number of gasoline-powered refuse trucks, transit buses, intercity buses and 

combination trucks was determined to be negligible, and they were omitted from the MOVES 

449 
 

runs to reduce run time. Because the PM10 calculation inputs for MOVES were incomplete, PM 

10 was calculated outside the model as PM2.5 times a correction factor of 1.086. 

Because at the time of this analysis the MOVES module for automating the calculation of 

E85 emissions from flexible fueled vehicles (FFVs) was not complete, we calculated the 

emission impact of E85 use by running MOVES for all E85 and for all E10 and then weighted 

the emissions in a post-processing step. To run MOVES for "all E85" we created a special set of 

MOVES input files that essentially set all gasoline vehicles to run on E85. We created MOVES 

fuel supply and fuel adjustment tables that applied multiplicative E85 fuel adjustments from 

Table 3.1-7 to all gasoline vehicle emissions.OOOOOOOO Because sulfate and vapor venting 

emissions are calculated using fuel properties (sulfur level and RVP) rather than fuel 

adjustments, we also created a specific MOVES table of E85 fuel properties as described in 

Section 3.1.1.1 In a post-processing step, we calculated a weighted average of the "all E85" 

results and the 2022 control case, sensitivity analysis results (called "all E10" results here). We 

chose to use the "sensitivity" results for consistency with its premise that modern vehicles are 

responsive to changes in fuel characteristics. The all E85 and all E10 results were weighted 

together by state, model year, and vehicle type using a weighting factor that was the product of 

the FFV fraction and the E85 market share, where FFV fraction is the fraction of that vehicle 

type and model year that are projected to be E85 flexible-fueled vehicles, and the E85 

marketshare is the state fraction of FFV energy use that we project will be provided by E85. 

These fractions were generated using the assumptions described in the sections in Chapter 1, 

Section 1.7.1 pertaining to Primary FFV Growth Assumptions and Projected Growth in E85 

Access. We performed this calculation for passenger cars and trucks and light commercial 

trucks only since the number of heavy-duty vehicles using E85 is expected to be small. 

Toxic emissions are in development for MOVES; for this analysis some post-processing 

was required to generate complete inventory estimates. Specific toxic:hydrocarbon ratios by 

fuel formulation, vehicle class and model year were developed from a series of MOBILE6 runs 

and fed into MOVES, which applied these ratios to HC emissions to produce emissions of 

benzene, acetaldehyde, 1-3 butadiene, formaldehyde and acrolein for all of these cases analyzed. 

Napthelene from heavy-duty vehicles was ratioed to PM 10 in MOVES. For light-duty vehicles, 

naphthalene emssions were calculated as the sum of PM 2.5 elemental carbon and PM 2.5 

organic carbon emissions times a ratio of 0.088. Aggregate ratios from the running emissions 

were also applied to start emissions to develop overall toxic emission inventories. E85 emissions 

were calculated in MOVES using the factors in Table 3-1.7. 

3.1.1.4.2 Off-Road Gasoline 

Emissions from nonroad gasoline equipment were developed by running the National 

Mobile Inventory Model (NMIM), a consolidated emissions modeling system for EPA’s 

MOBILE6 and NONROAD models.567 The key feature of NMIM is a national county database 

(NCD), which includes county-level information on temperatures, fuel properties, equipment 

populations, etc. NMIM runs MOBILE6 and NONROAD based on information in the NCD. 

OOOOOOOO The MOVES fuel adjustment table developed for this analysis contained all E85 fuel effects from Table 

3.1-9, including the not statistically significant NOx and NMHC results; however, only results pollutants identified 

as statistically significant in Table 3.1-9 are reported in the sensitivity case inventory results 

450 
 

The NCD used to produce these inventories was updated as part of the 2005 National Emission 

Inventory (NEI) process.568 The NCD also included the 2005 and 2022 fuels described in 

Section 3.1.1.2. The version of the NONROAD Model used included the effects of the recently 

signed Final Rule: Control of Emissions of Air Pollution from New Nonroad Spark-Ignition 

Engines, Equipment, and Vessels.569 It is also capable of modeling the effects of gasoline blends 

containing 10 percent or less of ethanol. 

Emissions from onroad and nonroad diesel equipment were also developed by running 

NMIM (see above), using the same NCD and version of the NONROAD Model described above. 

The version of MOBILE was MOBILE6.2. Diesel fuels are less fully characterized than 

gasoline, since the only property used by MOBILE and NONROAD is fuel sulfur. 

Toxic emissions for off-road reference cases were taken directly from NMIM. 

Inventories for the control case were developed by applying ratios of the aggregate MOVES 

toxic exhaust, evaporative and refueling emissions for on-road gasoline for control versus 

reference case, to reference case toxic emissions for off-road from NMIM. 

3.1.1.4.3 On-Road Diesel 

Today’s proposal requires an increase in biodiesel to 0.81 billion gallons by 2022. As it 

is likely this will be consumed in a variety of blend levels (e.g. 20 percent, 5 percent, 2 percent) 

by light-duty diesel vehicles and off-road diesel equipment as well as heavy-duty diesel vehicles, 

we assumed for this analysis that the effects of biodiesel on emissions are linear with biodiesel 

concentration as demonstrated by Sze, et al,570 and that impacts can be analyzed assuming all 

biodiesel is blended as BD20. We applied the BD20 effects discussed in Section 3.1.1.2.4 to 

baseline heavy-duty emissions generated by NMIM, as MOVES heavy-duty diesel estimates 

were not available in time for this analysis. Biodiesel impacts were using the following formula: 

Biodiesel Impact P = Base HD Emissions P * Effect P * (Increase in BD20 Volume / Total Diesel Volume) 

Where: 

P = pollutant 

Effect = Percent change with BD20 blend from Section 3.1.1.3.3 

Increase in B20 Volume= Change in B20 volume from 2022 reference case to control case 

in billion gallons of B20 blend (ie, change in gallons of biodiesel * 5) 

Total Volume = Total Highway Diesel Volume in 2022 in billion gallons 

Toxic effects were calculated using the HC effects from Table 3.1-9 

3.1.1.4.4 Portable Fuel Containers 

There are several sources of emissions associated with portable fuel containers (PFC) 

used for gasoline. These sources include vapor displacement and spillage while refueling the gas 

can at the pump, spillage during transport, permeation and evaporation from the gas can during 

transport and storage, and vapor displacement and spillage while refueling equipment. As the 

451 
 

 

calculation of emissions for refueling non-road equipment includes spillage and some vapor 

displacement, these impacts are not included here. 

As part of the 2007 regulation controlling emissions of hazardous pollutants from mobile 

sources (MSAT2 rule), EPA promulgated requirements to control VOC emissions from gas cans. 

The methodology used to develop emission inventories for gas cans is described in the regulatory 

impact analysis for the rule and in an accompanying technical support document.571, 572 

Based on the MSAT work, we generated two sets of hypothetical nationwide annual 

estimates of PFC VOC emissions, for calendar years 2017 and 2030, based on all E0 and all E10. 

Interpolation can be used to estimate PFC VOC emissions for the reference cases. Proportions of 

national E0 and E10 fuel use were calculated from the 2022 reference and policy scenarios. The 

reference case featured a mix of 89.1% E10 and 10.9% E0, while the policy case featured 100% 

E10. While E85 is used in flexible fueled highway vehicles, it is unlikely to be used in the near 

future in non-road equipment, and is therefore unlikely to be stored or dispensed from PFCs. 

MSATs found in liquid gasoline will be present as a component of VOC emissions. 

These MSATs include benzene and naphthalene. Ethanol is present as well in VOC emissions 

from ethanol blends. Inventories for these pollutants were estimated by the application of toxic 

to VOC ratios. 

For benzene emissions from all sources except permeation, the following formula was 

used to calculate toxic to VOC ratios: 

PFC Benzene Emissions =

⎛ Re fueling Benzene LDGV ⎞ PFC VOC Emissions × ⎜

⎜ ⎟⎟ × 0.36 

⎝ Re fueling VOCLDGV ⎠

where the ratio of refueling benzene to VOC was estimated using average nationwide fuel 

properties for zero and 10 percent ethanol gasoline from refinery modeling, done for RFS rule, 

and applied to EPA’s Complex Model for reformulated gasoline.573, 574 The 0.36 multiplier 

corrects for the difference in the percentage of gasoline in refueling emissions at 90o F, the 

temperature assumed for the algorithm in the Complex Model, versus a more typical lower fuel 

temperature of 60 o F for gas cans. The basis of this adjustment is discussed in more detail in the 

regulatory impact analysis for the Mobile Source Air Toxics Rule. An additional adjustment 

factor is applied to the ratio for permeation emissions, based on a recent study575 that suggests 

that the ratio of benzene from permeation to total VOC from permeation is about 1.77 times 

higher than the ratio associated with evaporation, according to the following formula: 

PFC Benzene Emissions =

⎛ Re fueling Benzene ⎞ PFC VOC Emissions × ⎜

⎜ LDGV ⎟

⎟ × 0.36 x 1.77 

⎝ Re fueling VOCLDGV ⎠

452 
 

 

The resulting ratios for 0% and 10% ethanol did not differ at the fifth decimal place, and 

were 0.0135 for all sources except for permeation, and 0.00239 for permeation. Thus, impacts of 

this rule on benzene emissions are due to the overall impact of RVP changes on total VOC 

emissions. 

A naphthalene to VOC ratio was estimated using the following formula: 

PFC Naphthalene Emissions =

⎛ Evaporative NaphthaleneLDGV ⎞ PFC VOC Emissions × ⎜

⎜ ⎟⎟ × 0.0054 

⎝ Evaporative VOCLDGV ⎠

An evaporative naphthalene to VOC ratio for light-duty gasoline vehicles of 0.0004 was 

obtained from analyses done for the Mobile Source Air Toxics Rule, and did not vary by fuel 

type. The 0.0054 adjustment was based on a recent analysis of average nationwide percentage of 

naphthalene in gasoline vapor from gasoline distribution with an RVP of 10 psi at 60 degrees 

Fahrenheit.576, 577 The resulting ratio applied to PFC emissions was 0.0000022. 

For E10 fuel, we assumed 16.74 percent of the evaporative emissions were ethanol 

(SPECIATE profile 1301)578 and 33.34 percent of permeation emissions were ethanol.579 

3.1.1.4.5 Refueling Emissions 

Refueling emissions were calculated by NMIM, based on MOBILE6 refueling module. 

Emissions are impacted by the increase in RVP due to ethanol, and also because the reduced 

energy density of ethanol would require more fillups. NMIM directly provides the emission 

increase due to increased RVP for the areas allowing the 1.0 psi waiver, so no additional 

processing was required to estimate RVP effects on refueling. 

In order to estimate the emission impact of the increase in refueling events, we developed 

ton per gallon refueling emission factors based on NMIM by dividing total refueling emissions 

from NMIM for each case by the number of gallons consumed in the AEO case. The ton per 

gallon emission factors were then applied to the total volume in gallons in each case. Fuel 

volumes for the control case, RFS 1 base, RFS 1 mandate and AE0 cases are listed in Table 3.1­

10. Our estimates of total gallons were calculated from energy balance, reflecting the various 

number of gallons needed to consume the same energy. We assume the number of trips to the 

pump will increase in proportion to the increased gallons estimated for the rule. 

Table 3.1-10. Gasoline Volumes (Billion Gallons) 

RFS 1 Base RFS 1 

Mandate AEO2007 Control Case 

E0 77.95 107.51 16.03 0 

E10 67.00 36.40 131.00 124.6 

E85 0.00 0.00 0.11 29.3 

Total 

Gallons 138.25 143.91 147.14 153.9 

453 
3.1.2 Impact on Non- GHG Emissions from Fuel Production and Distribution 

In addition to the effects of increased renewable fuel use on emissions from the vehicles 

and equipment that use the fuels, as discussed above, there are shifts in the fuel production and 

transport/distribution methods that can have substantial impacts on emissions. These "upstream" 

emissions are associated with all stages of biofuel production and distribution, including biomass 

production (agriculture, forestry), fertilizer and pesticide production and transport, biomass 

transport, biomass refining (corn or cellulosic ethanol production facilities), biofuel transport to 

blending/distribution terminals, and distribution of finished fuels to retail outlets. Additionally, 

changes in agricultural economics associated with increased biomass production can result in 

shifts in related agricultural production, such as livestock. 

This section describes the changes in upstream emission sources and related emission 

rates connected with the renewable fuel use. The emission inventory impacts resulting from 

these changes are described in Section 3.2. This section is divided into two major sub-sections, 

the first covering emissions of criteria pollutants, their precursors, and ammonia, and the second 

covering non-criteria air toxic emissions and ethanol. The specific air toxics covered are: 

benzene, acetaldehyde, formaldehyde, 1,3-butadiene, acrolein, and naphthalene. 

3.1.2.1 Upstream Criteria Pollutants 

3.1.2.1.1 Agricultural Sector 

Introduction 

In prior EPA estimates, such as the RFS1 rule, changes in agricultural emissions were 

based solely on the increases in bushels of corn (and soybeans for biodiesel), and the necessary 

acreage to produce those additional bushels. Given the greater pressure on farmland use likely in 

the 2022 timeframe for this proposed rule (15 billion gallons of corn ethanol) compared to the 

2012 assessment for RFS1 (6.7 or 9.6 billion gallons of ethanol depending on scenario), 

additional factors have been added to the agricultural analysis, such as likely shifts of acreage to 

corn from certain other crops as corn prices increase. 

The number of acres of cropland for corn, soy, and all other principle crops were 

estimated using the FASOM agriculture and forestry model, as described in Section 2.1 of this 

document. We are using the change in total acres of planted cropland to estimate changes in 

certain agricultural emissions, such as tillage dust and crop residue burning, that are not directly 

calculated by FASOM. Another substantial source of agricultural emissions (especially 

ammonia and methane) is livestock. Changes in livestock-related emissions are estimated based 

on the change in head counts of cattle, swine, and poultry predicted by FASOM. 

The impacts relative to the two RFS1 reference cases (3.64 and 6.7 billion gallons) rely 

only on applying ethanol volume proportions to the modeling results of the AEO reference case 

(13.2 billion gallons). Due to the complex interactions involved in projections in the agricultural 

modeling, we did not attempt to adjust the agricultural inputs of the AEO reference case for the 

other two reference cases. So the fertilizer and pesticide quantities, livestock counts, and total 

454 
agricultural acres were the same for all three reference cases. The agricultural modeling that had 

been done for the RFS1 rule itself was much simpler and inconsistent with the new modeling, so 

it would be inappropriate to use those estimates. Thus, we plan to conduct additional agricultural 

modeling specifically for the RFS1 mandate case prior to finalizing this rule. 

3.1.2.1.1.2 VOC/NOx/CO/SOx/PM2.5 

Criteria pollutants related to agricultural operations come from five major sources: farm 

equipment (mainly diesel engine emissions), fertilizer production and application, pesticide 

production and application, burning of crop residue, and fugitive dust from field tilling and 

related activities. 

Agricultural Equipment Emissions 

Changes in farm equipment emissions were estimated by multiplying an average fuelbased emission factor for diesel or gasoline farm equipment by the change in farm fuel 

consumption predicted by FASOM. The emission factors for each pollutant in units of grams 

emitted per million BTU of fuel burned were calculated from EPA NONROAD2005 nationwide 

modeling outputs for 2022 (pollutant tons emitted, gallons of fuel consumed) for each year of 

interest. The diesel emissions include all agricultural diesel equipment, which are dominated by 

agricultural tractors, while the gasoline emissions include only the limited number of larger 

agricultural gasoline-fueled equipment, such as tractors, combines, balers, swathers, and 

irrigation sets. The fuel energy contents (lower heating value) used for the unit conversions were 

115,000 BTU/gallon for gasoline and 130,000 BTU/gallon for diesel. For comparison, the 

corresponding 2020 emission factors from GREET are shown, where available. Most of the 

differences between NONROAD and GREET are small and are likely attributable to the 

difference between 2020 and 2022 values. And although the gasoline equipment emission 

factors for VOC and CO from NONROAD are much greater than those used in GREET, this 

does not have much impact on emission inventories due to the small number of gasoline-fueled 

equipment used in agriculture relative to diesel equipment. 

455 
 

Table 3.1-11. 

Agricultural Equipment Emission Factors 

(grams per mmBTU of fuel burned) 

Pollutant Diesel Gasoline 

NONROAD GREET NONROAD GREET 

NOx 306 298 204 208 

VOC 30.55 34.87 355.53 52.30 

PM10 21.12 22.67 7.49 9.07 

PM2.5 20.49 20.41 6.89 8.34 

CO 130 136 10,067 204 

Benzene 0.62 -- 11.90 --

Ethanol 0.00 -- 0.00 --

1,3-Butadiene 0.057 -- 1.90 --

Acetaldehyde 1.62 -- 1.63 --

Formaldehyde 3.61 -- 3.17 --

Naphthalene 0.027 -- 0.66 --

Acrolein 0.09 -- 0.14 --

SO2 0.44 -- 15.88 --

NH3 0.68 -- 1.01 --

Fertilizer and Pesticide Production 

The manufacturing processes for agricultural fertilizer and pesticides generate a variety 

of pollutants. The agricultural inputs from GREET provide emission factors in grams of 

pollutant per ton of nutrient for various types of fertilizers, herbicides, and insecticide, as shown 

in Table 3.1-13. These emission factors were multiplied by the changes in fertilizer and 

pesticide use predicted by FASOM, as shown in Table 3.1-12, to give projected changes in 

nationwide agricultural fertilizer and pesticide production emissions. 

Table 3.1-12. 

Changes in Agricultural Chemical Use Relative to AEO Reference Case 

Nitrogen 

(average) 

Phosphate 

(P2O5) 

Potash 

(K2O) 

Limestone 

(CaCO3) Herbicides Pesticides 

Annual Short 

Tons 322,430 211,988 657,066 -239 -11,240 -781 

Percentage 2.42% 7.17% 19.09% -2.12% -5.07% -1.86% 

456 
 

Table 3.1-13. 

Agricultural Chemical Production & Transport Emission Factors 

(grams per ton of nutrient) 

Pollutant Nitrogen 

(average) 

Phosphate 

(P2O5) 

Potash 

(K2O) 

Limestone 

(CaCO3) Herbicides Pesticides 

NOx 1,605 4,484 734 573 19,371 21,628 

VOC 2,761 240 40.7 56.8 1,575 2,040 

PM10 454 1,551 148 506 10,840 11,746 

PM2.5 262 1,018 74.5 167 4,869 5,479 

CO 2,595 790 129 186 5,417 6,872 

Benzene 0.00 0.00 0.00 0.00 3.21 4.16 

Ethanol 0.00 0.00 0.00 0.00 0.00 0.00 

1,3-Butadiene 0.000 0.000 0.000 0.000 0.576 0.745 

Acetaldehyde 0.018 0.001 0.000 0.000 0.082 0.106 

Formaldehyde 20.75 1.55 0.19 0.41 18.11 23.44 

Naphthalene 0.033 0.117 0.010 0.039 114.4 124.0 

Acrolein 0.009 0.001 0.000 0.000 0.024 0.031 

SO2 703 53,299 321 701 11,300 12,895 

NH3 0.00 0.00 0.00 0.00 0.00 0.00 

Until the 1990s it was reasonable to assume that all fertilizers and pesticides used on 

domestic agriculture were produced within the U.S. This has been less true in recent years as 

more agricultural chemicals, especially fertilizers, are being imported from countries with a 

greater availability of natural gas at lower costs. For greenhouse gases the location of these 

emissions is of less importance, but for criteria pollutants and toxics it is important to reduce the 

estimated impacts by the percentage of production and transportation occurring outside of the 

U.S. Using data from USDA580,581 the percentages applied from domestic sources are shown in 

Table 3.1-14. After applying these percentages to the production and initial transportation 

portions of the GREET emission factors, the unadjusted final (domestic) transportation portion 

of the GREET emission factors was added back in. Since the relative emissions from production 

versus transportation vary by pollutant, the net adjustments to the GREET emission factors also 

vary by pollutant, as shown in the second Section of Table 3.1-14. To calculate an overall factor 

for nitrogen fertilizers, the proportions from GREET were used: 70.7% ammonia, 21.1% urea, 

and 8.2% ammonium nitrate. The pesticide adjustment does not vary by pollutant because 

virtually all of the pesticide emissions come from actual production rather than 

transportation/distribution. 

457 
 

 

Table 3.1-14. 

 Domestic Fractions of Fertilizer and Pesticide Production Applied to Crops 

Nitrogen 

Fertilizers 

Potash Phosphate Pesticides 

Domestic Fraction of 

Production 

50% 20% 94% 76% 

Net Adjustment to Production, 

Transportation & Distribution 

Emission Factor from GREET 

VOC 50.63% 94.85% 53.62% 76% 

CO 52.47% 94.92% 54.37% 76% 

NOx 73.34% 94.92% 65.55% 76% 

PM10 52.64% 94.12% 24.06% 76% 

PM2.5 53.67% 94.14% 28.31% 76% 

SOx 60.48% 94.02% 33.66% 76% 

Fertilizer and Pesticide Application 

In addition to the agricultural equipment emissions mentioned above, the application of 

fertilizer and pesticides (herbicides, insecticides, fungicides, etc.) to agricultural fields causes the 

release of certain types of pollutants into the air. For nitrogen fertilizers the only pollutant 

considered to be significant is ammonia (NH3), the estimation of which is covered in Section 

3.1.3.1.1.2. Pesticide application emissions are mainly VOC and various individual organic 

compounds, most notably benzene and acrolein. A discussion of the toxic pollutant emissions as 

a fraction of VOC is presented in Section 3.1.3.2.2, but the resulting emission factors and 

inventory impacts are shown here in Table 3.1-15. There are also potential toxicity concerns 

with volatilization of the pesticide active ingredients, and this is discussed in Section 3.4 of this 

document. 

The basis of the pesticide application emissions for this analysis was the 2002 NEI areasource inventory. The ton per year emissions data from the NEI was used with USDA pesticide 

application data for 2002 (or the nearest year for which data were collected) to generate an 

overall average estimate of the pesticide application emissions per ton of pesticide applied. This 

ratio of pollutant tons (for VOC, benzene, and acrolein) per ton of pesticide applied was then 

multiplied by the change in total pesticide tons used (including herbicides) as projected by 

FASOM and shown in Table 3.1-12 to give the projected change in nationwide agricultural 

pesticide application emissions in Table 3.1-15. 

458 
Table 3.1-15. 

Herbicide and Pesticide Application Emission Factors and Impacts 

Relative to AEO Reference Case 

Pollutant Emission Factor Impact 

(tons per ton applied) (annual short tons) 

VOC 0.543 -6,531 

Benzene 0.142 -1,707 

Acrolein 0.0036 -43.1 

Agricultural Residue Burning Emissions 

One source of air pollution related to crop farming is the burning of crop residues. This 

practice is one of the methods that is used to clear fields between crop cycles so that the old crop 

residue does not build up and clog or otherwise hinder the tilling of the fields in preparation for 

new crop planting. This practice is mainly used for grassy crops like wheat, rye, and barley, but 

in some areas it is also used for corn and other crops. 

Crop residue burning produces substantial emissions of CO2, VOC, CO, NOx, as well as 

ammonia and toxic pollutants such as benzene, formaldehyde, 1,3-butadiene, and acrolein. 

The use of crop residue burning is quite variable from area to area and among individual 

farmers, since there are alternative methods to deal with crop residue, including use of 

conservation tillage methods and equipment that allows planting through the residue. In some 

locations and time periods crop residue burning has been prohibited by law, due to the possible 

health effects in nearby residential areas. 

Although the agricultural burning data in the NEI does not currently cover all states 

where crop residue burning occurs, the data available was used to generate a rough overall 

estimate of the average crop burning emissions per acre of planted crops. This was done using 

2002 crop acreage data from USDA/NASS for the counties covered by the NEI agricultural 

burning data. The overall ratio of pollutant tons (for each pollutant) per total acre farmed was 

then multiplied by the change in total planted acres projected by FASOM to give a projected 

change in nationwide agricultural burning emissions. These values are shown below in 

combination with the agricultural dust emissions in Table 3.1-12. 

Agricultural Dust Emissions 

Soil and related dust particles (e.g., fertilizer, pesticide, manure) become airborne as a 

result of field tillage and animal grazing/foraging, especially in drier areas of the country. Some 

of this dust is in a size range that is a concern for human health and welfare. The NEI includes 

estimates of these particulate emissions by county. 

As done for agricultural burning emissions, the agricultural dust data from the 2002 NEI 

was used to generate an estimate of the average fugitive dust emissions per acre of planted crops 

459 
for the crop related dust, and per head of cattle for the dust related to cattle. This was done using 

2002 nationwide crop acreage and livestock inventory data from USDA/NASS. The calculated 

pollutant tons (for PM) per total acre farmed was then multiplied by the change in total planted 

acres projected by FASOM to give a projected change in nationwide crop related dust emissions. 

And the calculated PM tons per head of cattle was multiplied by the change in cattle inventory 

projected by FASOM to give a projected change in nationwide livestock related dust emissions. 

The emission factors and inventory impacts of agricultural burning and fugitive dust from 

crop related acvities and livestock are shown in Table 3.1-16 and 3.1-17. The ton per year 

impacts for the crop-related emissions are based on a modeled increase of 2,327,000 farmed 

acres (0.79%) in 2022 relative to the AEO reference case. The changes in fugitive dust from 

livestock operations are based on the head count changes shown in Table 3.1-19. 

Table 3.1-16. 

2022 Crop-related Burning and Dust Emission Impacts 

Relative to AEO Reference Case 

Pollutant 

Emission Factors Inventory 

Impacts 

(Tons per thousand 

acres farmed) (annual short tons) 

NOx 0.191 443.8 

VOC 0.535 1,245 

PM10 7.62 17,723 

PM2.5 1.71 3,974 

CO 6.13 14,255 

Benzene 0.017 38.97 

Ethanol 0 0 

1,3-Butadiene 0.0073 17.06 

Acetaldehyde 0.032 75.46 

Formaldehyde 0.07 173.46 

Naphthalene unknown unknown 

Acrolein 0.013 30.01 

SO2 0.059 136.6 

NH3 0.071 165.5 

460 
 

 

 

 

 

 

Table 3.1-17. 

2022 Livestock-related Dust Emission Impacts 

Relative to AEO Reference Case 

Pollutant Beef Cattle Dust Emissions Dairy Cattle Dust Emissions 

(kg/head/year) (annual short tons) (kg/head/year) (annual short tons) 

PM10 0.888 -0.945 0.172 -0.008 

PM2.5 0.089 -0.095 0.017 -0.001 

3.1.2.1.1.2 Ammonia (NH3) 

The two primary sources of ammonia emissions on farms are fertilizer application and 

livestock waste. Fertilizer application emissions were estimated using an average emission 

factor of 57,428.71 grams per ton of fertilizer nitrogen applied for all forms of nitrogen, which is 

a weighted average of the standard EPA emission factors that are used to generate the NEI. The 

weightings for each type of fertilizer come from USDA Economic Research Service data for 

2006. The individual emission factors, weightings, and resulting average emission factor are 

shown in Table 3.1-18. This average emission factor was multiplied by the nitrogen application 

quantities generated by the FASOM model for each scenario. 

Table 3.1-18. Fertilizer Ammonia Emission Factors 

Fertilizer Type SCC Emission Factor 

(lbs NH3/Ton Nitrogen) 

USDA 2006 all 

crops Weighting 

Anhydrous Ammonia 2801700001 24 15.46% 

Aqua Ammonia 2801700002 24 1.61% 

Nitrogen Solutions 2801700003 61 40.88% 

Urea 2801700004 364 21.73% 

Ammonium Nitrate 2801700005 49 3.9% 

Ammonium Sulfate 2801700006 194 4.93% 

Ammonium Thiosulfate 2801700007 64 

Other Straight Nitrogen 2801700008 61 11.49% 

Ammonium Phosphates 2801700009 97 

N-P-K 2801700010 97 

avg lbs/ton 126.61 

avg grams/ton 57428.71 

Changes in ammonia emissions from livestock waste were estimated using emission 

factors (kg/head/year) multiplied by the change in animal head counts predicted by FASOM. 

The ammonia emission factors and livestock head changes used in this analysis, along with 

resulting ammonia inventory impacts are shown in Table 3.1-19. This analysis was limited to 

these four types of livestock because they are the ones specifically modeled by FASOM. 

461 
Table 3.1-19. Livestock Ammonia Emission Impacts Relative to AEO Reference Case 

Livestock 

Type 

kg NH3 per head 

per yeara 

Head count change 

(million head) 

Percent 

change 

Change in NH3 emissions 

(annual short tons) 

Beef Cattle 9 -1.065 -1.40% -9.58 

Dairy Cattle 25 -0.047 -0.60% -1.18 

Swine 5 -2.553 -2.15% -12.76 

Poultry 0.22 -90.14 -0.97% -19.83 a

 Source: EPA/600/R-02-017, "Review of Emission Factors and Methodologies to Estimate Ammonia Emissions From 

Animal Waste Handling," April 2002. 

Although it is a minor source of ammonia compared to fertilizer and livestock emissions 

described below, changes in farm equipment ammonia emissions were estimated by multiplying 

an average fuel-based emission factor for diesel or gasoline farm equipment by the change in 

farm fuel consumption predicted by FASOM. The ammonia emission factors in units of grams 

emitted per million BTU of fuel burned were calculated from the default ammonia emission 

factors used in the EPA NMIM model: 

 116 mg per gallon of gasoline burned; 

and 88.3 mg per gallon of diesel fuel burned. 

3.1.2.1.2 Biofuel Production 

Emissions from the production of biofuels include the emissions from the production 

facility itself as well as the emissions from production and transport of the biomass and any other 

fuels used by the biofuel plant, such as natural gas, coal, and electricity. The biomass feedstock 

production emissions are discussed above in the section on agricultural emissions. The 

calculation of emissions from corn ethanol, cellulosic ethanol, and biodiesel plants, including 

feedstock transport, was done using the basic methodology of the GREET model. But some 

updates and enhancements were made to GREET, including updated feedstock energy 

requirements and estimates of excess electricity available for sale from new cellulosic ethanol 

plants, based on modeling by the National Renewable Energy Laboratory (NREL). 

The facility emission factors used are shown in Table 3.1-20. The dry mill corn ethanol 

plant emission factors were developed for the RFS1 rule based on an average of state supplied 

data (RFS1 final rule RIA Table 3.4-2, based on C. Jackson memo Docket EPA-HQ-OAR-2005­

0161, April 6, 2007). The dry mill PM2.5 factors and all the wet mill emission factors come 

from GREET 1.7. Emission factors for cellulosic ethanol plants, biodiesel, and renewable diesel 

production were taken from GREET (version 1.8 added renewable diesel). Additional analyses 

are still being conducted to determine potential decreased plant energy requirements and 

emission rates that may be feasible by 2022. 

462 
 

Table 3.1-20. 

Biofuel Production Plant Emission Factors in 2022 

(grams per gallon produced) 

Biofuel Plant Type 

VOC CO NOx PM10 PM2.5 SOx NH3 

Corn Ethanol, Dry Mill NG 4.000 1.900 5.500 2.200 0.265 7.000 0.000 

Corn Ethanol, Dry Mill NG (wet DGS) 4.000 1.900 5.500 2.200 0.222 7.000 0.000 

Corn Ethanol, Dry Mill Coal 4.000 1.900 5.500 2.200 1.884 7.000 0.000 

Corn Ethanol, Dry Mill Biomass 4.000 1.900 5.500 2.200 0.421 7.000 0.000 

Corn Ethanol, Dry Mill Biomass (wet DGS) 4.000 1.900 5.500 2.200 0.313 7.000 0.000 

Corn Ethanol, Wet Mill NG 2.330 1.039 1.677 0.998 0.288 0.012 0.000 

Corn Ethanol, Wet Mill Coal 2.334 3.501 4.857 4.532 1.984 4.595 0.000 

Cellulosic Ethanol (switchgrass or corn stover, 

enzymatic) 1.937 11.722 16.806 2.792 1.116 0.625 0.000 

Cellulosic Ethanol (forest waste, 

thermochemical) 0.363 5.154 7.427 0.854 0.435 0.271 0.000 

Biodiesel, Soybean oil 0.040 0.454 0.733 0.062 0.062 0.005 0.000 

Renewable Diesel, Soybean Oil 0.029 0.329 0.530 0.045 0.045 0.004 0.000 

3.1.2.1.3 Crude Oil Production/Transport/Refining 

The estimate of emissions associated with production of gasoline and diesel fuel from 

crude oil is based on emission factors in the GREET model. The actual calculation of the 

emission inventory impacts of the decreased gasoline and diesel production is done in EPA's 

spreadsheet model for upstream emission impacts. This model uses the decreased volumes of 

the crude based fuels and the various crude production and transport emission factors from 

GREET to estimate the net emissions impact, which is shown below in Section 3.2 (see the 

displaced gasoline line of Table 3.2-5). 

3.1.2.1.4 Finished Fuel Transport and Distribution 

Transfer and Storage Evaporative Emissions from Gasoline, Gasoline/Ethanol Blends, 

and Ethanol -- VOC emissions are produced by transfer and storage activities associated with 

distribution of gasoline, gasoline/ethanol blends, and ethanol. These are referred to as Stage I 

emissions.582 Stage I distribution begins at the point the fuel leaves the production facility and 

ends when it is loaded into the storage tanks at dispensing facilities. 

There are five types of facilities that make up this distribution chain for gasoline. Bulk 

gasoline terminals are large storage facilities that receive gasoline directly from the refineries via 

pipelines, barges, or tankers (or are collocated at refineries). Gasoline from the bulk terminal 

storage tanks is loaded into cargo tanks (tank trucks or railcars) for distribution to smaller 

intermediate storage facilities (bulk plants), or directly to gasoline dispensing facilities (retail 

public service stations and private service stations). When ethanol is blended into gasoline it 

usually occurs in the pipes which supply the tank trucks. 

463 
There are two types of pipeline facilities found at various intervals along gasoline 

distribution pipelines: pipeline breakout stations and pipeline pumping stations. Pipeline 

breakout stations receive gasoline via pipelines, store it in storage tanks, and re-inject it into 

pipelines as needed to meet the demand from downstream facilities. Pipeline pumping stations 

are located along the entire length of a pipeline at about 40 mile intervals. Their purpose is to 

provide the extra ‘‘push’’ needed to move the product through the pipeline. They do not 

normally have gasoline storage capability. 

Bulk plants are intermediate storage and distribution facilities that normally receive 

gasoline or gasoline/ethanol blends from bulk terminals via tank trucks or railcars. Gasoline and 

gasoline/ethanol blends from bulk plants are subsequently loaded into tank trucks for transport to 

local dispensing facilities. 

Gasoline and gasoline/ethanol blend dispensing facilities include both retail public outlets 

and private dispensing operations such as rental car agencies, fleet vehicle refueling centers, and 

various government motor pool facilities. Dispensing facilities receive gasoline and 

gasoline/ethanol blends via tank trucks from bulk terminals or bulk plants. Inventory estimates 

for this source category only include the delivery of gasoline at dispensing facilities and does not 

include the vehicle or equipment refueling activities. 

Emission factors (EFs) for gasoline were based on inventory estimates from the 2002 

NEI.583 We used these data to develop E0 gasoline emission factors even though the 2002 

emissions included the E10 that was in the fuel pool at that time. In 2002 this was still a 

relatively small proportion of gasoline consumption, so it should not substantially affect the 

national E0 estimates. Since ethanol is blended with gasoline at bulk terminals to produce E10 

and E85 at the point fuel is loaded into tank trucks, we assumed bulk terminal emissions were 

associated with unblended gasoline. We then divided emissions into a refinery to bulk terminal 

component and a bulk terminal to dispensing facility component. Total nationwide emissions for 

these two components were divided by the energy content of the total volume of gasoline 

distributed in 1999, to obtain the emission factor in g/mmBTU. Total volume of gasoline was 

based on gasoline sales as reported by the Energy Information Administration.584 These 

emission factors are provided in Table 3.1-21. 

We also developed emission factors for Stage 1 emissions of E10 and E85 subsequent to 

blending at bulk terminals. These emission factors were calculated by applying adjustment 

factors to the gasoline EF. The adjustment factors for E10 and E85 were based on an algorithm 

from the 1994 On-Board Refueling Vapor Recovery Rule585: 

EF (g/gal) = exp[-1.2798 - 0.0049(ΔT) + 0.0203(Td) + 0.1315(RVP)] (1) 

where delta T is the difference in temperature between the fuel in the tank and the fuel being 

dispensed, and Td is the temperature of the gasoline being dispensed. We assumed delta T is 

zero, temperature of the fuel being dispensed averages 60 degrees over the year, and that the 

RVP of conventional gasoline is 8.7 psi, 10% ethanol is 9.7, and 85% ethanol is 6.2. Using these 

assumptions, the adjustment factor is +14% for E10 and -30% for E85. Emission factors in 

grams per million BTU of fuel transferred are given in Table 3.1-21. 

464 
 

 

In addition to these Stage I emissions for gasoline and gasoline/ethanol blends, transport 

of ethanol to bulk terminals also results in evaporative emissions of ethanol, a VOC. These 

emissions are estimated based on an adjustment to the gasoline transport VOC emissions to 

account for the much lower vapor pressure (approximately 3 psi at 100F for denatured ethanol 

versus 9 psi for gasoline) and molecular weight (48.7 for denatured ethanol versus approximately 

72 for gasoline vapor). The net factor is 0.23 x gasoline evap VOC, resulting in the value shown 

for E100 in Table 3.1-21: 

3.56 g/mmBTU of ethanol 

= 0.23 x gasoline VOC per-gallon EF / ethanol energy content 

= 0.23 x (10.2137 g/mmBTU x 115000 BTU/gal) / 76000 BTU/gal 

Note that this very simplified methodology does not attempt to account for differences 

between ethanol and gasoline transport modes, distances, or transfer methods in movement of the 

fuel from production facility to the bulk distribution terminal. We plan to do a more thorough 

analysis of this for the final rule. 

Significant evaporative emissions are not expected from storage and transport of 

biodiesel fuel due to its low volatility. 

Table 3.1-21. 

VOC Emission Factors for Gasoline and Gasoline/Ethanol 

Blend Storage and Transfer Emissions (Stage 1) 

Process Blend EF(g/mmBTU) 

Refinery to Bulk Terminal E0 14.94 

Refinery to Bulk Terminal E100 3.56 

Bulk Terminal to Pump E0 27.79 

Bulk Terminal to Pump E10 32.74 

Bulk Terminal to Pump E85 25.93 

Combustion Emissions from Transport and Distribution of Fuels and Feedstocks -- Emissions 

are produced by the vehicles and engines used to transport feedstocks such as crude oil, corn, and 

cellulosic biomass to fuel production facilities, as well as transport/distribution of the finished 

fuels from the production plants to distribution terminals and retail outlets. For example, corn 

would be transported from farms and grain facilities to ethanol plants by truck and possibly rail. 

The finished ethanol would be transported from there to bulk distribution terminals by truck, rail, 

or barge, and distribution from terminal to retail outlet is by truck. The emission factors for the 

year 2022 in Table 3.1-22 take into account the mix of newer better controlled engines (including 

trucks meeting the standards for 2008 and later engines586 and engines meeting the 2008 

locomotive/marine diesel engine rule587), as well as any remaining older engines subject to less 

stringent standards. The truck EFs are given in terms of grams per vehicle mile traveled, while 

the other EFs are in grams per million BTU of fuel burned by the engine. Emission factors for 

these engines are taken from the rulemaking analyses. 

465 
To estimate the net emission rates for the assumed mix of transport modes for each fuel 

type, these emission factors were incorporated into a modified version of GREET588, since 

GREET 1.7 and 1.8 retained emission factors based only on earlier regulations. Thus, the miles 

traveled and quantities of fuel burned are those used by GREET for each transport mode and fuel 

being transported. For the final rule air quality analysis we will have a more detailed analysis of 

miles and fuel volumes transported by mode within each county. 

Table 3.1-22. 2022 Criteria Emissions from Fuel and Feedstock Transport/Distribution 

Transport Mode Year VOC CO NOx PM10 PM2.5 

Class 2B HD Diesel Trucks (g/mile) 2005 0.282 1.303 3.594 0.163 0.139 

 2022 (2020) 0.137 0.205 0.483 0.033 0.019 

Medium HD DIesel Trucks (g/mile) 2005 0.653 2.482 8.297 0.309 0.271 

 2022 (2020) 0.289 0.417 1.243 0.053 0.035 

Locomotive (g/mmBTU of fuel burned) 2005 84.733 212.861 1620.376 51.575 50.028 

Barge (avg of C1 & C2 vessels)589

 2022 (2020) 

2005 

34.070 

26.761 

203.984 

237.513 

815.271 

1276.901 

19.015 

47.923 

18.445 

46.485 

 (g/mmBTU of fuel burned) 2022 (2020) 15.527 188.994 676.097 22.017 21.356 

Ocean Tanker (C3 vessels) 2005 79.943 181.746 2177.881 181.410 166.930

 (g/mmBTU of fuel burned) 2022 (2020) 79.891 181.526 2054.819 181.118 166.666 

3.1.2.2 Upstream Air Toxics 

3.1.2.2.1 Upstream Air Toxics Reference Case 

Air toxic emissions are associated with a variety of upstream processes. These processes 

include production of agricultural pesticides and fertilizers, as well as their application, operation 

of petroleum refineries, operation of ethanol and biodiesel production facilities, operation of 

electrical production facilities which supply power to these facilities, and distribution of 

agricultural pesticides and fertilizers, feedstocks, gasoline, gasoline/ethanol and biodiesel blends. 

Although a large number of compounds which are considered air toxics could be 

impacted by this rule, we focused on those which were identified as national and regional-scale 

cancer and noncancer risk drivers in the 1999 NATA590 and were also likely to be significantly 

impacted by this rule. These compounds include benzene, 1,3-butadiene, formaldehyde, 

acetaldehyde, and acrolein. Naphthalene impacts were included for petroleum refineries, since it 

is a significant emission product for those facilities. Ethanol impacts were also included in our 

analyses because of health concerns (Section 3.4.5) and its role as an acetaldehyde precursor. 

2002 air toxic emissions for stationary sources, other than for fires, were obtained from 

the 2002 National Emissions Inventory (NEI), version 3. Future year emissions of benzene, 1,3­

butadiene, formaldehyde, acetaldehyde, and acrolein were estimated for sectors only, rather than 

individual sources. These sectors included non-EGU (electric generating unit) point sources, 

466 
EGU point sources, the nonpoint storage and transfer subsector, and other nonpoint sources. 

Emissions were estimated by applying future year to 2002 VOC ratios to 2002 air toxic 

estimates. Air toxics from fires were estimated by applying toxics-to-VOC ratios to the VOC 

emissions from a fire inventory developed for air quality modeling. 2002 and future year ethanol 

emissions were estimated by speciating the VOC estimates. This was done using the Sparse 

Matrix Operator Kernel Emissions (SMOKE) modeling system, version 2.3. More details on the 

methods and data used to develop these inventories are found in a memo included in the docket 

for this rule.591 

Air toxic emission estimates for agricultural equipment (mainly diesel agricultural 

tractors) were obtained from the EPA NMIM model, as described for criteria pollutants in 

Section 3.1.2.1.1.1. 

3.1.2.2.2 Upstream Air Toxics Control Cases 

As described below, we developed emission factors for several air toxics using the most 

recent available data. These emission factors were used with estimates of changes in fuel 

volumes and associated energy outputs to estimate inventory changes associated with the 

proposed program. In general, emission factors are expressed as grams per million BTU 

(g/mmBTU) of energy produced or distributed as part of the process. Underlying data are 

available in the docket for the rule. 

Agricultural Pesticides and Fertilizers – The estimation of air toxic emissions from production 

and application of pesticides and fertilizers was done using toxic fractions of the corresponding 

VOC emissions described in Section 3.1.3.1.1.1. Table 3.1-23 shows the toxic fractions, which 

were calculated from the 2002 NEI inventories for VOC and each of the listed toxic pollutants. 

All the pollutants except acrolein from pesticide application are based on nationwide inventories. 

California was the only state that reported acrolein emissions associated with pesticide 

application, so the 0.66% value shown in the table represents the sum of acrolein emissions 

divided by the sum of VOC emissions from pesticide application for all counties in California in 

2002. The fertilizer and pesticide application data come from queries of the NEI area source 

inventories for SCCs like "28017*" (for fertilizer application) and SCCs like "246180*" or like 

"246185*" (for pesticide application). 

The production and blending data for fertilizer and pesticides come from queries of the 

NEI point source data that were submitted by 40 states and Puerto Rico for the following MACT 

codes 

0911 - Pesticide Active Ingredient Production 

0960 - Agricultural Chemicals and Pesticides Manufacturing 

1410 - Phosphate Fertilizers Production 

The data for these codes was compiled for the following four categories: Fertilizer production 

(F), Fertilizer mixing blending (FMB), Pesticide production (P), and Pesticide mixing blending 

(PMB). 

467 
Table 3.1-23. Air Toxic Fractions of VOC for Fertilizers and Pesticides

 Fertilizer 

Production & 

Blending 

Pesticide 

Production & 

Blending 

Fertilizer 

Application 

Pesticide 

Application 

1,3-Butadiene -­ 0.0003653 -­ -­

Acetaldehyde 6.530 E-06 5.198 E-05 -­ -­

Acrolein 3.320 E-06 1.513 E-05 -­ 0.0066 

Benzene -­ 0.002038 -­ 0.2615 

Ethanol -­ -­ -­ -­

Formaldehyde 0.007517 0.011494 -­ -­

Petroleum Refineries – Total nationwide emissions of air toxics for 153 U. S. petroleum 

refineries in 2002 were obtained from data collected as part of a risk and technology review 

(RTR) for EPA’s proposed rule, “National Emission Standards for Hazardous Air Pollutants 

From Petroleum Refineries.”592 These emissions were divided by BTUs of energy produced by 

those refineries in 2002 to obtain emission factors in g/mmBTU. Thus the resultant emission 

factors represent 2002 technology and emission standards. Energy output estimates included all 

refinery products, such as conventional and reformulated gasoline, aviation gasoline, jet fuel, 

kerosene, distillate fuel oil, residual fuel oil, petrochemical feedstocks, naphthas, lubricants, and 

other miscellaneous products. Energy output was estimated by multiplying volume of each 

product supplied593 by its heating value in BTUs per gallon. 

Resultant emission factors are provided below in Table 3.1-25, along with those for 

ethanol and electricity production. 

Ethanol Production Facilities – There are a number of processes at ethanol production facilities 

that result in emissions of air toxics. These processes include fermentation, distillation of the 

resultant mash, and drying of spent wet grain to produce animal feed. Emissions of air toxics 

vary tremendously from facility to facility due to a variety of factors, and it is difficult to 

determine how differences in the production processes individually impact emissions. Numerous 

production facilities have commenced operation in the last few years. To develop emission 

factors we used the most recent available inventory for benzene, formaldehyde, acetaldehyde, 

and acrolein, from calendar year 2005. These data were obtained from two sources: 

1) 2005 NEI State submittals for SCCs associated with ethanol production facilities 

2) the 2005 Toxics Release Inventory (TRI) 

2005 NEI data submittals were obtained from EPA’s Office of Air Quality Planning and 

Standards. These data are included in the docket for the rule. Additional data for facilities not 

included in these submittals were obtained from the 2005 TRI 

(http://www.epa.gov/triexplorer/list-chemical-hap.htm). Where emissions data were not 

available for a facility, the facility was excluded from subsequent calculations. 

Only a few facilities reported very low emissions of 1,3-butadiene, and the rest reported 

no emissions, so emissions of this pollutant from ethanol production facilities were assumed to 

468 
be insignificant. Almost all of the data were from wet mill plants running on natural gas, so it 

was not possible to develop separate emission factors for wet and dry mill plants, or those 

running on coal or natural gas. 

Energy output for each facility was estimated by multiplying production capacity by the 

heating value for ethanol. Since data on actual production by facility were not available, all 

plants were assumed to operate at capacity. Estimates of production capacity were obtained 

from data collected by the Renewable Fuels Association 

(http://www.ethanolrfa.org/industry/locations/). For some major ethanol producers production 

capacity was not available for specific facilities. 

Data for facilities where both emissions and production capacity were available were 

used to estimate nationwide emission rates in g/mmBTU. Table 3.1-24 lists the number of 

ethanol production facilities with emissions data for various air toxics, as well as production 

capacity estimates. 

Table 3.1-24. 

Number of Facilities with Emission Inventory Data 

by Pollutant and Production Capacity Estimates
 

Pollutant No. of Facilities with Emissions Data and 

Production Capacity Estimates. 

Benzene 30 

Formaldehyde 35 

Acetaldehyde 50 

Acrolein 22 

An emission factor for ethanol was estimated using data collected in Minnesota from 16 

facilities, all of which were dry mill plants.594 Since most ethanol emissions occur during 

fermentation, and new production of ethanol is likely to occur at dry mill facilities, these data are 

likely to provide representative estimates of future year increases in ethanol emissions under the 

control scenarios modeled. The resultant emission factors for ethanol production facilities are 

provided in Table 3.1-25. 

Distillers’ grains with solubles (DGS) is a co-product of dry mill corn ethanol production 

that can be used as animal feed. Corn oil remaining in the DGS can be extracted and sold for 

commercial uses, such as biodiesel production, at a relatively high value compared to the DGS 

itself. The oil can be extracted by gravimetric methods or by extraction with n-hexane, which is 

a potentially important toxic emission associated with increased ethanol production. Capital 

costs for solvent extraction are higher, but so are yields. 

Corn oil for food grade use is produced by a process wherein corn is separated into 

component parts, prior to fermentation, with the starch heavy dehulled-degermed corn portion 

fed to the ethanol plant and the corn germ fed to a hexane-based corn oil extraction facility. This 

process is capital intensive and must be designed into the plant. We expect the food grade 

extraction process to be less widespread than commercial grade processes for these reasons. 

469 
VeraSun recently submitted an application to the Iowa Department of Natural Resources 

(IDNR) to add a facility for solvent extraction of corn oil to an ethanol plant in Fort Dodge 

Iowa.595 In this application, Verasun proposed to control particulate matter emissions from the 

process using a baghouse, and to minimize VOC emissions through good design and operating 

processes. Verasun estimated that this plant, with an annual DDGS capacity of 455,000 tons of 

DDGS per year, would produce 305 tons of VOCs per year, with n-hexane emissions of 295 tons 

per year. PM10 emissions would be about 13 tons. 

EPA used the Verasun application data to develop an estimate of potential nationwide nhexane emissions from ethanol plants nationwide. EPA estimates that about 40% of ethanol 

production will have corn oil extraction by 2022; thus, we assumed that about half of this would 

be from solvent extraction and 20% of dry mill plants would employ this process. It is likely a 

number of plants will use gravimetric recovery, since it can be easily retrofitted to any size plant 

at modest capital cost. First, we developed emission rates per ton of DDGS production. Then 

we developed an estimate of DDGS produced nationwide, using industry characterization 

estimates of 13.67 billion gallons of dry mill ethanol production in 2022, and 0.00334 tons 

DDGS per gallon of ethanol produced by dry mills.596 Multiplying the emission rate from the 

Verasun application by total production of DDGS, EPA estimates these facilities could emit 

about 9,000 tons of n-hexane nationwide. However, given the very limited data on emissions 

from such facilities and the nascent nature of this process at ethanol production facilities, such 

estimates should be regarded as highly uncertain. 

Biodiesel Production Facilities -- To estimate emission factors for biodiesel production facilities, 

we identified air toxic emission data for individual facilities developed for the 2005 NEI. 

Unfortunately, only toxics data for two existing biodiesel facilities could be found. These data 

were used to develop toxic to VOC ratios, then applied to VOC emission factors for biodiesel 

plants obtained from GREET, with modifications to add energy used in crushing soybeans. 

VOC emission rates vary by feedstock. Toxic to VOC ratios, VOC emission rates, and resultant 

toxic emission rates in grams per gallon are give in Table 3.1-26. 

Transportation and Distribution of Gasoline, Ethanol, Gasoline/Ethanol Blends and Biodiesel -- 

Air toxic emissions associated with distributing fuel and fuel blends come from two sources. 

The first source is evaporative, spillage and permeation emissions from storage and transfer 

activities, and the second source is emissions from vehicles and pipeline pumps used to transport 

the fuels. Since a pipeline system does not exist for ethanol, increased ethanol use is likely to 

increase toxic emissions from vehicles used to transport it, while a corresponding decrease in 

gasoline distribution would decrease any emissions related to pipeline pumping. 

Storage and transfer activities result in evaporative emissions of benzene and ethanol 

from gasoline, ethanol, and gasoline/ethanol blends. Evaporative emissions from biodiesel fuel 

are not expected to be significant. Emissions of ethanol occur both during transport of ethanol 

from production facilities to bulk terminals, and after blending, at bulk terminals. In addition, 

emission factors for benzene must be estimated separately for fuel before and after blending. As 

previously discussed, we assumed bulk terminal emissions were associated with unblended 

gasoline. We then divided emissions into a refinery to bulk terminal component and a bulk 

terminal to dispensing facility component. Benzene emission factors for gasoline transport from 

470 
refinery to bulk terminals were weighted by the fraction of 2002 VOC emissions for this part of 

the process, whereas emission factors for E0 gasoline, E10 gasoline, and E85 were weighted by 

the fraction of 2002 VOC from the bulk terminal to the pump. Benzene emission rates from 

these activities also vary with the year being modeled, since phase-in of the recently finalized 

Mobile Source Air Toxics Rule will substantially reduce the amount of benzene in gasoline 

beginning in 2011.597 Thus, one set of emission factors were developed for 2002, and a separate 

set of emission factors for the reference case in that year. The reference case also includes 

impacts of the 2007 renewable fuels standard.598 Thus, the reference case already reflects 

ethanol volumes mandated by RFS1. 

The emission factors used for 2002 were derived from the estimated gasoline distribution 

inventory for benzene in 1999, estimated for the Mobile Source Air Toxics Rule.599 Total 

nationwide emissions were divided by the energy content of the total volume of gasoline 

distributed in 1999, to obtain the emission factor in g/mmBTU. Total volume of gasoline was 

based on gasoline sales as reported by the Energy Information Administration.600 To estimate 

the energy content, sales of fuel types (conventional, Federal reformulated, California 

reformulated) were multiplied by their respective heating values. 

The emission factors used for the reference case in 2022 were derived from an estimated 

gasoline distribution inventory for that year. This inventory estimate was calculated by linear 

interpolation of 2020 and 2030 inventories from the Mobile Source Air Toxics Rule. Total 

nationwide emissions were divided by the energy content of the total volume of gasoline 

projected for 2022 by the Energy Information Administration.601 To estimate the energy content, 

the projected gasoline volume was multiplied by the heating value for low-sulfur gasoline 

(115,000 BTU/gallon). 

We assumed that in order to attain the fuel benzene standard for gasoline promulgated in 

the Mobile Source Air Toxics Rule, E10 would have the same fuel benzene content per gallon as 

E0 . However, for E10 the E0 emission factor was adjusted to account for the lower energy 

content of E10 relative to E0. For E85, the E0 emission factor was adjusted to account for 66% 

lower benzene emissions per gallon, as well as the lower energy content of E85. 

The emission factors for benzene are provided in Table 3.1-27. 

To estimate ethanol emissions associated with the distribution of E10 and E85, ethanol to 

benzene emission ratios were applied to benzene estimates. The ratios were 14.8 for E10 and 

112.8 for E85. The ratio for E10 was obtained from the profile for composite evaporative 

emissions from U. S. EPA’s SPECIATE database, profile 1301.602 The ratio for E85 was 

obtained from analyses of evaporative emissions from three vehicles tested as part of the 

Auto/Oil program in the early 1990’s.603 These emission factors are reported in Table 3.1-27. 

471 
 

Table 3.1-25. Air Toxic Emission Factors for Petroleum Refineries, Ethanol 

Refineries, and Electricity Production (g/mmBTU of fuel or electricity produced) 

Pollutant 

Petroleum 

Refinery 

Ethanol 

refinery 

Electricity 

Production 

1,3-butadiene 0.0014 N. A. 0.0001 

Acetaldehyde 0.0002 3.0585 0.0297 

Acrolein 0.0001 0.1323 0.0115 

Benzene 0.0264 0.0998 0.0443 

Ethanol 0.0000 21.6858 

Formaldehyde 0.0042 0.5263 0.0629 

Naphthalene 0.0029 

Table 3.1-26. Air Toxic Emission Factors for Biodiesel 

Production Facilities (g/gallon produced) 

Pollutant Toxic/VOC 

Ratio 

Biodiesel 

Soybean Oil EF 

(g/gal) 

Biodiesel Yellow 

Grease/tallow 

(g/gal) 

Renewable 

Biodiesel Soybean 

Oil (g/gal) 

VOC 0.040 0.042 0.029 

Benzene 7.4x10-7 3.0x10-8 3.1x10-8 2.1x10-8 

1,3-Butadiene 0 0 0 0 

Formaldehyde 3.5x10-5 1.4x10-6 1.5x10-6 1.0x10-6 

Acetaldehyde 5.6x10-6 2.3x10-7 2.4x10-7 1.6x10-7 

Acrolein 4.8x10-6 1.9x10-7 2.0x10-7 1.4x10-7 

Ethanol 0 0 0 0 

Naphthalene 6.3x10-7 2.5x10-8 2.6x10-8 1.8x10-8 

472 
 

 

 

 

 

 

Table 3.1-27. Air Toxic Evaporative Emission Factors for Gasoline, Ethanol, 

and Blend Transport and Distribution (g/mmBTU of fuel transported) 

Pollutant Process Year Fuel EF (g/mmBTU) 

Benzene Refinery to 

Bulk Terminal 

 Refinery to 

Bulk Terminal 

 Bulk Terminal 

to Pump 

 Bulk Terminal 

to Pump 

 Bulk Terminal 

to Pump 

 Bulk Terminal 

to Pump 

2002 

2022 

2002 

2022 

2022 

2022 

E0 

E0 

E0 

E0 

E10 

E85 

0.0488 

0.0270 

0.0908 

0.0502 

0.0519 

0.0228 

Ethanol Bulk Terminal 

to Pump 2022 E10 1.8591 

 Bulk Terminal 

to Pump 2022 E85 7.1432 

As mentioned previously, ethanol vapor emissions during transport from the ethanol plant 

to the bulk terminal are based on an adjustment to the gasoline transport VOC emissions to 

account for the much lower vapor pressure and molecular weight. 

There are also toxic emissions associated with combustion of fuels used in transport and 

distribution of feedstocks and fuels. The emission factors for these are shown in Table 3.1-28 as 

fractions of exhaust VOC, or PM10 for exhaust naphthalene. The VOC and PM10 emission 

factors that these fractions are applied to are presented above in Table 3.1-22. The locomotive, 

marine distillate, and residual boiler estimates come from a 2005 EPA report.604 The heavy-duty 

diesel truck emission fractions come from a 2002 report documenting the toxics module of 

EPA's MOBILE6.2 model,605 and the pipeline values come from the EPA AP-42 document.606 

473 
 

 

 

 

 

Table 3.1-28. 

Toxic Fractions of Exhaust VOC (or fraction of PM10 for exhaust naphthalene) 

(grams toxics per gram of VOC or PM10) 

Mode Source 

1,3­

Butadiene Acetaldehyde Acrolein Benzene Formaldehyde Naphthalene 

Rail 

Diesel 

Locomotive 0.003246519 0.018786 0.0031238 0.002587511 0.04328653 0.0018716 

Barge 

Marine 

Diesel --

Distillate 0.00061 0.074298 0.0035 0.020344 0.1496 0.0018716 

Ocean 

Tanker 

Residual 

Boiler 0 0.003858 0 0.000165354 0.02645669 0.0025885 

Truck 

HD Diesel 

Trucks 0.00061 0.0288 0.0035 0.0105 0.0782 0.00128892 

Pipeline 

Natural Gas 

Turbines 0 0.019048 0.0030476 0.005714286 0.33809524 

Gasoline 

Farm Equip 

HD Gasoline 

Trucks 0.088005387 

3.2. Non-GHG Emission Impact Results 

The reference case emission inventories used for this proposed rule are based on different 

sources depending on sector. 

 For stationary/area sources and aircraft we used the 2002 National Emissions Inventory 

(NEI), Version 3, including the NEI projections for 2020. The development of these inventories 

is documented in the November 27, 2007, memo titled, "Approach for Developing 2002 and 

Future Year National Emission Summaries," from Madeleine Strum to Docket EPA-HQ-OAR2007-0491. That memo summarizes the methodologies and additional reference documents for 

criteria air pollutants (CAP) and mobile source air toxics (MSATs). 

For onroad mobile sources we used a special version of the MOVES model that estimates 

emissions from light-duty and heavy-duty gasoline vehicles, except for motorcycles. For other 

onroad vehicles including diesel vehicles and motorcycles, we relied on the MOBILE6.2 model 

as run using the NMIM platform with county specific fuel properties and temperatures. Most 

nonroad equipment was modeled with NONROAD2005d using NMIM, which is a version of the 

NONROAD that includes the benefits of the two nonroad regulations published in 2008 (the 

locomotive and marine diesel rule and the small spark-ignition and recreational marine engine 

rule). 

Inventories for locomotives and commercial marine vessels are not covered by the 

NONROAD model, and they have been updated since the 2002 NEI was published. Thus we 

used the more recent inventories published in the regulatory impact analyses of their respective 

recent rulemakings. Locomotives and C1/C2 commercial marine vessel inventories come from 

the spring 2008 final rule, and the C3 commercial marine emission inventory is from the 

Advance Notice of Proposed Rulemaking (ANPRM) published in late 2007. 

474 
 

Table 3.2-1 shows the total 2022 mobile and non-mobile source inventory projections 

that were used as the basis for the impact percentages shown above in Table 3.2-1 through 3.2-4. 

The mobile source values in this table use the inventory values of the AEO reference case. 

Table 3.2-1. 2022 Reference Case Emissions by Sector 

VOC CO NOx PM10 PM2.5 SO2 NH3 

Onroad 

Gasoline 909,960 26,250,531 1,333,977 48,472 44,633 34,031 390,486 

Onroad Diesel 140,854 243,820 501,660 29,894 16,533 4,352 11,426 

Nonroad 

Gasoline 1,434,660 14,718,809 228,632 54,432 50,077 1,422 1,112 

Other Nonroada 276,526 1,608,678 3,379,781 232,711 212,053 1,027,440 3,035 

Stationary/Area 8,740,057 11,049,239 5,773,927 3,194,610 3,047,714 7,864,681 3,839,925 

Total 11,502,057 53,871,078 11,217,977 3,560,119 3,371,010 8,931,926 4,245,983 

Table 3.2-1 

continued Benzene Ethanol 1,3­

Butadiene 

Acetaldehyde Formaldehyde Naphthalene Acrolein 

Onroad 

Gasoline 25,363 43,875 3,282 6,623 7,866 4,037 384 

Onroad Diesel 1,749 0 958 3,857 10,589 20 513 

Nonroad 

Gasoline 26,193 71,433 4,935 4,033 7,245 713 436 

Other Nonroada 3,815 12 939 9,549 22,355 24 1,021 

Stationary/Area 111,337 462,566 1,847 13,118 23,846 9,404 3,412 

Total 168,457 577,885 11,961 37,181 71,901 14,198 5,766 

a

 Nonroad diesel, LPG, CNG engines and all locomotive, aircraft, and commercial marine 

Our projected overall emission impacts for the less sensitive and more sensitive cases are 

shown in Table 3.2-2 and 3.2-3 for 2022, showing the expected emission changes for the U.S. in 

that year, and the percent contribution of this impact relative to the total U.S. inventory across all 

sectors relative to each of the reference cases. 

475 
 

 

Table 3.2-2. 

RFS2 “Less Sensitive” Case Emission Impacts in 2022 Relative to Each Reference Case
 

Pollutant 

RFS1 Base RFS1 Mandate AEO2007 

Annual 

Short Tons 

% of Total 

US 

Inventory 

Annual 

Short Tons 

% of Total 

US 

Inventory 

Annual 

Short Tons 

% of Total 

US 

Inventory 

NOx 312,400 2.8% 274,982 2.5% 195,735 1.7% 

HC 112,401 1.0% 72,362 0.6% -8,193 -0.07% 

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

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

CO -2,344,646 -4.4% -1,669,872 -3.1% -240,943 -0.4% 

Benzene -2,791 -1.7% -2,507 -1.5% -1,894 -1.1% 

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

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

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

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

Naphthalene 5 0.03% 3 0.02% -1 -0.01% 

Acrolein 290 5.0% 252 4.4% 174 3.0% 

SO2 28,770 0.3% 4,461 0.05% -47,030 -0.5% 

NH3 -27,161 -0.6% -27,161 -0.6% -27,161 -0.6% 

Table 3.2-3. 

RFS2 “More Sensitive” Case Emission Impacts in 2022 Relative to Each Reference Case
 

Pollutant 

RFS1 Base RFS1 Mandate AEO2007 

Annual 

Short Tons 

% of Total 

US 

Inventory 

Annual 

Short Tons 

% of Total 

US 

Inventory 

Annual 

Short Tons 

% of Total 

US 

Inventory 

NOx 402,795 3.6% 341,028 3.0% 210,217 1.9% 

HC 100,313 0.9% 63,530 0.6% -15,948 -0.14% 

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

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

CO -3,779,572 -7.0% -3,104,798 -5.8% -1,675,869 -3.1% 

Benzene -5,962 -3.5% -5,494 -3.3% -4,489 -2.7% 

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

1,3-Butadiene -212 -1.8% -282 -2.4% -430 -3.6% 

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

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

Naphthalene -175 -1.2% -178 -1.3% -187 -1.3% 

Acrolein 253 4.4% 218 3.8% 143 2.5% 

SO2 28,770 0.3% 4,461 0.05% -47,030 -0.5% 

NH3 -27,161 -0.6% -27,161 -0.6% -27,161 -0.6% 

476 
Fuel production and distribution emission impacts of the proposed program were 

estimated in conjunction with the development of life cycle GHG emission impacts, and the 

GHG emission inventories discussed in chapter 2. These emissions are calculated according to 

the breakdowns of agriculture, feedstock transport, fuel production, and fuel distribution; the 

basic calculation is a function of fuel volumes in the analysis year and the emission factors 

associated with each process or subprocess. Additionally, the emission impact of displaced 

petroleum is estimated, using the same domestic/import shares discussed in chapter 2. 

In general the basis for this life cycle evaluation was the analysis conducted as part of the 

Renewable Fuel Standard (RFS1) rulemaking, but enhanced significantly. While our approach 

for the RFS1 was to rely heavily on the “Greenhouse Gases, Regulated Emissions, and Energy 

Use in Transportation” (GREET) model, developed by the Department of Energy’s Argonne 

National Laboratory (ANL), we are now able to take advantage of additional information and 

models to significantly strengthen and expand our analysis for this proposed rule. In particular, 

the modeling of the agriculture sector was greatly expanded beyond the RFS1 analysis, 

employing economic and agriculture models to consider factors such as land-use impact, 

agricultural burning, fertilizer, pesticide use, livestock, crop allocation, and crop exports. 

Other updates and enhancements to the GREET model assumptions include updated 

emission factors for NOx, CO, and SO2 from new cellulosic ethanol plant modeling by the 

National Renewable Energy Laboratory (NREL), and updated fuel and feedstock transport 

emission factors that account for recent EPA emission standards and modeling, such as the Tier 4 

diesel truck standards published in 2004 and the locomotive and commercial marine standards 

finalized in 2008. Emission factors for new corn ethanol plants continue to use the values 

developed for the RFS1 rule, which were based on data submitted by states for dry mill plants. 

There are no new standards planned at this time that would offer any additional control of 

emissions from corn or cellulosic ethanol plants. In addition, GREET does not include air toxics 

or ethanol. Thus emission factors for ethanol and the following air toxics were added: benzene, 

1,3-butadiene, formaldehyde, acetaldehyde, acrolein and naphthalene. 

Results of these calculations relative to each of the reference cases for 2022 are shown in 

Table 3.2-4 for the criteria pollutants, ammonia, ethanol and individual air toxic pollutants. It 

should be noted that the impacts relative to the two RFS1 reference cases (3.64 and 6.7 billion 

gallons) rely on applying ethanol volume proportions to the modeling results of the AEO 

reference case (13.2 billion gallons). Due to the complex interactions involved in projections in 

the agricultural modeling, we cannot say how reliable this simple proportional methodology is, 

and the modeling that had been done for the RFS1 rule itself was much simpler and inconsistent 

with the new modeling. Thus, we plan to conduct additional agricultural modeling specifically 

for the RFS1 mandate case prior to finalizing this rule. 

The fuel production and distribution impacts of the proposed program on VOC are 

mainly due to increases in emissions connected with biofuel production, countered by decreases 

in emissions associated with gasoline production and distribution as ethanol displaces some of 

the gasoline. Increases in NOx, PM2.5, and SOx are driven by combustion emissions from the 

substantial increase in corn and cellulosic ethanol production. Ethanol plants (corn and 

cellulosic) tend to have greater combustion emissions relative to petroleum refineries on a per477 
 

British thermal unit (BTU) of fuel produced basis. Increases in SOx emissions are primarily due 

to corn ethanol production. Ammonia emissions are expected to decrease substantially due to 

lower livestock counts, which more than offsets increased ammonia from fertilizer use. 

Ethanol vapor and most air toxic emissions associated with fuel production and 

distribution are projected to increase. Relative to the US total reference case emissions with 

RFS1 mandate ethanol volumes, increases of 10 - 20 percent for acetaldehyde and ethanol vapor 

are especially significant because they are driven directly by the increased ethanol production 

and distribution. Formaldehyde and acrolein increases are smaller, on the order of 1 - 5 percent. 

Benzene emissions are estimated to decrease by 1 percent due to decreased gasoline use. There 

are also very small increases in 1,3-butadiene and decreases in naphthalene relative to the US 

total emissions. 

Table 3.2-4. 

Fuel Production and Distribution Impacts in 2022 Relative to Each Reference Case
 

Pollutant 

RFS1 Base RFS1 Mandate AEO2007 

Annual 

Short Tons 

% of Total 

US 

Inventory 

Annual 

Short Tons 

% of Total 

US 

Inventory 

Annual 

Short Tons 

% of Total 

US 

Inventory 

NOx 241,041 2.1% 222,732 2.0% 183,951 1.6% 

HC 77,295 0.7% 46,702 0.4% -17,501 -0.2% 

PM10 50,482 1.4% 37,324 1.1% 9,453 0.3% 

PM2.5 14,419 0.4% 11,550 0.3% 5,473 0.16% 

CO 186,559 0.3% 179,855 0.3% 165,656 -0.5% 

Benzene -1,670 -1.0% -1,686 -1.0% -1,719 -1.0% 

Ethanol 115,187 19.9% 100,134 17.3% 68,379 11.8% 

1,3-Butadiene 16 0.13% 16 0.14% 17 0.14% 

Acetaldehyde 7,460 20.1% 6,680 18.0% 5,029 13.5% 

Formaldehyde 877 1.2% 800 1.1% 638 0.9% 

Naphthalene -6 -0.04% -5 -0.04% -4 -0.03% 

Acrolein 278 4.8% 244 4.2% 174 3.0% 

SO2 28,770 0.3% 4,461 0.05% -47,030 -0.5% 

NH3 -27,161 -0.6% -27,161 -0.6% -27,161 -0.6% 

A breakout of these upstream emissions by where they occur in the 

production/distribution chain is shown in Table 3.2-5. The displaced gasoline line of this table 

refers to the impacts of decreasing the petroleum based gasoline and diesel fuel production as 

some of the needed energy is replaced with ethanol and biodiesel fuels. 

478 
 

 

Table 3.2-5. Emission Inventory Impacts by Fuel Production/Distribution Segment 

Relative to the AEO Reference Case (annual short tons)
 

VOC CO NOx PM10 PM2.5 SO2 NH3 

Agriculture -4,619 15,449 -8,454 17,074 4,108 12,773 -27,161 

Biofuel Feedstock 

Transport 534 786 2,201 348 149 917 0 

Biofuel 

Production 32,278 159,188 217,975 5,372 6,150 -37,629 0 

Biofuel Transport 

& Distribution -2,217 3,610 12,755 470 355 1,147 0 

Displaced gasoline -43,477 -13,377 -40,526 -13,812 -5,288 -24,238 0 

Total Upstream -17,501 165,656 183,951 9,453 5,473 -47,030 -27,161 

Table 3.2-5 

continued Benzene Ethanol 1,3­Butadiene 

Acetaldehyde Formaldehyde Naphthaleneb Acrolein 

Agriculture -1,665 0 17.71 75 179 -1.25 -13 

Biofuel 

Feedstock 

Transport 

6 0 0.33 15 42 0.45 2 

Biofuel 

Production 156 37,856 -0.01 4,986 835 0.01 191 

Biofuel 

Transport & 

Distribution 

-89 30,523 1.78 17 40 0.84 2 

Displaced 

gasoline -127 0 -3.22 -64 -458 -4.21 -8 

Total Upstream -1,719 68,379 16.59 5,029 638 -4.17 174 

Tables 3.2-6 and 3.2-7 summarize the vehicle and equipment emission impacts in 2022 

for the “less sensitive” and “more sensitive” cases, including the biodiesel impacts. Table 3.2-8 

shows that the biodiesel contribution to these impacts is quite small. While the three fuel effect 

scenarios were only modeled for passenger cars and trucks, these totals reflect the net emissions 

from all mobile sources, including passenger cars and trucks, heavy duty trucks, off-road sources 

and portable fuel containers, using the same emissions in all three cases for the non-passenger 

car/truck categories. A full description of the basis of these vehicle and equipment emission 

impacts is given in Section 3.1.1 of this document. 

479 
 

Table 3.2-6. 

2022 Vehicle and Equipment Emission Impacts by Fuel Type 

for the “Less Sensitive” Case Relative to Each Reference Case
 

Pollutant 

RFS1 Base RFS1 Mandate AEO2007 

Annual 

Short Tons 

% of Total 

US 

Inventory 

Annual 

Short Tons 

% of Total 

US 

Inventory 

Annual 

Short Tons 

% of Total 

US 

Inventory 

NOx 71,359 0.6% 52,250 0.5% 11,784 0.11% 

HC 35,106 0.3% 25,659 0.2% 9,308 0.08% 

PM10 -177 0.00% -177 0.00% -177 0.00% 

PM2.5 -98 0.00% -98 0.00% -98 0.00% 

CO -2,531,205 -4.7% -1,849,728 -3.4% -406,599 -0.8% 

Benzene -1,122 -0.7% -821 -0.5% -174 -0.1% 

Ethanol 95,493 16.5% 69,795 12.1% 15,383 2.7% 

1,3-Butadiene 328 2.7% 238 2.0% 48 0.4% 

Acetaldehyde 5,057 13.6% 3,689 9.9% 793 2.1% 

Formaldehyde 771 1.1% 548 0.8% 76 0.11% 

Naphthalene 10 0.07% 8 0.05% 3 0.02% 

Acrolein 12 0.2% 8 0.14% -0.4 -0.01% 

SO2 0 0.0% 0 0.0% 0 0.0% 

NH3 0 0.0% 0 0.0% 0 0.0% 

480 
Table 3.2-7. 

2022 Vehicle and Equipment Emission Impacts by Fuel Type 

for the “More Sensitive” Case Relative to Each Reference Case
 

Pollutant 

RFS1 Base RFS1 Mandate AEO2007 

Annual 

Short Tons 

% of Total 

US 

Inventory 

Annual 

Short Tons 

% of Total 

US 

Inventory 

Annual 

Short Tons 

% of Total 

US 

Inventory 

NOx 161,754 1.4% 118,295 1.1% 26,266 0.2% 

HC 23,018 0.2% 16,828 0.15% 1,553 0.01% 

PM10 -4,289 -0.12% -4,289 -0.12% -4,289 -0.12% 

PM2.5 -3,884 -0.12% -3,884 -0.12% -3,884 -0.12% 

CO -3,966,131 -7.4% -3,284,654 -6.1% -1,841,524 -3.4% 

Benzene -4,293 -2.6% -3,808 -2.3% -2,770 -1.6% 

Ethanol 113,376 19.6% 87,792 15.2% 36,886 6.4% 

1,3-Butadiene -228 -1.9% -298 2.5% -446 -3.7% 

Acetaldehyde 8,915 24.0% 7,598 20.4% 4,809 12.9% 

Formaldehyde 2,497 3.5% 2,324 3.2% 1,958 2.7% 

Naphthalene -170 -1.2% -172 -1.2% -182 -1.3% 

Acrolein -25 -0.4% -27 -0.5% -31 -0.5% 

SO2 0 0.0% 0 0.0% 0 0.0% 

NH3 0 0.0% 0 0.0% 0 0.0% 

Table 3.2-8. 

2022 Biodiesel Emission Impacts Relative to All Reference Cases 

(these impacts are included in Tables 3.2-5 and 3.2-6)
 

Pollutant 

Biodiesel 

Impacts 

Annual Short 

Tons 

NOx 418 

HC -753 

PM10 -177 

PM2.5 -98 

CO -1,275 

Benzene -9.4 

Ethanol 0.0 

1,3-Butadiene -5.1 

Acetaldehyde -21 

Formaldehyde -57 

Naphthalene -0.12 

Acrolein -2.7 

SO2 0.0 

NH3 0.0 

481 
 

Table 3.2-9 shows a breakout of the relative impacts of this proposal on the various types 

of vehicle and equipment emissions for the more sensitive case relative to the AEO reference 

case. The gasoline vehicle exhaust emission values were generated by MOVES, while the 

NMIM model was used to generate the other vehicle and equipment emission impacts. The 

impacts on portable fuel container emissions were estimated using an analysis of available data, 

adjusted for the ethanol and gasoline fuel volumes in this proposal. The methods used are 

described above in Section 3.1.1. The substantial CO and PM reductions from light-duty 

vehicles are due to the effects of E85. Evaporative and refueling vapor emissions only include 

VOC, benzene, and naphthalene. 

Table 3.2-9. Vehicle and Equipment Emission Inventory Impacts by Source Type 

for the “More Sensitive” Case Relative to the AEO Reference Case (annual short tons)
 

VOCa CO NOx PM10 PM2.5 SO2 NH3 

Light-duty gasoline 

vehicle exhaust -1,945 -1,418,363 14,258 -4,112 -3,786 0 0 

Light-duty gasoline 

vehicle evap -2,549 n/a b

 n/a n/a n/a n/a n/a 

Light-duty gasoline 

vehicle refueling 4,476 n/a n/a n/a n/a n/a n/a 

Heavy-duty 

gasoline vehicle 

exhaust 

-141 839 1,060 0 0 0 0 

Heavy-duty 

gasoline vehicle 

evap 

44 n/a n/a n/a n/a n/a n/a 

Heavy-duty 

gasoline vehicle 

refueling 

977 n/a n/a n/a n/a n/a n/a 

Nonroad gasoline 

equipment exhaust -6,810 -422,725 10,530 0 0 0 0 

Nonroad gasoline 

equipment evap 7,216 n/a n/a n/a n/a n/a n/a 

Nonroad gasoline 

equipment refueling 6,609 n/a n/a n/a n/a n/a n/a 

Portable fuel 

containers 1,037 n/a n/a n/a n/a n/a n/a 

Onroad diesel 

vehicles -753 -1,275 418 -177 -98 0 0 

482 
 

Table 3.2-9 

continued Benzene Ethanol 1,3­Butadiene 

Acetaldehyde Formaldehyde Naphthaleneb Acrolein 

Light-duty gasoline 

vehicle exhaust -2,758 19,850 -474 4,489 1,948 -180 -29 

Light-duty gasoline 

vehicle evap 27 7,981 n/a n/a n/a -4 n/a 

Light-duty gasoline 

vehicle refueling 15 1,034 n/a n/a n/a 2 n/a 

Heavy-duty 

gasoline vehicle 

exhaust 

-19 109 0.46 33 4.6 0 0 

Heavy-duty 

gasoline vehicle 

evap 

0.39 77 n/a n/a n/a 0.02 n/a 

Heavy-duty 

gasoline vehicle 

refueling 

3 214 n/a n/a n/a 0.11 n/a 

Nonroad gasoline 

equipment exhaust -156 3,071 32 308 63 0 1.2 

Nonroad gasoline 

equipment evap 128 4,937 n/a n/a n/a 0 n/a 

Nonroad gasoline 

equipment refueling 108 1,645 n/a n/a n/a 0 n/a 

Portable fuel 

containers -0.30 646 n/a n/a n/a 0.13 n/a 

Onroad diesel 

vehicles -9 0 -5 -21 -57 -0.12 -3 

a

 "VOC" values shown are actually THC for onroad gasoline exhaust and evaporative emissions. b

 n/a = Not applicable 

Table 3.2-10 shows the relative impacts of various types of renewable fuels on the basis 

of tons per million BTUs of renewable fuel consumed. These values include all 

vehicle/equipment as well as upstream fuel production/distribution impacts. 

483 
 

Table 3.2-10. Emission Inventory Impacts (tons per mmBTU) 

by Type of Renewable Fuel Relative to the AEO Reference Case 

VOC CO NOx PM10 PM2.5 SO2 NH3 

Ethanol from 

domestic corn 

(except coal) 

32.50 -1,131 57.45 41.72 3.62 111.30 -18.85 

Ethanol from 

domestic corn 

(coal) 

-72.28 -1,038 -12.47 332.23 79.56 -131.38 -11.85 

Ethanol from 

domestic 

cellulosic 

-9.32 -1,035 131.30 -0.40 1.69 -55.03 -18.88 

Ethanol from 

imported 

sugarcane 

-23.82 -1,174 -30.37 -10.54 -5.33 -13.71 0.29 

Biodiesel -37.11 -15.20 5.02 4.97 0.35 10.78 -11.04 

Renewable Diesel -24.37 -3.85 -10.63 -2.69 -0.82 -4.85 0.00 

Ethanol from 

domestic corn 

(except coal) 

-0.94 43.35 0.0120 3.42 0.50 -0.0025 0.64 

Ethanol from 

domestic corn 

(coal) 

-0.60 43.35 0.0073 3.40 0.44 -0.0022 0.46 

Ethanol from 

domestic 

cellulosic 

-0.94 47.27 0.0119 3.67 0.51 -0.0026 0.63 

Ethanol from 

imported 

sugarcane 

0.12 19.39 -0.0008 -0.0272 -0.25 -0.0020 0.505 

Biodiesel -0.61 2.89E-07 0.0057 0.0095 -0.15 -0.0026 0.289 

Renewable Diesel -0.072 0 -0.0012 -0.0273 -0.25 -0.0022 -0.0035 

3.3 Air Quality Impacts 

Section 3.2 of this DRIA presents the projected emissions changes due to the proposed 

rule. Once the emissions changes are projected, the next step is to look at how the ambient air 

quality would be impacted by those emissions changes. This section presents information about 

ambient air quality, including discussion of the methodology that we will use to perform ambient 

air quality modeling for the final rule. Section 3.4 describes the health effects associated with 

criteria and air toxic pollutants. Section 5.4 describes the methodology for calculating monetized 

benefits of this rule due to reductions in adverse health effects associated with PM2.5 and ozone. 

484 
3.3.1 Air Quality Modeling 

Air quality models use mathematical and numerical techniques to simulate the physical 

and chemical processes that affect air pollutants as they disperse and react in the atmosphere. 

Based on inputs of meteorological data and source information, these models are designed to 

characterize primary pollutants that are emitted directly into the atmosphere and secondary 

pollutants that are formed as a result of complex chemical reactions within the atmosphere. 

Photochemical air quality models have become widely recognized and routinely utilized tools for 

regulatory analysis by assessing the effectiveness of control strategies. These models are applied 

at multiple spatial scales - local, regional, national, and global. Section 3.3.1.2 of this DRIA 

provides more detail on the photochemical model, the Community Multi-scale Air Quality 

(CMAQ) model, which will be utilized for the final rule analysis. 

3.3.1.1 Current and Projected Ambient Levels of Pollutants 

Although the purpose of this proposal is to implement the renewable fuel requirements 

established by the Energy Independence and Security Act (EISA) of 2007, this proposed rule 

would also impact emissions of criteria and air toxic pollutants. This section describes current 

and recently projected ambient levels of ozone, PM and some air toxics without the standards 

being proposed in this rule. 

3.3.1.1.1 Particulate Matter (PM2.5 and PM10) 

As of December 16, 2008, approximately 88 million people live in the 39 areas that are 

designated as nonattainment for the 1997 PM2.5 National Ambient Air Quality Standard 

(NAAQS). These PM2.5 nonattainment areas are comprised of 208 full or partial counties. The 

1997 PM2.5 NAAQS was recently revised and the 2006 24-hour PM2.5 NAAQS became effective 

on December 18, 2006. Area designations for the 2006 24-hour PM2.5 NAAQS are expected to 

be promulgated in 2009 and become effective 90 days after publication in the Federal Register. 

As of December 16, 2008, approximately 26 million people live in the 47 areas that are 

designated as nonattainment for the PM10 NAAQS. There are 40 full or partial counties that 

make up the PM10 nonattainment areas. 

EPA has already adopted many mobile source emission control programs that are 

expected to reduce ambient PM levels. These control programs include the Marine SparkIgnition and Small Spark-Ignition Engine rule (73 FR 59034, October 8, 2008), Locomotive and 

Marine Compression-Ignition Engine Rule (73 FR 25098, May 6, 2008), the Clean Air Nonroad 

Diesel rule (69 FR 38957, June 29, 2004), the Heavy Duty Engine and Vehicle Standards and 

Highway Diesel Fuel Sulfur Control Requirements (66 FR 5002, Jan. 18, 2001) and the Tier 2 

Motor Vehicle Emissions Standards and Gasoline Sulfur Control Requirements (65 FR 6698, 

Feb. 10, 2000). As a result of these programs, the number of areas that fail to meet the PM2.5 

NAAQS in the future is expected to decrease. This decrease is shown in the PM air quality 

analyses that were performed for the Marine Spark-Ignition and Small Spark-Ignition Engine 

485 
 

rule.PPPPPPPP That analysis projected that there would be 11 counties (down from 208 counties 

currently designated as nonattainment), where 24 million people are projected to live, with PM2.5 

design values at or above the 2006 annual PM2.5 standard in 2020. 

3.3.1.1.2 Ozone 

As of December 16, 2008, approximately 132 million people live in the 57 areas that are 

designated as nonattainment for the 1997 8-hour ozone NAAQS. There are 293 full or partial 

counties that make up the 8-hour ozone nonattainment areas. The 1997 ozone NAAQS was 

recently revised and the 2008 ozone NAAQS was finalized on March 12, 2008. Table 3.3-2 

presents the number of counties in areas currently designated as nonattainment for the 1997 

ozone NAAQS as well as the number of additional counties that have monitored data that is 

greater than the 2008 ozone NAAQS. 

Table 3.3-2. 

Counties with Design Values Greater than the 2008 Ozone NAAQS 

Based on 2004-2006 Air Quality Data 

 Number of Counties Populationa 

1997 Ozone Standard: counties within the 57 

areas currently designated as nonattainment 

293 131,977,890 

2008 Ozone Standard: additional counties that 

would not meet the 2008 NAAQSb 

74 15,984,135 

Total 367 147,962,025 

Notes: 

a

 Population numbers are from 2000 census data. 

b

 Attainment designations for the 2008 ozone NAAQS have not yet been made. Nonattainment for the 2008 Ozone 

NAAQS will be based on three years of air quality data from later years. Also, the county numbers in the table 

include only the counties with monitors violating the 2008 Ozone NAAQS. The numbers in this table may be an 

underestimate of the number of counties and populations that will eventually be included in areas with multiple 

counties designated nonattainment. 

EPA has already adopted many mobile source emission control programs that are 

expected to reduce ambient ozone levels. These control programs include the Marine SparkIgnition and Small Spark-Ignition Engine rule (73 FR 59034, October 8, 2008), Locomotive and 

Marine Compression-Ignition Engine Standards (73 FR 25098, May 6, 2008), the Clean Air 

Nonroad Diesel rule (69 FR 38957, June 29, 2004), the Heavy Duty Engine and Vehicle 

Standards and Highway Diesel Fuel Sulfur Control Requirements (66 FR 5002, Jan. 18, 2001) 

and the Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur Control Requirements 

(65 FR 6698, Feb. 10, 2000). As a result of these programs, the number of areas that fail to meet 

the 8-hour ozone NAAQS in the future is expected to decrease. This decrease in areas that fail to 

meet the 8-hour ozone NAAQS is shown in the ozone air quality analyses that were performed 

for the Marine Spark-Ignition and Small Spark-Ignition Engine rule.QQQQQQQQ That analysis 

projected that there would be 8 counties (down from 293 counties currently designated as 

PPPPPPPP Details on the air quality modeling are provided in the RIA for the Marine Spark-Ignition and Small SparkIgnition Engine final rule, included in the docket for this proposed rule. 

QQQQQQQQ Details on the air quality modeling are provided in the RIA for the Marine Spark-Ignition and Small 

Spark-Ignition Engine final rule, included in the docket for this proposed rule. 

486 
 

nonattainment), where 22 million people are projected to live, with 8-hour ozone design values at 

or above 85 ppb in 2020. 

3.3.1.1.3 Air Toxics 

According to the National Air Toxic Assessment (NATA) for 1999, mobile sources were 

responsible for 44 percent of outdoor toxic emissions and almost 50 percent of the cancer risk. 

Benzene is the largest contributor to cancer risk of all 133 pollutants quantitatively assessed in 

the 1999 NATA. Mobile sources were responsible for 68 percent of benzene emissions in 1999. 

Over the years, EPA has implemented a number of mobile source and fuel controls resulting in 

VOC reductions, which also reduce benzene and other air toxic emissions. Recent fuel and 

vehicle standards were implemented to specifically control benzene emissions, and it is expected 

that overall levels of air toxics will decrease through 2020, after which concentrations start to 

increase slowly due to expected increases in vehicle and engine activity.607 

However, as presented in Section 3.2 of this DRIA, there would be a substantial increase 

in emissions of ethanol and acetaldehyde from the proposed fuels standards. This suggests a 

likely increase in ambient levels of acetaldehyde. Formaldehyde and acrolein emissions would 

also increase somewhat, while emissions of benzene and 1,3-butadiene would decrease as a 

result of the proposed standards. Full-scale photochemical modeling is necessary to provide the 

needed spatial and temporal detail to more completely and accurately estimate the changes in 

ambient levels of both criteria and non-criteria pollutants. The plans for full-scale photochemical 

air quality modeling are discussed immediately below in Section 3.3.1.2. 

3.3.1.2 Community Multi-scale Air Quality (CMAQ) Modeling Plans 

Full-scale photochemical air quality modeling is necessary to accurately project levels of 

PM2.5, ozone and air toxics. For the final rule, a national-scale air quality modeling analysis will 

be performed to analyze the impacts of the standards on PM2.5, ozone, and selected air toxics. 

The length of time needed to prepare necessary inventory and model updates precluded us from 

performing air quality modeling for this proposal. 

The atmospheric chemistry related to ambient concentrations of PM2.5, ozone and air 

toxics is very complex, and making predictions based solely on emissions changes is extremely 

difficult. Localized changes in VOC and NOx emissions, as well as direct PM and PM 

precursors may impact concentrations of PM and ozone. Air quality modeling will allow us to 

account for both changes in the spatial distribution of PM and PM precursors, and changes in 

VOC speciation which could impact secondary PM formation. For example, reductions in 

aromatics in gasoline might reduce ambient PM concentrations by reducing secondary PM 

formation. Section 3.3.3 of this DRIA contains more information on aromatics and secondary 

aerosol formation. 

In addition, air quality modeling would account for changes in fuel type and spatial 

distribution of fuels that would change emissions of ozone precursor species and thus could 

affect ozone concentrations. Section 3.3.2 of this DRIA provides more detail on the atmospheric 

chemistry and potential changes in ozone formation due to increased usage of ethanol fuels. 

487 
 

For the final rule, EPA intends to use a 2005-based CMAQ modeling platform as the tool 

for the air quality modeling. The CMAQ modeling system is a comprehensive three-dimensional 

grid-based Eulerian air quality model designed to estimate the formation and fate of oxidant 

precursors, primary and secondary PM concentrations and deposition, and air toxics, over 

regional and urban spatial scales (e.g., over the contiguous U.S.).608,609,610 The CMAQ model is 

a well-known and well-respected tool and is commonly used for both regulatory analyses, for 

instance the recent ozone NAAQS rule611, and in developing attainment demonstration State 

Implementation Plans. The CMAQ model (version 4.6) was peer-reviewed in February of 2007 

for EPA as reported in “Third Peer Review of CMAQ Model.”612 

CMAQ includes many science modules that simulate the emission, production, decay, 

deposition and transport of organic and inorganic gas-phase and particle-phase pollutants in the 

atmosphere. We intend to use the most recent CMAQ version (v4.7) which was officially 

released by EPA’s Office of Research and Development (ORD) in December 2008, and reflects 

updates to earlier versions in a number of areas to improve the underlying science. These 

include (1) enhanced secondary organic aerosol (SOA) mechanism to include chemistry of 

isoprene, sesquiterpene, and aged in-cloud biogenic SOA in addition to terpene; (2) improved 

vertical convective mixing; (3) improved heterogeneous reaction involving nitrate formation; and 

(4) an updated gas-phase chemistry mechanism, Carbon Bond 05 (CB05), with extensions to 

model explicit concentrations of air toxic species as well as chlorine and mercury. This 

mechanism, CB05-toxics, also computes concentrations of species that are involved in aqueous 

chemistry and that are precursors to aerosols. Section 3.3.3 of the DRIA for this proposal 

discusses SOA formation and details about the improvements made to the SOA mechanism 

within this recent release of CMAQ. 

As shown in Figure 3.3-3 the CMAQ modeling domain covers the continental U.S. and 

portions of Canada and Mexico. There are two 12 x 12 km horizontal grid resolution modeling 

domains, an Eastern US domain (outlined in red) and a Western US domain (outlined in blue). 

The modeling domain contains 14 vertical layers with the top of the modeling domain at about 

16,200 meters, or 100 millibars (mb). 

488 
Figure 3.3-3. CMAQ 12-km Eastern and Western US Modeling Domains 

The key inputs to the CMAQ model include emissions from anthropogenic and biogenic 

sources, meteorological data, and initial and boundary conditions. The CMAQ meteorological 

input files will be derived from a simulation of the Pennsylvania State University / National 

Center for Atmospheric Research Mesoscale Model613 for the entire year of 2005. This model, 

commonly referred to as MM5, is a limited-area, nonhydrostatic, terrain-following system that 

solves for the full set of physical and thermodynamic equations which govern atmospheric 

motions. The meteorology for the national 36 km grid and the 12 km Eastern and Western U.S. 

grids will be developed by EPA and described in more detail within the Air Quality Modeling 

Technical Support Document for the final rule.614 The meteorological outputs from MM5 will 

be processed to create model-ready inputs for CMAQ using the Meteorology-Chemistry 

Interface Processor (MCIP) version 3.4 to derive the specific inputs to CMAQ, for example: 

horizontal wind components (i.e., speed and direction), temperature, moisture, vertical diffusion 

rates, and rainfall rates for each grid cell in each vertical layer.615 

The lateral boundary and initial species concentrations will be provided by a threedimensional global atmospheric chemistry model, the GEOS-CHEM model.616 The global 

GEOS-CHEM model simulates atmospheric chemical and physical processes driven by 

assimilated meteorological observations from the NASA’s Goddard Earth Observing System 

489 
 

 

 

(GEOS). This model will be run for 2005 with a grid resolution of 2 degree x 2.5 degree 

(latitude-longitude) and 30 vertical layers. The predictions will be used to provide one-way 

dynamic boundary conditions and an initial concentration field for the 36 km CMAQ 

simulations. The future base conditions from the 36 km coarse grid modeling will be used as the 

initial/boundary state for all subsequent 12 km finer grid modeling. 

3.3.2 Atmospheric Reactions Associated with Ethanol in Gasoline 

Ethanol, molecular formula CH3CH2OH, is a volatile organic hydrocarbon and is present 

in the gas-phase in the atmosphere.617 Complete combustion of ethanol in fuel produces carbon 

dioxide (CO2) and water (H2O). 

Incomplete combustion results in the production of other air pollutants, such as 

acetaldehyde and other aldehydes, and the release of unburned ethanol. Ethanol is also present 

in evaporative emissions. In the atmosphere, ethanol from unburned fuel and evaporative 

emissions can undergo photodegradation to form aldehydes (acetaldehyde and formaldehyde) 

and peroxyacetyl nitrate (PAN), and also plays a role in ground level ozone formation. 

Based on kinetic data for molecular reactions, the only important chemical loss process 

for ethanol (and other alcohols) is reaction with the hydroxyl radical (·OH).618 This reaction 

produces acetaldehyde (CH3CHO) with a 90% yield.619 The lifetime of ethanol in the 

atmosphere can be calculated from the rate coefficient, k, and due to reaction with the OH 

radical, occurs on the order of hours in polluted urban areas or several days in unpolluted areas. 

(All rate coefficients are listed at 298 K and, if applicable, 1 bar of air.) 

-1 620 CH3CH2OH + ·OH → CH3C·HOH + H2O k = 3.2 x 10-12 cm3

molecule-1s

CH3C·HOH + O2 → CH3CHO + HO2 

Reactions of ethanol (and other alcohols) with nitrate radical, ozone, and photolysis are 

slow and of negligible importance in the atmosphere. 

3.3.2.1 Aldehydes 

3.3.2.1.1 Acetaldehyde 

Acetaldehyde is the main photodegradation product of ethanol (see Section 3.3.2 of this 

DRIA) as well as other precursor hydrocarbons. Acetaldehyde is also a product of fuel 

combustion. In the atmosphere, acetaldehyde can react with the OH radical and O2 to form the 

acetyl peroxy radical [CH3C(O)OO·].RRRRRRRR This radical species can then further react with 

nitric oxide (NO), to produce formaldehyde (HCHO), or with nitrogen dioxide (NO2), to produce 

PAN [CH3C(O)OONO2]. An overview of these reactions and the corresponding reaction rates 

are provided below. 

RRRRRRRR Acetaldehyde is not the only source of acetyl peroxy radicals in the atmosphere. For example, dicarbonyl 

compounds (methylglyoxal, biacetyl, and others) also form acetyl radicals, which can further react to form 

peroxyacetyl nitrate (PAN). 

490 
 

 

 

 

 

 

 

 

 

 

-1 621 CH3CHO + ·OH → CH3C·O + H2O k = 1.5 x 10-11 cm3

molecule-1s

CH3C·O + O2 + M → CH3C(O)OO· + M 

-1 622 CH3C(O)OO· + NO → CH3C(O)O· + NO2 k = 2.0 x 10-11 cm3

molecule-1s

CH3C(O)O· → ·CH3 + CO2 

·CH3 + O2 + M → CH3OO· + M 

CH3OO· + NO → CH3O· + NO2 

CH3O· + O2 → HCHO + HO2 

-1 623 CH3C(O)OO· + NO2 + M → CH3C(O)OONO2 + M k = 1.0 x 10-11 cm3

molecule-1s

Acetaldehyde can also photolyze (hν), which predominantly produces ·CH3 and HCO: 

CH3CHO + hν → ·CH3 + HCO λ = 240-380 nm 624 

As described above, ·CH3 is oxidized in the atmosphere to produce formaldehyde (HCHO). 

3.3.2.1.2 Formaldehyde 

Formaldehyde is the photodegradation product of acetaldehyde (DRIA Section 3.3.2.1.1 

above) as well as other precursor hydrocarbons. Formaldehyde is also a product of hydrocarbon 

combustion. In the atmosphere, formaldehyde undergoes photolysis and reaction with the OH 

radical, NO3 radical, and ozone, and the resulting lifetimes are ~4 hours, 1.2 days, 83 days, and 

>4.5 years, respectively.SSSSSSSS Formaldehyde is removed mainly by photolysis whereas the 

higher aldehydes, those with two or more carbons such as acetaldehyde, react predominantly 

with OH radicals. The photolysis of formaldehyde is important since it is a source of additional 

radicals. 

HCHO + hν → H + HCO λ = 240-360 nm 625 

3.3.2.2 Peroxyacetyl Nitrate (PAN) 

PAN is a reservoir and carrier of NOx. PAN is the product of acetyl radicals reacting 

with NO2 in the atmosphere. One source of PAN is the photooxidation of acetaldehyde (see 

Section 3.3.2.1.1 of this DRIA), but any hydrocarbon having a methyl group has the potential for 

forming acetyl radicals and therefore PAN.TTTTTTTT PAN can undergo thermal decomposition 

with a lifetime of approximately 1 hour at 298K or 148 days at 250K. 

-1 626 CH3C(O)OONO2 + M → CH3C(O)OO· + NO2 + M k = 3.3 x 10-4 s

SSSSSSSS Lifetime calculated using the following: for photolysis, with overhead sun (at noontime during the summer); 

for OH radical reactions, a 12-hour daytime average of 2.0 x 106

 molecule cm-3; for NO3 radical reactions, a 12-hour 

nighttime average of 5 x 108

 molecule cm-3; and for ozone, a 24-hour average of 7 x 1011 molecule cm-3. TTTTTTTT Many aromatic hydrocarbons, particularly those present in high percentages in gasoline (toluene, m-, o-, pxylene, and 1,3,5-, 1,2,4-trimethylbenzene), form methylglyoxal and biacetyl, which are also strong generators of 

acetyl radicals (Smith, D.F., T.E. Kleindienst, C.D. McIver (1999) Primary product distribution from the reaction of 

OH with m-, p-xylene and 1,2,4- and 1,3,5-Trimethylbenzene. J. Atmos. Chem., 34: 339- 364.). 

491 
 

 

This temperature sensitivity allows PAN to be stable enough at low temperatures to be 

transported long distances before decomposing to release NO2. NO2 can then participate in 

ozone formation in regions remote from the original NOx source.627 

3.3.2.3 Ozone Formation 

The series of reactions described above plays a role in the formation of ground level 

ozone. In the photodegradation reactions, NO is converted to NO2 (see OH radical reaction of 

acetaldehyde in Section 3.3.2.1.1 of this DRIA). In the thermal decomposition of PAN, NO2 is 

released. In both cases, NO2 further photolyzes to produce ozone (O3). 

NO2 + hν → NO + O(3P) λ = 300-800 nm 628 

O(3

P) + O2 + M → O3 + M 

3.3.2.4 Chemical Mechanisms in Modeling 

The RFS2 rule is presenting inventories for ethanol and six air toxics -- benzene, 1,3­

butadiene, formaldehyde, acetaldehyde, acrolein, and naphthalene. All of these compounds are 

explicit model species in the CMAQv4.7 model with carbon bond 5 (CB05) mechanisms.629 

However, CMAQ also requires inventories for a large number of other air toxics and precursor 

pollutants. Inventories for these other pollutants will be developed either by running the 

National Mobile Inventory Model (NMIM) or by application of speciation profiles to VOC. 

Emissions of benzene, 1,3-butadiene, formaldehyde, acetaldehyde, acrolein, and 

naphthalene for light duty gasoline vehicles will be generated using the Motor Vehicle Emissions 

Simulator (MOVES). Ethanol emissions for air quality modeling will be based on speciation of 

VOC using different ethanol profiles (E0, E10, and E85). Light duty gasoline vehicle air toxic 

emissions not modeled by MOVES will be based on NMIM outputs, as will emissions of mobile 

source air toxic pollutants from other vehicle classes and nonroad engines. All other pollutants 

will be modeled by application of speciation profiles to VOC. MOVES, NMIM, and the 

speciation profiles which will be used all account for impacts of ethanol on emissions. 

CMAQ has the capability to track and quantify primary emissions of acetaldehyde 

separately from acetaldehyde formed by secondary reactions. In determining how much of the 

acetaldehyde in ambient air is from primary (emitted) versus secondary (produced in the 

atmosphere) sources, CMAQ would account for the degradation of primary emissions of 

acetaldehyde (lessening the impact of these emissions on total acetaldehyde) plus the formation 

of secondary acetaldehyde from other precursors. 

The CB05 mechanisms also have a speciesUUUUUUUU representing higher molecular 

weight aldehydes, those with three or more carbons. These aldehydes form, among other 

products, acetaldehyde. To the extent that these higher molecular weight aldehydes decrease or 

increase in the exhaust with increased use of ethanol, the amount of acetaldehyde formed in the 

ambient air is affected. The amount of acetaldehyde, as well as formaldehyde, formed in the 

UUUUUUUU The word species represents a technique used to lump several similar compounds into a single ‘bin’ for 

streamlining the numerical calculations performed by the model. 

492 
 

ambient air as well as emitted in the exhaust (the latter being accounted for in emission 

inventories) would also be affected by any changes in alkanes and alkenes due to the addition of 

ethanol to fuels (i.e., decreases in alkanes and alkenes would cause some decrease of 

acetaldehyde, and to a larger extent, formaldehyde). As mentioned above, the exhaust level of 

these aldehydes could be affected by use of ethanol which would also be incorporated into the 

modeling. 

The addition of ethanol to fuels has been shown to contribute to PAN formation and 

therefore ozone formation (discussed below in DRIA Section 3.3.2.5), and these compounds 

would be quantified by CMAQ. Additionally, other aromatic hydrocarbons (AHC) and 

hydrocarbons are considered because any increase in acetyl peroxy radicals due to ethanol 

increases might be counterbalanced by a decrease in radicals resulting from decreases in AHC 

and other hydrocarbons. 

CMAQ includes 63 inorganic reactions to account for the cycling of all relevant oxidized 

nitrogen species and cycling of radicals, including the termination of NO2 and formation of nitric 

acid (HNO3) without PAN formation. 

-1 630 NO2 + ·OH + M → HNO3 + M k = 1.19 x 10-11 cm3

molecule-1s

The CB05 mechanism also includes more than 90 organic reactions that include alternate 

pathways for the formation of acetyl peroxy radical, such as by reaction of methylglyoxal, which 

is also formed from reactions of AHC. Alternate reactions of acetyl peroxy radical, such as 

oxidation of NO to form NO2, which again leads to ozone formation, are also included. 

It is unclear whether ozone and other atmospheric oxidants (such as OH radical) would 

increase or decrease with the increased usage of ethanol fuels, or where the largest impacts 

would occur. The decreases in hydrocarbons other than ethanol in fuels, especially the AHC, 

would counteract the effects of increased acetaldehyde exhaust emissions to some extent, since 

AHC contribute to ozone formation. NOx increases or decreases would also have a critical 

effect on ozone. Moreover, changes in CO emissions would also impact regional background 

ozone. Modeling the ethanol fuels exhaust and evaporative emissions and the complex 

chemistry they undergo in the ambient atmosphere would allow a better assessment of the 

impacts of the changes in fuel composition. 

3.3.2.5 Ambient Monitoring and Modeling Data 

Ambient monitoring and modeling studies in the US and abroad quantify the relative 

concentrations of ethanol emissions and the potential air quality impacts of using ethanol in 

fuels. 

3.3.2.5.1 US Studies 

In the late 1980s Denver, Colorado adopted the first regulation in the country that 

required the use of oxygenated fuels to reduce carbon monoxide (CO) emissions. From the time 

the regulation was first adopted, the fuels used shifted from methyl tertiary butyl ether (MTBE) 

493 
 

and gasoline to largely ethanol-blended fuels. By the winter of 1996-1997, nearly all of the fuel 

was blended with ethanol at 10% by volume. The effect of using oxygenated fuels on 

formaldehyde and acetaldehyde concentrations were monitored from the winter of 1987-1988 

(95% of fuel blended with MTBE) through the winter of 1996-1997 (nearly all fuel blended with 

ethanol).631 Results showed no clear effect on ambient concentrations of formaldehyde and 

acetaldehyde through ten winters of oxygenated fuels use. It was hypothesized that the 

photochemical destruction of these compounds suppressed the emissions effect. 

Albuquerque, NM is another location that mandated the use of oxygenates in the 

wintertime to reduce CO emissions. A field study was conducted in Albuquerque to determine 

the atmospheric impacts of the use of ethanol fuels.632 Atmospheric concentrations of ozone, 

NOx, CO, PAN, aldehydes, and organic acids were measured in the summer of 1993, before the 

use of ethanol fuels, and in the winters of 1994 and 1995, during the use of 10% ethanol fuel 

(>99%). Results showed increased levels of PAN and aldehydes in winter. Seasonal differences 

were not accounted for. The authors noted that the daytime temperatures were fairly comparable 

for the summer and winter study periods so it appeared that the significantly higher winter 

values, despite the much lower photochemical reactivity in winter, were primarily due to local 

production of PAN. For acetaldehyde, winter values were about twice as high as the summer 

values. These acetaldehyde levels anti-correlated with PAN levels, indicating a primary source 

of aldehydes in the winter. 

Grosjean et al (2002) conducted monitoring studies in various California cities and 

measured daily maximum PAN concentrations ranging from 0.2 to 6.9 ppb.633 Peroxypropionyl 

nitrate (PPN, a compound similar to PAN) concentrations were measured at lower levels and 

ranged from 0.33-1.04 ppb. This study concluded that aromatics and alkene compounds are 

responsible for significant PAN formation with ethanol and acetaldehyde having a minor role. 

A modeling analysis performed by the California Air Resources Board suggests PAN 

formation with increased use of ethanol, but the increase was somewhat minimal.634 

Acetaldehyde and ethanol concentrations were shown to increase for the ethanol-blended fuels 

by 1 to 6% and 37 to 121%, respectively. The changes in acetaldehyde and ethanol 

concentrations were predicted to lead to a 1 to 3% increase in PAN concentration, similar to the 

3% increase in PAN concentration predicted for the non-oxygenated gasoline. Benzene (0 to ­

9%), formaldehyde (-1 to -2%), and NO2 (0 to 1%) concentrations stayed the same or decreased, 

and changes in 1,3-butadiene (-2 to 2%) and PPN (-1 to 4%) were similarly modest. 

Consequently, a sensitivity analysis of PAN formation indicated that increases in acetaldehyde 

and ethanol emissions would not lead to substantially higher PAN concentrations, presumably 

because other VOCs are larger contributors to PAN formation. 

Another air quality modeling study investigated the impacts of widespread usage of E85 

in Los Angeles and the US in 2020.635 Overall results showed increases in acetaldehyde and 

formaldehyde and decreases in 1,3-butadiene and benzene in Los Angeles and the US. Sources 

of acetaldehyde included direct emissions and to a larger degree photooxidation of unburned 

ethanol. Results of this modeling study also showed increases in unburned ethanol, PAN, and 

ozone for a future E85 scenario. 

494 
The US studies discussed here are winter studies and the lack of summer studies makes it 

difficult to quantify the magnitude of air quality impacts of ethanol fuel usage, which are 

expected to be greatest during the summer. 

3.3.2.5.2 Brazilian Studies 

The following studies investigate changes in ambient concentrations of several air 

pollutants that result from the use of ethanol fuels in Brazil. These studies are not directly 

relevant to the US due to differences such as vehicles, fuels, and climate; therefore, the EPA 

could not draw upon these conclusions to assess the magnitude of the impact of ethanol fuels on 

air quality. However, these studies do provide useful information on potential directional 

changes in pollutant levels with widespread ethanol use. 

Brazil is the only country in the world where a nationwide, large-scale alcohol fuel 

program has been implemented. In 1997, approximately 4 million automobiles ran on neat 

ethanol and approximately nine million automobiles ran on a 22% ethanol-blended gasoline 

mixture.636 

In Salvador, Bahia, Brazil, ambient levels of formaldehyde and acetaldehyde and their 

relationship with vehicular fleet composition was evaluated.637 The measured concentrations for 

formaldehyde and acetaldehyde ranged from 0.20 to 88 ppbv and from 0.40 to 93 ppbv, 

respectively. The ratio of formaldehyde to acetaldehyde revealed the relationship of vehicular 

fleet composition to ambient levels. In locations where ethanol-fueled vehicular emissions 

dominated, the ratio decreased, versus locations where diesel-fueled vehicles dominated. 

Sampling in rural areas showed no relationship between formaldehyde and acetaldehyde. 

Acetaldehyde and formaldehyde concentrations were measured in the winter of 1999 in 

Sao Paulo, Brazil.638 Ambient levels of these carbonyls were similar. Higher average mixing 

ratios of acetaldehyde and formaldehyde were found in the morning (18.9 and 17.2 ppbv) than 

midday (9.5 and 11.8 ppbv) and evening (7.2 and 10.2 ppbv). In the morning, direct emission 

from vehicles seemed to be the main primary source, whereas at midday and evening these 

compounds appeared to result mainly from photochemistry. 

A survey of volatile organic compounds in areas impacted by heavy traffic, including a 

tunnel, was obtained for Sao Paulo.639 Researchers found the ambient air was dominated by 

ethanol (414 ppbv) with elevated methanol and 1- and 2-propanol. These levels were well above 

those measurements available for US cities, particularly Los Angeles, CA. The overall data 

trend also showed levels of C4-C9 n-aldehydes to be approximately 10 times higher than in Los 

Angeles. They conclude that the use of alcohol-based fuels is the primary source for these 

differences since alcohol comprises about 40% of the mobile fuel by volume compared to 3% in 

Los Angeles. Also, the single-ring aromatic hydrocarbons (2.6 ppbv benzene, 9.0 ppbv toluene, 

4.6 ppbv m,p-xylene) and the C4-C11 n-alkanes were similar or slightly elevated in concentration 

compared to Los Angeles. 

A study in Rio de Janeiro, Brazil some years ago measured and modeled ambient PAN 

concentrations.640 The measurements were as high as 5 ppb over a 200 day period, but typically 

495 
 

below 1 ppb, at one site; at another site, as high as 3 ppb, but again generally below 1 ppb. 

Modeling estimates were as high as 3 ppb for PAN and 1 ppb for PPN. This study concluded 

that with increased use of ethanol in fuels there would be increases in ambient PAN. 

More recent monitoring studies in Brazil measured daily maximum PAN concentrations 

ranging from 0.19 to 6.67 ppb.641 Also, PPN was measured at lower levels of 0.06 to 0.72 ppb. 

During the 41 days of these measurements, PAN levels accounted for a large fraction of the 

ambient NOx. This study concluded that aromatics and alkene compounds are responsible for 

significant PAN formation with ethanol and acetaldehyde having a minor role. 

Speciated ambient carbonyls have also been measured in Rio de Janeiro.642 The most 

abundant carbonyls were formaldehyde (9.3 ppb) and acetaldehyde (9.0 ppb). They also 

examined the ambient acetaldehyde to formaldehyde concentration ratio in Brazilian cities since 

mid-1980 in the context of changes in Brazil’s reliance on ethanol as a vehicle fuel. They 

showed that this ratio has begun to decrease in recent years due to fleet turnover and decrease in 

ethanol-fueled vehicles. Ethanol-fueled vehicles are being replaced by lower-emitting models 

that run on a gasoline-ethanol blend. 

Using an empirical kinetic modeling approach, researchers simulated ozone, 

formaldehyde, and acetaldehyde concentrations for the urban downtown area of Rio de 

Janeiro.643 The simulated ozone peak was in good agreement with monitoring results. Modeling 

results also showed that acetaldehyde and formaldehyde concentrations were highest in early 

morning, reaching a maximum which coincided with peak vehicular traffic. Additionally, they 

confirmed monitoring evidence that the high acetaldehyde to formaldehyde ratios were due to 

the use of alcohol-based fuels. 

These studies modeled and measured ambient concentrations of several compounds that 

result from the use of ethanol fuels. However, the direct impacts of ethanol fuel usage on air 

quality in Brazil could not be evaluated since there were no ambient data available prior to the 

use of ethanol fuel. 

3.3.3 Aromatics and SOA Formation 

Particulate matter (PM) is an air pollutant consisting of a complex mixture of particles 

that can be solid, liquid or both, are suspended in the air, and consist of organic and inorganic 

substances. These particles vary in size, composition and origin. The major PM components are 

sulfate, nitrates, ammonia, carbon, crustal material and water. 

Primary PM is emitted directly into the atmosphere from anthropogenic and biogenic 

processes. Primary PM includes PM from mobile sources and, on a mass basis, is largely 

carbonaceous in nature. Various studies have shown that mobile sources are a major source of 

primary PM in urban areas over many portions of the United States.644,645,646,647,648,649,650 

Primary PM that is carbonaceous is also referred to as primary organic aerosol (POA). 

Secondary PM is formed in the atmosphere from chemical transformations of gases. 

Secondary products include sulfates, nitrates and organics. Secondary organic aerosol (SOA) 

496 
results when products of atmospheric transformation or photooxidation of a volatile organic 

compound (VOC) form or partition to the particle phase. Current research suggests SOA 

contributes significantly to ambient organic aerosol (OA) concentrations, and in southeast and 

midwest states may make up more than 50% (although the contribution varies from area to area) 

of the organic fraction of PM2.5 during the summer (but less in the winter).651,652 A wide range 

of laboratory studies conducted over the past twenty years show that anthropogenic aromatic 

hydrocarbons and long-chained alkanes, along with biogenic isoprene, monoterpenes, and 

sesquiterpenes, contribute to SOA formation.653 Based on these laboratory results, SOA 

chemical mechanisms have been developed and integrated into air quality models such as the 

Community Multiscale Air Quality (CMAQ) model and have been used to predict OA 

concentrations.654 Studies have also shown that alkanes could be important anthropogenic SOA 

contributors.655,656,657,658 

Over the past 10 years, ambient OA concentrations have been routinely measured in the 

U.S. and some of these data have been used to determine, by employing source/receptor 

methods, the contributions of the major OA sources, including biomass burning and vehicular 

gasoline and diesel exhaust. Since mobile sources are a significant source of VOC emissions, 

currently accounting for approximately 50% of anthropogenic VOC,659 mobile sources are also 

an important source of SOA. 

Toluene is an important contributor to anthropogenic SOA, although anthropogenic SOA 

is a small portion of all SOA. Other aromatic compounds contribute as well, but the extent of 

their contribution has not been quantified. Mobile sources are the most significant contributor to 

ambient toluene concentrations as shown by analyses done for the 1999 National Air Toxics 

Assessment (NATA)660 and the Mobile Source Air Toxics (MSAT) Rule.661 MSAT rule 

analyses indicate that onroad and nonroad mobile sources accounted for 68% (2.22 μg/m3

) of the 

total average nationwide ambient concentration of toluene in 1999 (3.24 μg/m3

). 

The amount of toluene in gasoline influences the amount of toluene emitted in vehicle 

exhaust and evaporative emissions. In turn, levels of toluene and other aromatics in gasoline are 

potentially influenced by the amount of ethanol blended into the fuel. Due to the high octane 

quality of ethanol, it greatly reduces the need for and levels of other high-octane components 

such as aromatics including toluene (which is the major aromatic compound in gasoline) when 

ethanol is used as a component of gasoline. Since toluene contributes to SOA and the toluene 

level of gasoline is decreasing, it is important to assess the effect of these reductions on ambient 

PM. To do this, EPA plans to run air quality models to assess the overall role of toluene’s 

contribution to ambient PM and the benefits that would accrue from PM reductions associated 

with gasoline/ethanol blends having lower aromatic levels. 

There is also the potential for ethanol to directly form SOA or affect SOA formation 

indirectly through changes in the radical populations from increasing ethanol exhausts. 

However, there is a lack of evidence for both. Scientists at the U.S. EPA’s Office of Research 

and Development’s National Exposure Research Laboratory recently directed a couple of 

experiments to investigate ethanol’s SOA forming potential.662 The experiments were conducted 

under conditions where peroxy radical reactions would predominate (irradiations performed in 

the absence of NOx and OH produced from the photolysis of hydrogen peroxide). This was the 

497 
most likely scenario under which SOA formation could occur, since a highly oxygenated C4 

organic would be potentially made. As expected, no SOA was produced. From these 

experiments, the upper limit for the aerosol yield would have been less than 0.01% based on 

scanning mobility particle sizer data. Given the expected negative result, this data was not 

published. 

In general, a review of the literature shows limited data on SOA concentrations, largely 

due to the lack of analytical methods for identifying and determining the concentrations of the 

highly polar organic compounds that make up SOA. The most widely applied method of 

estimating total ambient SOA concentrations is the EC tracer method using ambient data and 

estimates of the OC/EC ratio in primary source emissions.663,664 SOA concentrations have also 

been estimated using OM (organic mass) to OC (organic carbon) ratios, which can indicate that 

SOA formation has occurred, or by subtracting the source/receptor-based total POA from the 

measured OC concentration.665 Such methods, however, may not be quantitatively accurate and 

provide no information on the contribution of individual biogenic and anthropogenic SOA 

sources, which is critical information needed to assess the impact of specific sources and the 

associated health risk. In particular, the contributions of anthropogenic SOA sources, including 

those of aromatic precursors, are required to determine exposures and risks associated with 

replacing fossil fuels with biofuels. 

Upon release into the atmosphere, numerous VOC compounds can react with free 

radicals in the atmosphere to form SOA. While this has been investigated in the laboratory, there 

is relatively little information available on the specific chemical composition of SOA compounds 

themselves from specific VOC precursors. This absence of compositional data has largely 

prevented the identification of aromatically-derived SOA in ambient samples which, in turn, has 

prevented observation-based measurements of the aromatic and other SOA contributions to 

ambient PM levels. 

As a first step in determining the ambient SOA concentrations, EPA has developed a 

tracer-based method to estimate such concentrations.666,667 The method is based on using mass 

fractions of SOA tracer compounds, measured in smog chamber-generated SOA samples, to 

convert ambient concentrations of SOA tracer compounds to ambient SOA concentrations. This 

method consists of irradiating the SOA precursor of interest in a smog chamber in the presence 

of NOx, collecting the SOA produced on filters, and then analyzing the samples for highly polar 

compounds using advanced analytical chemistry methods. Employing this method, candidate 

tracers have been identified for several VOC compounds which are emitted in significant 

quantities and known to produce SOA in the atmosphere. Some of these SOA-forming 

compounds include toluene, a variety of monoterpenes, isoprene, and β-caryophyllene; the latter 

three of which are emitted by vegetation. Smog chamber work can also be used to investigate 

SOA chemical formation mechanisms.668,669,670,671 

Although these concentrations are only estimates, due to the assumption that the mass 

fractions of the smog chamber SOA samples using these tracers are equal to those in the ambient 

atmosphere, there are presently no other means available for estimating the SOA concentrations 

originating from individual SOA precursors. Among the tracer compounds observed in ambient 

PM2.5 samples are two tracer compounds that have been identified in smog chamber aromatic 

498 
SOA samples.672 To date, these aromatic tracer compounds have been identified, in the 

laboratory, for toluene and m-xylene SOA. Additional work is underway by the EPA to 

determine whether these tracers are also formed by benzene and other alkylbenzenes (including 

o-xylene, p-xylene, 1,2,4-trimethylbenzene, and ethylbenzene). 

One caveat regarding this work is that a large number of VOCs emitted into the 

atmosphere, which have the potential to form SOA, have not yet been studied in this way. It is 

possible that these unstudied compounds produce SOA species which are being used as tracers 

for other VOCs. This means that the present work could overestimate the amount of SOA 

formed in the atmosphere by the VOCs studied to date. This approach may also estimate entire 

hydrocarbon classes (e.g. all methylsubstituted-monoaromatics or all monoterpenes) and not 

individual precursor hydrocarbons. Thus the tracers could be broadly representative and not 

indicative of individual precursors. This is still unknown. Also, anthropogenic precursors play a 

role in formation of atmospheric radicals and aerosol acidity, and these factors influence SOA 

formation from biogenic hydrocarbons. This anthropogenic and biogenic interaction, important 

to EPA and others, needs further study. The issue of SOA formation from aromatic precursors is 

an important one to which EPA and others are paying significant attention. 

For benzene, smog chamber studies show that benzene forms SOA possibly through 

reactions with NOx. Early smog chamber work suggests benzene might be relatively inert in 

forming SOA, although this study may not be conclusive.673 However, more recent work shows 

that benzene does form SOA in smog chambers.674 This new smog chamber work shows that 

benzene can be oxidized in the presence of NOx to form SOA with maximum mass of SOA 

being 8-25% of the mass of benzene. As mentioned above, work is needed to determine if a 

tracer compound can be found for benzene SOA which might indicate how much of ambient 

SOA comes from benzene. 

The aromatic tracer compounds and their mass fractions have also been used to estimate 

monthly ambient aromatic SOA concentrations from March 2004 to February 2005 in five U.S. 

Midwestern cities.675 The annual tracer-based SOA concentration estimates were 0.15, 0.18, 

0.13, 0.15, and 0.19 μg carbon/m3

 for Bondville, IL, East St. Louis, IL, Northbrook, IL, 

Cincinnati, OH and Detroit, MI, respectively, with the highest concentrations occurring in the 

summer. On average, the aromatic SOA concentrations made up 17 % of the total SOA 

concentration. Thus, this work suggests that we are finding ambient PM levels on an annual 

basis of about 0.15 μg/m3

 associated with present toluene levels in the ambient air in these 

Midwest cities. Based on preliminary analysis of recent laboratory experiments, it appears the 

toluene tracer could also be formed during photooxidation of some of the xylenes.676 

Over the past decade a variety of modeling studies have been conducted to predict 

ambient SOA levels, with most studies focusing on the contributions of biogenic monoterpenes 

and anthropogenic aromatic hydrocarbons. More recently, modelers have begun to include the 

contribution of the isoprene SOA to ambient OC concentrations.677 In general, the studies have 

been limited to comparing the sum of the POA and SOA concentrations with ambient OC 

concentrations. The general consensus in the atmospheric chemistry community appears to be 

that monoterpene contributions, which are clearly significant, and the somewhat smaller 

aromatic contributions, are insufficient to account for observed ambient SOA levels. Part of this 

499 
gap has been filled recently by SOA predictions for isoprene. Furthermore, the identification in 

ambient SOA of a tracer compound for the sesquiterpene β-caryophyllene,678 coupled with the 

high sesquiterpene SOA yields measured in the laboratory,679 suggests this class of hydrocarbons 

should be included in SOA chemical mechanisms. In addition, recent data on SOA formation 

from aromatic hydrocarbons suggest their contributions could be larger than previously 

thought.680 

Based on laboratory experiments, researchers have proposed a new aromatic SOA 

chemical mechanism that takes into account both the impact of NOx on SOA formation and the 

contribution of benzene to SOA formation. EPA has updated the SOA treatment in CMAQ by 

using this new mechanism, along with (1) laboratory-determined thermodynamic enthalpies of 

vaporization and SOA-to-secondary organic carbon ratios, (2) SOA contributions from 

sesquiterpenes and isoprene, (3) an elementary treatment of acid catalyzed SOA from isoprene, 

(4) a simple treatment of SOA oligomerization, and (5) SOA contributions from dicarbonyl 

compounds (glyoxyl, methylglyoxyl) that dissolve in cloud water and are oxidized to form 

oligomers. 

This new SOA mechanism was first evaluated by comparing simple box model 

predictions with field measurements, and initial comparisons indicated the mechanism might 

underpredict the ambient SOA data. This underprediction might be due to potential 

shortcomings in the tracer contribution method as well as difficulties associated with using the 

laboratory-based Odum model approach to predict ambient SOA concentrations. An 

underprediction in ambient SOA data might result in an underprediction of SOA benefits that 

might result from decreasing aromatic content due to increasing ethanol content in gasoline. On 

the other hand, aldehydes produced from the oxidation of ethanol could increase the SOA 

formed in cloud water, but only two aldehydes (glyoxal and methylglyoxal) are considered in the 

current SOA treatment. More fundamental research will be required to further enhance the SOA 

mechanism. Recently, the EPA awarded seven grants totaling $3.8 million to leading SOA 

researchers for additional mechanistic research. 

The new SOA mechanism has been integrated into CMAQ version 4.7 and has undergone 

internal EPA evaluation. The SOA predictions have been compared with ambient OC 

concentrations measured at PM2.5 monitoring sites across the country, CMAQ version 4.7 with 

the new SOA chemical mechanism will be used in the final rule. Public release of this version of 

the model occurred in December 2008. 

3.4 Health Effects 

In this section we will discuss the health and environmental effects associated with 

particulate matter, ozone, carbon monoxide and air toxics. The renewable fuel requirements 

established by the Energy Independence and Security Act (EISA) of 2007 will impact emissions 

of criteria and air toxic pollutants. 

3.4.1 Health Effects of Particulate Matter 

500 
 

 

As stated in EPA’s Particulate Matter Air Quality Criteria Document (PM AQCD), 

available scientific findings “demonstrate well that human health outcomes are associated with 

ambient PM.”VVVVVVVV We are relying on the data and conclusions in the PM AQCD and PM 

Staff Paper, which reflects EPA’s analysis of policy-relevant science from the PM AQCD, 

regarding the health effects associated with particulate matter.681,682 We also present additional 

recent studies published after the cut-off date for the PM AQCD.WWWWWWWW683 Taken together 

this information supports the conclusion that PM-related emissions are associated with adverse 

health effects. 

3.4.1.1 Short-term Exposure Mortality and Morbidity Studies 

As discussed in the PM AQCD, short-term exposure to PM2.5 is associated with mortality 

from cardiopulmonary diseases (PM AQCD, p. 8-305), hospitalization and emergency 

department visits for cardiopulmonary diseases (PM AQCD, p. 9-93), increased respiratory 

symptoms (PM AQCD, p. 9-46), decreased lung function (PM AQCD Table 8-34) and 

physiological changes or biomarkers for cardiac changes (PM AQCD, Section 8.3.1.3.4). In 

addition, the PM AQCD describes a limited body of new evidence from epidemiologic studies 

for potential relationships between short term exposure to PM and health endpoints such as low 

birth weight, preterm birth, and neonatal and infant mortality. (PM AQCD, Section 8.3.4). 

Among the studies of effects from short-term exposure to PM2.5, several specifically 

address the contribution of mobile sources to short-term PM2.5 effects on daily mortality. These 

studies indicate that there are statistically significant associations between mortality and PM 

related to mobile source emissions (PM AQCD, p.8-85). The analyses incorporate source 

apportionment tools into daily mortality studies and are briefly mentioned here. Analyses 

incorporating source apportionment by factor analysis with daily time-series studies of daily 

death indicated a relationship between mobile source PM2.5 and mortality.684,685 Another recent 

study in 14 U.S. cities examined the effect of PM10 exposures on daily hospital admissions for 

cardiovascular disease. This study found that the effect of PM10 was significantly greater in 

areas with a larger proportion of PM10 coming from motor vehicles, indicating that PM10 from 

these sources may have a greater effect on the toxicity of ambient PM10 when compared with 

other sources.686 These studies provide evidence that PM-related emissions, specifically from 

mobile sources, are associated with adverse health effects. 

3.4.1.2 Long-term Exposure Mortality and Morbidity Studies 

VVVVVVVV Personal exposure includes contributions from many different types of particles, from many sources, and 

in many different environments. Total personal exposure to PM includes both ambient and nonambient 

components; and both components may contribute to adverse health effects. 

WWWWWWWW These additional studies are included in the 2006 Provisional Assessment of Recent Studies on Health 

Effects of Particulate Matter Exposure. The provisional assessment did not and could not (given a very short 

timeframe) undergo the extensive critical review by EPA, CASAC, and the public, as did the PM AQCD. The 

provisional assessment found that the “new” studies expand the scientific information and provide important 

insights on the relationship between PM exposure and health effects of PM. The provisional assessment also found 

that “new” studies generally strengthen the evidence that acute and chronic exposure to fine particles and acute 

exposure to thoracic coarse particles are associated with health effects. 

501 
Long-term exposure to elevated ambient PM2.5 is associated with mortality from 

cardiopulmonary diseases and lung cancer (PM AQCD, p. 8-307), and effects on the respiratory 

system such as decreased lung function or the development of chronic respiratory disease (PM 

AQCD, pp. 8-313, 8-314). Of specific importance to this proposal, the PM AQCD also notes 

that the PM components of gasoline and diesel engine exhaust represent one class of 

hypothesized likely important contributors to the observed ambient PM-related increases in lung 

cancer incidence and mortality (PM AQCD, p. 8-318). 

The PM AQCD and PM Staff Paper emphasize the results of two long-term studies, the 

Six Cities and American Cancer Society (ACS) prospective cohort studies, based on several 

factors – the inclusion of measured PM data, the fact that the study populations were similar to 

the general population, and the fact that these studies have undergone extensive reanalysis (PM 

AQCD, p. 8-306, Staff Paper, p.3-18).687,688,689 These studies indicate that there are significant 

associations for all-cause, cardiopulmonary, and lung cancer mortality with long-term exposure 

to PM2.5. One analysis of a subset of the ACS cohort data, which was published after the PM 

AQCD was finalized but in time for the 2006 Provisional Assessment, found a larger association 

than had previously been reported between long-term PM2.5 exposure and mortality in the Los 

Angeles area using a new exposure estimation method that accounted for variations in 

concentration within the city.690 

As discussed in the PM AQCD, the morbidity studies that combine the features of crosssectional and cohort studies provide the best evidence for chronic exposure effects. Long-term 

studies evaluating the effect of ambient PM on children’s development have shown some 

evidence indicating effects of PM2.5 and/or PM10 on reduced lung function growth (PM AQCD, 

Section 8.3.3.2.3). In another recent publication included in the 2006 Provisional Assessment, 

investigators in southern California reported the results of a cross-sectional study of outdoor 

PM2.5 and measures of atherosclerosis in the Los Angeles basin.691 The study found significant 

associations between ambient residential PM2.5 and carotid intima-media thickness (CIMT), an 

indicator of subclinical atherosclerosis, an underlying factor in cardiovascular disease. 

3.4.1.3 Roadway-Related PM Exposure and Health Studies 

A recent body of studies examines traffic-related PM exposures and adverse health 

effects. However, note that the near-road environment is influenced by both gasoline sparkignition (SI) and diesel vehicles, as well as re-entrained road dust and brake and tire wear. One 

study was done in North Carolina looking at concentrations of PM2.5 inside police cars and 

corresponding physiological changes in the police personnel driving the cars. The authors report 

significant elevations in markers of cardiac risk associated with concentrations of PM2.5 inside 

police cars on North Carolina state highways.692 Other studies have found associations between 

traffic-generated particle concentrations at residences and adverse effects, including all-cause 

mortality, infant respiratory symptoms, and reduced cognitive functional 

development.693,694,695,696 There are other pollutants present in the near roadway environment, 

including air toxics which are discussed in Section 3.4.5, and it is important to note that current 

studies do not identify a single pollutant that is most associated with adverse health effects. 

Additional information on near-roadway health effects can be found in the recent Mobile Source 

Air Toxics rule (72 FR 8428, February 26, 2007). 

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3.4.2 Health Effects of Ozone 

Exposure to ambient ozone contributes to a wide range of adverse health 

effects.XXXXXXXX These health effects are well documented and are critically assessed in the 

EPA ozone air quality criteria document (ozone AQCD) and EPA staff paper.697,698 We are 

relying on the data and conclusions in the ozone AQCD and staff paper, regarding the health 

effects associated with ozone exposure. 

Ozone-related health effects include lung function decrements, respiratory symptoms, 

aggravation of asthma, increased hospital and emergency room visits, increased asthma 

medication usage, and a variety of other respiratory effects. Cellular-level effects, such as 

inflammation of lungs, have been documented as well. In addition, there is suggestive evidence 

of a contribution of ozone to cardiovascular-related morbidity and highly suggestive evidence 

that short-term ozone exposure directly or indirectly contributes to non-accidental and 

cardiopulmonary-related mortality, but additional research is needed to clarify the underlying 

mechanisms causing these effects. In a recent report on the estimation of ozone-related 

premature mortality published by the National Research Council (NRC), a panel of experts and 

reviewers concluded that short-term exposure to ambient ozone is likely to contribute to 

premature deaths and that ozone-related mortality should be included in estimates of the health 

benefits of reducing ozone exposure.699 People who appear to be more susceptible to effects 

associated with exposure to ozone include children, asthmatics and the elderly. Those with 

greater exposures to ozone, for instance due to time spent outdoors (e.g., children and outdoor 

workers), are also of concern. 

Based on a large number of scientific studies, EPA has identified several key health 

effects associated with exposure to levels of ozone found today in many areas of the country. 

Short-term (1 to 3 hours) and prolonged exposures (6 to 8 hours) to ambient ozone 

concentrations have been linked to lung function decrements, respiratory symptoms, increased 

hospital admissions and emergency room visits for respiratory problems.700, 701, 702, 703, 704, 705 

Repeated exposure to ozone can increase susceptibility to respiratory infection and lung 

inflammation and can aggravate preexisting respiratory diseases, such as asthma.706, 707, 708, 709, 710 

Repeated exposure to sufficient concentrations of ozone can also cause inflammation of the lung, 

impairment of lung defense mechanisms, and possibly irreversible changes in lung structure, 

which over time could affect premature aging of the lungs and/or the development of chronic 

respiratory illnesses, such as emphysema and chronic bronchitis.711, 712, 713, 714 

Children and adults who are outdoors and active during the summer months, such as 

construction workers, are among those most at risk of elevated ozone exposures.715 Children and 

outdoor workers tend to have higher ozone exposure because they typically are active outside, 

working, playing and exercising, during times of day and seasons (e.g., the summer) when ozone 

levels are highest.716 For example, summer camp studies in the Eastern United States and 

Southeastern Canada have reported statistically significant reductions in lung function in 

XXXXXXXX Human exposure to ozone varies over time due to changes in ambient ozone concentration and because 

people move between locations which have notable different ozone concentrations. Also, the amount of ozone 

delivered to the lung is not only influenced by the ambient concentrations but also by the individuals breathing route 

and rate. 

503 
 

 

 

 

children who are active outdoors.717, 718, 719, 720, 721, 722, 723, 724 Further, children are more at risk of 

experiencing health effects from ozone exposure than adults because their respiratory systems 

are still developing. These individuals (as well as people with respiratory illnesses, such as 

asthma, especially asthmatic children) can experience reduced lung function and increased 

respiratory symptoms, such as chest pain and cough, when exposed to relatively low ozone levels 

during prolonged periods of moderate exertion.725, 726, 727, 728 

3.4.3 Health Effects of Carbon Monoxide 

We are relying on the data and conclusions in the EPA Air Quality Criteria Document for 

CO (CO Criteria Document), which was published in 2000, regarding the health effects 

associated with CO exposure.YYYYYYYY729 Carbon monoxide enters the bloodstream through the 

lungs and forms carboxyhemoglobin (COHb), a compound that inhibits the blood’s capacity to 

carry oxygen to organs and tissues.730,731 Carbon monoxide has long been known to have 

substantial adverse effects on human health, including toxic effects on blood and tissues, and 

effects on organ functions. Although there are effective compensatory increases in blood flow to 

the brain, at some concentrations of COHb somewhere above 20 percent, these compensations 

fail to maintain sufficient oxygen delivery, and metabolism declines.732 The subsequent hypoxia 

in brain tissue then produces behavioral effects, including decrements in continuous performance 

and reaction time.733 

Carbon monoxide has been linked to increased risk for people with heart disease, reduced 

visual perception, cognitive functions and aerobic capacity, and possible fetal effects.734 Persons 

with heart disease are especially sensitive to CO poisoning and may experience chest pain if they 

breathe the gas while exercising.735 Infants, elderly persons, and individuals with respiratory 

diseases are also particularly sensitive. Carbon monoxide can affect healthy individuals, 

impairing exercise capacity, visual perception, manual dexterity, learning functions, and ability 

to perform complex tasks.736 

Several epidemiological studies have shown a link between CO and premature morbidity 

(including angina, congestive heart failure, and other cardiovascular diseases). Several studies in 

the United States and Canada have also reported an association between ambient CO exposures 

and frequency of cardiovascular hospital admissions, especially for congestive heart failure 

(CHF). An association between ambient CO exposure and mortality has also been reported in 

epidemiological studies, though not as consistently or specifically as with CHF admissions. EPA 

reviewed these studies as part of the CO Criteria Document review process and noted the 

possibility that the average ambient CO levels used as exposure indices in the epidemiology 

studies may be surrogates for ambient air mixes impacted by combustion sources and/or other 

constituent toxic components of such mixes. More research will be needed to better clarify CO’s 

role.737 

3.4.4 Environmental Effects of Criteria Pollutants 

YYYYYYYY The NAAQS review process is underway for CO and the CO Integrated Science 

Assessment is scheduled to be completed in January 2010. 

504 
In this section we discuss some of the environmental effects of PM and its precursors 

such as visibility impairment, atmospheric deposition, and materials damage and soiling, as well 

as environmental effects associated with the presence of ozone in the ambient air, such as 

impacts on plants, including trees, agronomic crops and urban ornamentals. 

3.4.4.1 Visibility Impairment 

Visibility can be defined as the degree to which the atmosphere is transparent to visible 

light.738 Visibility impairment manifests in two principal ways: as local visibility impairment 

and as regional haze.739 Local visibility impairment may take the form of a localized plume, a 

band or layer of discoloration appearing well above the terrain as a result of complex local 

meteorological conditions. Alternatively, local visibility impairment may manifest as an urban 

haze, sometimes referred to as a “brown cloud.” This urban haze is largely caused by emissions 

from multiple sources in the urban area and is not typically attributable to only one nearby source 

or to long-range transport. The second type of visibility impairment, regional haze, usually 

results from multiple pollution sources spread over a large geographic region. Regional haze can 

impair visibility over large regions and across states. 

Visibility is important because it has direct significance to people’s enjoyment of daily 

activities in all parts of the country. Individuals value good visibility for the well-being it 

provides them directly, where they live and work and in places where they enjoy recreational 

opportunities. Visibility is also highly valued in significant natural areas such as national parks 

and wilderness areas, and special emphasis is given to protecting visibility in these areas. 

Fine particles are the major cause of reduced visibility in parts of the United States. To 

address the welfare effects of PM on visibility, EPA sets secondary PM2.5 standards which work 

in conjunction with the regional haze program. The secondary (welfare-based) PM2.5 NAAQS is 

equal to the suite of primary (health-based) PM2.5 NAAQS. The regional haze rule (64 FR 

35714, July 1999) was put in place to protect the visibility in mandatory class I federal areas. 

These areas are defined in Section 162 of the Act as those national parks exceeding 6,000 acres, 

wilderness areas and memorial parks exceeding 5,000 acres, and all international parks which 

were in existence on August 7, 1977. Visibility is impaired in both PM2.5 nonattainment areas 

and mandatory class I federal areas. 

3.4.4.2 Particulate Matter Deposition 

Particulate matter contributes to adverse effects on vegetation and ecosystems, and to 

soiling and materials damage. These welfare effects result predominately from exposure to 

excess amounts of specific chemical species, regardless of their source or predominant form 

(particle, gas or liquid). Reflecting this fact, the PM AQCD concludes that regardless of size 

fractions, particles containing nitrates and sulfates have the greatest potential for widespread 

environmental significance, while effects are also related to other chemical constituents found in 

ambient PM, such as trace metals and organics. The following characterizations of the nature of 

these welfare effects are based on the information contained in the PM AQCD and PM Staff 

Paper.740,741 

505 
 

3.4.4.2.1 Deposition of Nitrates and Sulfates 

Nitrogen and sulfur interactions in the environment are highly complex. Both are 

essential, and sometimes limiting, nutrients needed for growth and productivity. Excesses of 

nitrogen or sulfur can lead to acidification, nutrient enrichment, and eutrophication.742 

The process of acidification affects both freshwater aquatic and terrestrial ecosystems. 

Acid deposition causes acidification of sensitive surface waters. The effects of acid deposition on 

aquatic systems depend largely upon the ability of the ecosystem to neutralize the additional 

acid. As acidity increases, aluminum leached from soils and sediments, flows into lakes and 

streams and can be toxic to both terrestrial and aquatic biota. The lower pH concentrations and 

higher aluminum levels resulting from acidification make it difficult for some fish and other 

aquatic organisms to survive, grow, and reproduce. Research on effects of acid deposition on 

forest ecosystems has come to focus increasingly on the biogeochemical processes that affect 

uptake, retention, and cycling of nutrients within these ecosystems. Decreases in available base 

cations from soils are at least partly attributable to acid deposition. Base cation depletion is a 

cause for concern because of the role these ions play in acid neutralization and, because calcium, 

magnesium and potassium are essential nutrients for plant growth and physiology. Changes in 

the relative proportions of these nutrients, especially in comparison with aluminum 

concentrations, have been associated with declining forest health. 

At current ambient levels, risks to vegetation from short-term exposures to dry deposited 

particulate nitrate or sulfate are low. However, when found in acid or acidifying deposition, such 

particles do have the potential to cause direct leaf injury. Specifically, the responses of forest 

trees to acid precipitation (rain, snow) include accelerated weathering of leaf cuticular surfaces, 

increased permeability of leaf surfaces to toxic materials, water, and disease agents; increased 

leaching of nutrients from foliage; and altered reproductive processes—all which serve to 

weaken trees so that they are more susceptible to other stresses (e.g., extreme weather, pests, 

pathogens). Acid deposition with levels of acidity associated with the leaf effects described 

above are currently found in some locations in the eastern U.S.743 Even higher concentrations of 

acidity can be present in occult depositions (e.g., fog, mist or clouds) which more frequently 

impacts higher elevations. Thus, the risk of leaf injury occurring from acid deposition in some 

areas of the eastern U.S. is high. Nitrogen deposition has also been shown to impact ecosystems 

in the western U.S. A study conducted in the Columbia River Gorge National Scenic Area 

(CRGNSA), located along a portion of the Oregon/Washington border, indicates that lichen 

communities in the CRGNSA have shifted to a higher proportion of nitrophilous species and the 

nitrogen content of lichen tissue is elevated.744 Lichens are sensitive indicators of nitrogen 

deposition effects to terrestrial ecosystems and the lichen studies in the Columbia River Gorge 

clearly show that ecological effects from air pollution are occurring. 

Some of the most significant detrimental effects associated with excess reactive nitrogen 

deposition are those associated with a syndrome known as nitrogen saturation. These effects 

include: (1) decreased productivity, increased mortality, and/or shifts in plant community 

composition, often leading to decreased biodiversity in many natural habitats wherever 

atmospheric reactive nitrogen deposition increases significantly above background and critical 

thresholds are exceeded; (2) leaching of excess nitrate and associated base cations from soils into 

506 
streams, lakes, and rivers, and mobilization of soil aluminum; and (3) fluctuation of ecosystem 

processes such as nutrient and energy cycles through changes in the functioning and species 

composition of beneficial soil organisms.745 

In the U.S. numerous forests now show severe symptoms of nitrogen saturation. These 

forests include: the northern hardwoods and mixed conifer forests in the Adirondack and 

Catskill Mountains of New York; the red spruce forests at Whitetop Mountain, Virginia, and 

Great Smoky Mountains National Park, North Carolina; mixed hardwood watersheds at Fernow 

Experimental Forest in West Virginia; American beech forests in Great Smoky Mountains 

National Park, Tennessee; mixed conifer forests and chaparral watersheds in southern California 

and the southwestern Sierra Nevada in Central California; the alpine tundra/subalpine conifer 

forests of the Colorado Front Range; and red alder forests in the Cascade Mountains in 

Washington. 

Excess nutrient inputs into aquatic ecosystems (i.e. streams, rivers, lakes, estuaries or 

oceans) either from direct atmospheric deposition, surface runoff, or leaching from nitrogen 

saturated soils into ground or surface waters can contribute to conditions of severe water oxygen 

depletion; eutrophication and algae blooms; altered fish distributions, catches, and physiological 

states; loss of biodiversity; habitat degradation; and increases in the incidence of disease. 

Atmospheric deposition of nitrogen is a significant source of total nitrogen to many 

estuaries in the United States. The amount of nitrogen entering estuaries that is ultimately 

attributable to atmospheric deposition is not well-defined. On an annual basis, atmospheric 

nitrogen deposition may contribute significantly to the total nitrogen load, depending on the size 

and location of the watershed. In addition, episodic nitrogen inputs, which may be ecologically 

important, may play a more important role than indicated by the annual average concentrations. 

Estuaries in the U.S. that suffer from nitrogen enrichment often experience a condition known as 

eutrophication. Symptoms of eutrophication include changes in the dominant species of 

phytoplankton, low levels of oxygen in the water column, fish and shellfish kills, outbreaks of 

toxic alga, and other population changes which can cascade throughout the food web. In 

addition, increased phytoplankton growth in the water column and on surfaces can attenuate light 

causing declines in submerged aquatic vegetation, which serves as an important habitat for many 

estuarine fish and shellfish species. 

Severe and persistent eutrophication often directly impacts human activities. For 

example, losses in the nation’s fishery resources may be directly caused by fish kills associated 

with low dissolved oxygen and toxic blooms. Declines in tourism occur when low dissolved 

oxygen causes noxious smells and floating mats of algal blooms create unfavorable aesthetic 

conditions. Risks to human health increase when the toxins from algal blooms accumulate in 

edible fish and shellfish, and when toxins become airborne, causing respiratory problems due to 

inhalation. According to a NOAA report, more than half of the nation’s estuaries have moderate 

to high expressions of at least one of these symptoms – an indication that eutrophication is well 

developed in more than half of U.S. estuaries.746 

3.4.4.2.2 Materials Damage and Soiling 

507 
The effects of the deposition of atmospheric pollution, including ambient PM, on 

materials are related to both physical damage and impaired aesthetic qualities. The deposition of 

PM (especially sulfates and nitrates) can physically affect materials, adding to the effects of 

natural weathering processes, by potentially promoting or accelerating the corrosion of metals, 

by degrading paints, and by deteriorating building materials such as concrete and limestone. 

Only chemically active fine particles or hygroscopic coarse particles contribute to these physical 

effects. In addition, the deposition of ambient PM can reduce the aesthetic appeal of buildings 

and culturally important articles through soiling. Particles consisting primarily of carbonaceous 

compounds cause soiling of commonly used building materials and culturally important items 

such as statues and works of art. 

3.4.4.3 Impacts of Ozone on Vegetation 

The Air Quality Criteria Document for Ozone and related Photochemical Oxidants notes 

that “ozone affects vegetation throughout the United States, impairing crops, native vegetation, 

and ecosystems more than any other air pollutant. Like carbon dioxide (CO2) and other gaseous 

substances, ozone enters plant tissues primarily through apertures (stomata) in leaves in a process 

called “uptake”.747 Once sufficient levels of ozone, a highly reactive substance, (or its reaction 

products) reaches the interior of plant cells, it can inhibit or damage essential cellular 

components and functions, including enzyme activities, lipids, and cellular membranes, 

disrupting the plant's osmotic (i.e., water) balance and energy utilization patterns.748,749 This 

damage is commonly manifested as visible foliar injury, such as chlorotic or necrotic spots, 

increased leaf senescence (accelerated leaf aging) and/or reduced photosynthesis. All these 

effects reduce a plant’s capacity to form carbohydrates, which are the primary form of energy 

used by plants.750 With fewer resources available, the plant reallocates existing resources away 

from root growth and storage, above ground growth or yield, and reproductive processes, toward 

leaf repair and maintenance. Studies have shown that plants stressed in these ways may exhibit a 

general loss of vigor, which can lead to secondary impacts that modify plants' responses to other 

environmental factors. Specifically, plants may become more sensitive to other air pollutants, 

more susceptible to disease, insect attack, harsh weather (e.g., drought, frost) and other 

environmental stresses. Furthermore, there is evidence that ozone can interfere with the 

formation of mycorrhiza, essential symbiotic fungi associated with the roots of most terrestrial 

plants, by reducing the amount of carbon available for transfer from the host to the 

symbiont.751,752 

Ozone can produce both acute and chronic injury in sensitive species depending on the 

concentration level and the duration of the exposure. Ozone effects also tend to accumulate over 

the growing season of the plant, so that even lower concentrations experienced for a longer 

duration have the potential to create chronic stress on sensitive vegetation. Not all plants, 

however, are equally sensitive to ozone. Much of the variation in sensitivity between individual 

plants or whole species is related to the plant’s ability to regulate the extent of gas exchange via 

leaf stomata (e.g., avoidance of O3 uptake through closure of stomata).753,754,755 Other resistance 

mechanisms may involve the intercellular production of detoxifying substances. Several 

biochemical substances capable of detoxifying ozone have been reported to occur in plants 

including the antioxidants ascorbate and glutathione. After injuries have occurred, plants may be 

capable of repairing the damage to a limited extent.756 

508 
 

 

Because of the differing sensitivities among plants to ozone, ozone pollution can also 

exert a selective pressure that leads to changes in plant community composition. Given the range 

of plant sensitivities and the fact that numerous other environmental factors modify plant uptake 

and response to ozone, it is not possible to identify threshold values above which ozone is 

consistently toxic for all plants. The next few paragraphs present additional information on 

ozone damage to trees, ecosystems, agronomic crops and urban ornamentals. 

Ozone also has been conclusively shown to cause discernible injury to forest trees.757,758 

In terms of forest productivity and ecosystem diversity, ozone may be the pollutant with the 

greatest potential for regional-scale forest impacts. Studies have demonstrated repeatedly that 

ozone concentrations commonly observed in polluted areas can have substantial impacts on plant 

function.759,760 

Because plants are at the center of the food web in many ecosystems, changes to the plant 

community can affect associated organisms and ecosystems (including the suitability of habitats 

that support threatened or endangered species and below ground organisms living in the root 

zone). Ozone impacts at the community and ecosystem level vary widely depending upon 

numerous factors, including concentration and temporal variation of tropospheric ozone, species 

composition, soil properties and climatic factors.761 In most instances, responses to chronic or 

recurrent exposure in forested ecosystems are subtle and not observable for many years. These 

injuries can cause stand-level forest decline in sensitive ecosystems.762,763,764 It is not yet 

possible to predict ecosystem responses to ozone with much certainty; however, considerable 

knowledge of potential ecosystem responses has been acquired through long-term observations 

in highly damaged forests in the United States. 

Laboratory and field experiments have also shown reductions in yields for agronomic 

crops exposed to ozone, including vegetables (e.g., lettuce) and field crops (e.g., cotton and 

wheat). The most extensive field experiments, conducted under the National Crop Loss 

Assessment Network (NCLAN) examined 15 species and numerous cultivars. The NCLAN 

results show that “several economically important crop species are sensitive to ozone levels 

typical of those found in the Unites States.”765 In addition, economic studies have shown 

reduced economic benefits as a result of predicted reductions in crop yields associated with 

observed ozone levels.766,767,768 

Urban ornamentals represent an additional vegetation category likely to experience some 

degree of negative effects associated with exposure to ambient ozone levels. It is estimated that 

more than $20 billion (1990 dollars) are spent annually on landscaping using ornamentals, both 

by private property owners/tenants and by governmental units responsible for public areas.769 

This is therefore a potentially costly environmental effect. However, in the absence of adequate 

exposure-response functions and economic damage functions for the potential range of effects 

relevant to these types of vegetation, no direct quantitative analysis has been conducted. 

3.4.5 Health Effects of Air Toxics 

Motor vehicle emissions contribute to ambient levels of air toxics known or suspected as 

human or animal carcinogens, or that have noncancer health effects. The population experiences 

509 
 

 

 

 

 

an elevated risk of cancer and other noncancer health effects from exposure to air toxics. 770 

These compounds include, but are not limited to, benzene, 1,3-butadiene, formaldehyde, 

acetaldehyde, acrolein, naphthalene, ethanol and PAN. These compounds, except acetaldehyde, 

ethanol and PAN, were identified as national or regional risk drivers in the 1999 National-Scale 

Air Toxics Assessment (NATA) and have significant inventory contributions from mobile 

sources. 

According to NATA for 1999, mobile sources were responsible for 44 percent of outdoor 

toxic emissions and almost 50 percent of the cancer risk. Benzene is the largest contributor to 

cancer risk of all 133 pollutants quantitatively assessed in the 1999 NATA and mobile sources 

were responsible for 68 percent of benzene emissions in 1999. In response, EPA has recently 

finalized vehicle and fuel controls that address this public health risk.771 

Noncancer health effects can result from chronic,ZZZZZZZZ subchronic,AAAAAAAAA or 

acuteBBBBBBBBB inhalation exposures to air toxics, and include neurological, cardiovascular, liver, 

kidney, and respiratory effects as well as effects on the immune and reproductive systems. 

According to the 1999 NATA, nearly the entire U.S. population was exposed to an average 

concentration of air toxics that has the potential for adverse noncancer respiratory health effects. 

This will continue to be the case in 2030, even though toxics concentrations will be lower. 

Mobile sources were responsible for 74 percent of the noncancer (respiratory) risk from outdoor 

air toxics in 1999. The majority of this risk was from exposure to acrolein. The confidence in 

the RfC for acrolein is medium and confidence in NATA estimates of population noncancer 

hazard from ambient exposure to this pollutant is low.772,773 

The NATA modeling framework has a number of limitations which prevent its use as the 

sole basis for setting regulatory standards. These limitations and uncertainties are discussed on 

the 1999 NATA website.774 Even so, this modeling framework is very useful in identifying air 

toxic pollutants and sources of greatest concern, setting regulatory priorities, and informing the 

decision making process. 

Benzene: The EPA’s IRIS database lists benzene as a known human carcinogen (causing 

leukemia) by all routes of exposure, and concludes that exposure is associated with additional 

health effects, including genetic changes in both humans and animals and increased proliferation 

of bone marrow cells in mice.775,776,777 EPA states in its IRIS database that data indicate a causal 

relationship between benzene exposure and acute lymphocytic leukemia and suggest a 

relationship between benzene exposure and chronic non-lymphocytic leukemia and chronic 

lymphocytic leukemia. The International Agency for Research on Carcinogens (IARC) has 

determined that benzene is a human carcinogen and the U.S. Department of Health and Human 

Services (DHHS) has characterized benzene as a known human carcinogen.778,779 

ZZZZZZZZ Chronic exposure is defined in the glossary of the Integrated Risk Information (IRIS) database 

(http://www.epa.gov/iris) as repeated exposure by the oral, dermal, or inhalation route for more than approximately 

10% of the life span in humans (more than approximately 90 days to 2 years in typically used laboratory animal 

species).

AAAAAAAAA Defined in the IRIS database as exposure to a substance spanning approximately 10% of the lifetime of 

an organism. 

BBBBBBBBB Defined in the IRIS database as exposure by the oral, dermal, or inhalation route for 24 hours or less. 

510 
A number of adverse noncancer health effects including blood disorders, such as 

preleukemia and aplastic anemia, have also been associated with long-term exposure to 

benzene.780,781 The most sensitive noncancer effect observed in humans, based on current data, 

is the depression of the absolute lymphocyte count in blood.782,783 In addition, recent work, 

including studies sponsored by the Health Effects Institute (HEI), provides evidence that 

biochemical responses are occurring at lower levels of benzene exposure than previously 

known.784,785,786,787 EPA’s IRIS program has not yet evaluated these new data. 

1,3-Butadiene: EPA has characterized 1,3-butadiene as carcinogenic to humans by 

inhalation.788,789 The IARC has determined that 1,3-butadiene is a human carcinogen and the 

U.S. DHHS has characterized 1,3-butadiene as a known human carcinogen.790,791 There are 

numerous studies consistently demonstrating that 1,3-butadiene is metabolized into genotoxic 

metabolites by experimental animals and humans. The specific mechanisms of 1,3-butadieneinduced carcinogenesis are unknown; however, the scientific evidence strongly suggests that the 

carcinogenic effects are mediated by genotoxic metabolites. Animal data suggest that females 

may be more sensitive than males for cancer effects associated with 1,3-butadiene exposure; 

there are insufficient data in humans from which to draw conclusions about sensitive 

subpopulations. 1,3-butadiene also causes a variety of reproductive and developmental effects in 

mice; no human data on these effects are available. The most sensitive effect was ovarian 

atrophy observed in a lifetime bioassay of female mice.792 

Formaldehyde: Since 1987, EPA has classified formaldehyde as a probable human 

carcinogen based on evidence in humans and in rats, mice, hamsters, and monkeys.793 EPA is 

currently reviewing recently published epidemiological data. For instance, research conducted 

by the National Cancer Institute (NCI) found an increased risk of nasopharyngeal cancer and 

lymphohematopoietic malignancies such as leukemia among workers exposed to 

formaldehyde.794,795 NCI is currently performing an update of these studies. A recent National 

Institute of Occupational Safety and Health (NIOSH) study of garment workers also found 

increased risk of death due to leukemia among workers exposed to formaldehyde.796 Extended 

follow-up of a cohort of British chemical workers did not find evidence of an increase in 

nasopharyngeal or lymphohematopoietic cancers, but a continuing statistically significant excess 

in lung cancers was reported.797 

In the past 15 years there has been substantial research on the inhalation dosimetry for 

formaldehyde in rodents and primates by the CIIT Centers for Health Research (formerly the 

Chemical Industry Institute of Toxicology), with a focus on use of rodent data for refinement of 

the quantitative cancer dose-response assessment.798,799,800 CIIT’s risk assessment of 

formaldehyde incorporated mechanistic and dosimetric information on formaldehyde. 

Based on the developments of the last decade, in 2004, the working group of the IARC 

concluded that formaldehyde is carcinogenic to humans (Group 1), on the basis of sufficient 

evidence in humans and sufficient evidence in experimental animals - a higher classification than 

previous IARC evaluations. After reviewing the currently available epidemiological evidence, 

the IARC (2006) characterized the human evidence for formaldehyde carcinogenicity as 

“sufficient,” based upon the data on nasopharyngeal cancers; the epidemiologic evidence on 

leukemia was characterized as “strong.”801 EPA is reviewing the recent work cited above from 

511 
 

the NCI and NIOSH, as well as the analysis by the CIIT Centers for Health Research and other 

studies, as part of a reassessment of the human hazard and dose-response associated with 

formaldehyde. 

Formaldehyde exposure also causes a range of noncancer health effects, including 

irritation of the eyes (burning and watering of the eyes), nose and throat. Effects from repeated 

exposure in humans include respiratory tract irritation, chronic bronchitis and nasal epithelial 

lesions such as metaplasia and loss of cilia. Animal studies suggest that formaldehyde may also 

cause airway inflammation – including eosinophil infiltration into the airways. There are several 

studies that suggest that formaldehyde may increase the risk of asthma – particularly in the 

802,803 young.

Acetaldehyde: Acetaldehyde is classified in EPA’s IRIS database as a probable human 

carcinogen, based on nasal tumors in rats, and is considered toxic by the inhalation, oral, and 

intravenous routes.804 Acetaldehyde is reasonably anticipated to be a human carcinogen by the 

U.S. DHHS in the 11th Report on Carcinogens and is classified as possibly carcinogenic to 

humans (Group 2B) by the IARC.805,806 EPA is currently conducting a reassessment of cancer 

risk from inhalation exposure to acetaldehyde. 

The primary noncancer effects of exposure to acetaldehyde vapors include irritation of 

the eyes, skin, and respiratory tract.807 In short-term (4 week) rat studies, degeneration of 

olfactory epithelium was observed at various concentration levels of acetaldehyde 

808,809 exposure. Data from these studies were used by EPA to develop an inhalation reference 

concentration. Some asthmatics have been shown to be a sensitive subpopulation to decrements 

in functional expiratory volume (FEV1 test) and bronchoconstriction upon acetaldehyde 

inhalation.810 The agency is currently conducting a reassessment of the health hazards from 

inhalation exposure to acetaldehyde. 

Acrolein: EPA determined in 2003 that the human carcinogenic potential of acrolein 

could not be determined because the available data were inadequate. No information was 

available on the carcinogenic effects of acrolein in humans and the animal data provided 

inadequate evidence of carcinogenicity.811 The IARC determined in 1995 that acrolein was not 

classifiable as to its carcinogenicity in humans.812 

Acrolein is extremely acrid and irritating to humans when inhaled, with acute exposure 

resulting in upper respiratory tract irritation, mucus hypersecretion and congestion. Levels 

considerably lower than 1 ppm (2.3 mg/m3

) elicit subjective complaints of eye and nasal 

irritation and a decrease in the respiratory rate.813,814 Lesions to the lungs and upper respiratory 

tract of rats, rabbits, and hamsters have been observed after subchronic exposure to acrolein. 

Based on animal data, individuals with compromised respiratory function (e.g., emphysema, 

asthma) are expected to be at increased risk of developing adverse responses to strong respiratory 

irritants such as acrolein. This was demonstrated in mice with allergic airway-disease by 

comparison to non-diseased mice in a study of the acute respiratory irritant effects of acrolein.815 

EPA is currently in the process of conducting an assessment of acute exposure effects for 

acrolein. The intense irritancy of this carbonyl has been demonstrated during controlled tests in 

512 
human subjects, who suffer intolerable eye and nasal mucosal sensory reactions within minutes 

of exposure.816 

Naphthalene: Naphthalene is found in small quantities in gasoline and diesel fuels. 

Naphthalene emissions have been measured in larger quantities in both gasoline and diesel 

exhaust compared with evaporative emissions from mobile sources, indicating it is primarily a 

product of combustion. EPA released an external review draft of a reassessment of the 

inhalation carcinogenicity of naphthalene based on a number of recent animal carcinogenicity 

studies.817 The draft reassessment completed external peer review.818 Based on external peer 

review comments received, additional analyses are being undertaken. This external review draft 

does not represent official agency opinion and was released solely for the purposes of external 

peer review and public comment. Once EPA evaluates public and peer reviewer comments, the 

document will be revised. The National Toxicology Program listed naphthalene as "reasonably 

anticipated to be a human carcinogen" in 2004 on the basis of bioassays reporting clear evidence 

of carcinogenicity in rats and some evidence of carcinogenicity in mice.819 California EPA has 

released a new risk assessment for naphthalene, and the IARC has reevaluated naphthalene and 

re-classified it as Group 2B: possibly carcinogenic to humans.820 Naphthalene also causes a 

number of chronic non-cancer effects in animals, including abnormal cell changes and growth in 

respiratory and nasal tissues.821 

Ethanol: EPA is conducting an assessment of the cancer and noncancer effects of 

exposure to ethanol, a compound which is not currently listed in EPA’s IRIS. A description of 

these effects will be presented, as required by Section 1505 of EPAct, in a Report to Congress on 

public health, air quality and water resource impacts of fuel additives. We expect to release that 

report in 2009. 

Extensive data are available regarding adverse health effects associated with the ingestion 

of ethanol while data on inhalation exposure effects are sparse. As part of the IRIS assessment, 

pharmacokinetic models are being evaluated as a means of extrapolating across species (animal 

to human) and across exposure routes (oral to inhalation) to better characterize the health hazards 

and dose-response relationships for low levels of ethanol exposure in the environment. 

The IARC has classified “alcoholic beverages” as carcinogenic to humans based on 

sufficient evidence that malignant tumors of the mouth, pharynx, larynx, esophagus, and liver are 

causally related to the consumption of alcoholic beverages.822 The U.S. DHHS in the 11th Report 

on Carcinogens also identified “alcoholic beverages” as a known human carcinogen (they have 

not evaluated the cancer risks specifically from exposure to ethanol), with evidence for cancer of 

the mouth, pharynx, larynx, esophagus, liver and breast.823 There are no studies reporting 

carcinogenic effects from inhalation of ethanol. EPA is currently evaluating the available human 

and animal cancer data to identify which cancer type(s) are the most relevant to an assessment of 

risk to humans from a low-level oral and inhalation exposure to ethanol. 

Noncancer health effects data are available from animal studies as well as epidemiologic 

studies. The epidemiologic data are obtained from studies of alcoholic beverage consumption. 

Effects include neurological impairment, developmental effects, cardiovascular effects, immune 

system depression, and effects on the liver, pancreas and reproductive system.824 There is 

513 
evidence that children prenatally exposed via mothers’ ingestion of alcoholic beverages during 

pregnancy are at increased risk of hyperactivity and attention deficits, impaired motor 

coordination, a lack of regulation of social behavior or poor psychosocial functioning, and 

deficits in cognition, mathematical ability, verbal fluency, and spatial 

memory.825,826,827,828,829,830,831,832 In some people, genetic factors influencing the metabolism of 

ethanol can lead to differences in internal levels of ethanol and may render some subpopulations 

more susceptible to risks from the effects of ethanol. 

N-Hexane: N-Hexane is associated with polyneuropathy in humans. Effects observed in 

rodents include nasal lesions as well as neurotoxic effects. EPA has developed a reference 

concentration of 700 μg/m3

 from a study of peripheral neuropathy.833 There is inadequate data to 

assess its carcinogenic potential. 

Peroxyacetyl nitrate (PAN): PAN has not been evaluated by EPA’s IRIS program. 

Information regarding the potential carcinogenicity of PAN is limited. As noted in the EPA air 

quality criteria document for ozone and related photochemical oxidants, cytogenetic studies 

indicate that PAN is not a potent mutagen, clastogen (a compound that can cause breaks in 

chromosomes), or DNA-damaging agent in mammalian cells either in vivo or in vitro. Some 

studies suggest that PAN may be a weak bacterial mutagen at high concentrations much higher 

than exist in present urban atmospheres.834 

Effects of ground-level smog causing intense eye irritation have been attributed to 

photochemical oxidants, including PAN.835 Animal toxicological information on the inhalation 

effects of the non-ozone oxidants has been limited to a few studies on PAN. Acute exposure to 

levels of PAN can cause changes in lung morphology, behavioral modifications, weight loss, and 

susceptibility to pulmonary infections. Human exposure studies indicate minor pulmonary 

function effects at high PAN concentrations, but large inter-individual variability precludes 

definitive conclusions.836 

Pesticides: There are potential toxicity concerns with volatilization of pesticide active 

ingredients,837 in addition to concerns with contamination of foods and drinking water. 

Furthermore, raising acreage under corn production may increase the quantity of pesticide 

products in use. As the domestic corn supply grows between the years of 2005 and 2022, the 

percentage of corn used for ethanol production in the US is expected to increase, though the 

agricultural impacts of this shifting of crop production domestically are anticipated to be small. 

Whether there is the potential for adverse human health effects from any increase in pesticide use 

associated with increased corn production domestically warrants further assessment. Additional 

information on pesticides and health effects is included in Section 6.1 of this DRIA. 

Other Air Toxics: In addition to the compounds described above, other compounds in 

gaseous hydrocarbon and PM emissions from vehicles will be affected by today’s proposed 

action. Mobile source air toxic compounds that will potentially be impacted include 

ethylbenzene, polycyclic organic matter, propionaldehyde, toluene, and xylene. Information 

regarding the health effects of these compounds can be found in EPA’s IRIS database.838 

514 
3.4.6 Environmental Effects of Air Toxics 

Fuel combustion emissions contribute to ambient levels of pollutants that contribute to 

adverse effects on vegetation. PAN is a well-established phytotoxicant causing visible injury to 

leaves that can appear as metallic glazing on the lower surface of leaves with some leafy 

vegetables exhibiting particular sensitivity (e.g., spinach, lettuce, chard).839,840,841 PAN has been 

demonstrated to inhibit photosynthetic and non-photosynthetic processes in plants and retard the 

growth of young navel orange trees.842,843 In addition to its oxidizing capability, PAN contributes 

nitrogen to forests and other vegetation via uptake as well as dry and wet deposition to surfaces. 

As noted above in Section 3.4.2.2, nitrogen deposition can lead to saturation of terrestrial 

ecosystems and research is needed to understand the impacts of excess nitrogen deposition 

experienced in some areas of the country on water quality and ecosystems.844 

Volatile organic compounds (VOCs), some of which are considered air toxics, have long 

been suspected to play a role in vegetation damage.845 In laboratory experiments, a wide range 

of tolerance to VOCs has been observed.846 Decreases in harvested seed pod weight have been 

reported for the more sensitive plants, and some studies have reported effects on seed 

germination, flowering and fruit ripening. Effects of individual VOCs or their role in 

conjunction with other stressors (e.g., acidification, drought, temperature extremes) have not 

been well studied. In a recent study of a mixture of VOCs including ethanol and toluene on 

herbaceous plants, significant effects on seed production, leaf water content and photosynthetic 

efficiency were reported for some plant species.847 

Research suggests an adverse impact of vehicle exhaust on plants, which has in some 

cases been attributed to aromatic compounds and in other cases to nitrogen oxides.848,849,850 The 

impacts of VOCs on plant reproduction may have long-term implications for biodiversity and 

survival of native species near major roadways. Most of the studies of the impacts of VOCs on 

vegetation have focused on short-term exposure and few studies have focused on long-term 

effects of VOCs on vegetation and the potential for metabolites of these compounds to affect 

herbivores or insects. 

515 
Chapter 4: Impacts on Cost of Renewable Fuels, 

Gasoline, and Diesel 

4.1 Renewable Fuel Production Costs 

4.1.1 Ethanol Production Costs 

4.1.1.1 Corn Ethanol 

Corn ethanol costs for our work were estimated using a model developed by USDA that 

was documented in a peer-reviewed journal paper on cost modeling of the dry-grind corn ethanol 

process.851 The USDA model considers a 40 MMgal/yr corn plant producing ethanol with a 

primary co-product of distillers dried grains with solubles (DDGS). The ethanol yield used in 

the model is 2.76 gallons per bushel with 2.0% gasoline denaturant. The model is based on work 

done in chemical process simulation software to generate equipment sizes, stream flowrates, and 

material and energy balances. These results were then put together with feedstock, energy, and 

equipment cost information in a spreadsheet format to arrive at a final per-gallon cost estimate. 

Although the model is current in terms of technology, yields, and capital estimates, we made 

some modifications to allow estimation of costs for ethanol plants of different sizes and 

operating under different energy and feedstock prices. We believe that these updates, in 

combination with the industry and supplier surveys done by USDA in developing the model, 

result a reasonable estimate for projected ethanol production costs. 

We estimate an average corn ethanol production cost of $1.43 per gallon in 2022 (2006 

dollars) for the policy case. 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 credit represents about 57% of the 

final per-gallon cost, while utilities, facility, and labor comprise about 22%, 11%, and 4%, 

respectively. For this work, we used corn and DDGS price projections generated by the Forestry 

and Agricultural Sector Optimization Model, which is described in Section 5.1.1 of this RIA. 

Figure 4.1-1 shows the cost breakdown for production of a gallon of ethanol. Note that this 

production model does not account for the cost to ship the DDGS. Those costs are external and 

are expected to increase the price of DDGS an end user located far from the plant. 

516 
Figure 4.1-1. 

Cost Breakdown of Natural Gas Dry Mill Corn Ethanol Production (2006$). 

-0.46 

0.81 

0.31 

0.16 

0.09 

0.06 

-$0.50 

-$0.25 

$0.00 

$0.25 

$0.50 

$0.75 

$1.00 

$1.25 

$1.50 

$/gal 

Labor 

Chemicals, enzymes 

Facilty cost, maint 

Utilities 

Corn minus DDGS 

DDGS sale 

Corn 

cost 

Corn price $3.34/bu 

DDGS price $139.78/ton 

Natural gas price $6.21/MMBtu 

Electricity price $0.059/kWh 

The effect of plant scaling on production cost can be estimated by applying an 

engineering scaling factor to all plant equipment. In past rulemakings involving modifications to 

refineries we have used a material scaling factor of 0.65. This factor is applied as an exponent to 

the ratio of the new size to the original size, the result of which is then multiplied by the original 

capital cost. The fact that this figure is less than 1.0 reflects the per-unit or per-gallon savings 

that is often realized when processes are scaled up. However, there is information suggesting 

that a general factor may be considerably higher for ethanol plants. A factor of 0.84 was put 

forth in a recent publication on dry mill ethanol production.852 Using this larger factor, we find 

that the change in per-gallon production cost due to economies of scale is very small over the 

range of typical plant sizes, on the order of $0.02 between 40 and 100 MMgal/yr. Thus, in 

computing production costs for this rulemaking we chose to ignore effects of any changes 

average plant size. Capital cost for a 40 million gal/yr facility is estimated at $58.1 million 

(2006$) based on the USDA production model. 

We considered the per-gallon cost impact of coal, biomass, and biogas as a process 

energy source rather than natural gas. Our industry characterization and forecast work suggests 

that ethanol production in the timeframe of our analysis will use a mix of feedstocks for process 

energy. We assumed that on average, coal and biomass combustion systems would have the 

capital cost due to similarities in feed, ash handling, and emission controls; the same argument 

can be made for use of biogas combustion relative to natural gas combustion (excluding the 

digesters or other source). Tables 4.1-2 and 4.1-3 show the breakdown of fuel sources and their 

cost impacts in cents per gallon. The weighted average cent per gallon change to baseline for 

ethanol production is given at the bottom of Table 4.1-3. 

517 
 

 

Table 4.1-2. 

Breakdown of fuel types used in estimating production cost of corn ethanol 

Fuel Type Total by Plant Type 

Plant Type Biomass Coal Natural Gas Biogas All Fuels 

Coal/Biomass Boiler 11% 0% - - 11% 

Coal/Biomass Boiler + CHP 10% 4% - - 14% 

Natural Gas Boiler - - 49% 14% 63% 

Natural Gas Boiler + CHP - - 12% - 12% 

Total by Fuel Type 21% 4% 61% 14% 100% 

Table 4.1-3. 

Breakdown of cost impacts by fuel type used in estimating production cost of corn ethanol 

Fuel Type Total by Plant Type 

Plant Type Biomass a

 Coal Natural Gas Biogas b All Fuels 

Coal/Biomass Boiler -$0.02 -$0.02 - - -

Coal/Biomass Boiler + CHP +$0.14 +$0.14 - - -

Natural Gas Boiler - - baseline +$0.00 -

Natural Gas Boiler + CHP - - +$0.16 - -

Total by Fuel Type - - - - $0.04 

Table 4.1.3 shows that we made the assumption that biomass firing has the same overall 

cost impact on ethanol production as coal firing. One reason for this is that our analysis of 

biomass feedstock costs suggests a range of $72 per ton in future years which is comparable to 

the cost of coal supplied to non-electric-power industries after transportation is included.853 

Wood and stover biomass has on average approximately 85% of the energy content of coal on a 

mass basis, varying by type of biomass and coal, again suggesting that they are comparable on an 

energy per mass basis.854 Thus, it is plausible that some ethanol producers near biomass sources 

(such as the Midwest and Southeast) may have a cost incentive to transition from coal to biomass 

for process heat. A second reason the assumption of biomass replacing coal in ethanol plants a 

desire for ethanol plant owners to comply with or hedge against potential fossil carbon emission 

limits for stationary sources and/or transportation fuel producers. 

Similarly, we made the assumption that biogas combustion for process heat would have 

the same cost impact on ethanol production as natural gas combustion. Use of biogas is 

somewhat different from biomass in that it would require some capital investment for on-site 

anaerobic digesters and related feedstock and gas handling equipment. However, we anticipate 

the digester feedstock itself would have very low or no cost, thus it is reasonable to assume that 

the ongoing operating costs besides capital would be considerably less than purchasing natural 

gas. As with biomass combustion, most plants utilizing biogas would take advantage of 

situations such as co-location with feedlots or MSW facilities where suitable biomass resources 

are available. 

Energy prices used in the model were taken from EIA Annual Energy Outlook 2008, and 

are shown in Table 4.1-4. 855 Gasoline denaturant was assumed to cost $2.05 per gallon in all 

cases, and coal was assumed to be $1.94/MMBtu in all cases. The impact of coal firing and CHP 

were figured as changes from baseline. Table 4.1-5 shows the feedstock prices used for the 

reference and low-yield agricultural cases. The low-yield case refers to a reduction of per-acre 

518 
 

corn yields by approximately 12%, which has a higher impact on prices than the AEO high oil 

case. 

Table 4.1-4. 

Energy Prices Used for Ethanol Cost Modeling for 2022 (2006$) 

EIA Price Case Crude Oil Natural Gas Electricity 

$/bbl $/MMBtu $/kWh 

Reference 53 6.21 0.059 

High oil 92 7.21 0.061 

Table 4.1-5. 

Feedstock Prices Used for Ethanol Cost Modeling for 2022 (2006$) 

AEO Price Case Agricultural Case Corn DDGS 

$/bu $/ton 

Reference Reference 3.34 139.78 

Reference Low yield 3.84 160.32 

High Reference 3.42 141.68 

4.1.1.2 Cellulosic Ethanol 

Crop Residue Costs 

We could have used any of the crop residues as an example feedstock in the following 

discussion, since similar logistics apply to all of them. We chose to use corn stover, e.g., the 

stalks, leaves, and cobs that remain following grain harvest, since it is likely to represent a 

significant portion of cellulosic feedstocks in the future. Since there is no equipment specifically 

designed to harvest corn, the system we describe below uses combines, mowers, rakes, balers, 

and bale haulers already in use for harvesting hay or straw. Differences in stalk or stem diameter 

and density, bale density, moisture content, machine field speeds and efficiencies are a few 

things that make it relatively more difficult to harvest stover than hay or straw. One of the main 

concerns is that the density of the large stover bales, whether round or rectangular, can be as 

little as one-half that of similar dimension hay bales, which usually translates into higher 

transportation costs.856 

Most biomass feedstocks must be harvested, stored, and transported to a processing 

facility before they can be converted into ethanol. At present, there are no commercial sized 

cellulosic ethanol plants in the U.S. Likewise, there are no commercially proven, fullyintegrated feedstock supply systems dedicated to providing any of the crop residues or other 

feedstocks to ethanol facilities of any size. We emphasize ‘integrated feedstock supply systems’ 

because logistically the delivery of a feedstock to a processing facility will require the planning, 

executing, and controlling of several different, closely integrated operations, e.g., feedstock 

harvesting, gathering, storing, and moving by road and rail. Apart from the large numbers and 

wide variety of equipment, these operations will require professional and technical support 

services and personnel such as office space, staff, and office equipment such as computers and 

printers. Also, engineers, light- and heavy-duty equipment operators, vehicle maintenance 

519 
 

 

 

 

 

 

personnel and repair and storage facilities for tractors, rakes, balers, loaders, and trucks and 

trailers, as well as transportation infrastructure planning and management. 

Ordinarily, to determine the operational sufficiency and efficiency of such a system, we 

would ‘analyze’ it. We would first break it down into its component parts or essential features 

and then study them, e.g., how much they cost, and how and/or whether they operate efficiently 

within the ‘system.’ However, no such system currently exists. Therefore, we ‘synthesized’ a 

feedstock supply system in order to analyze it. We used a Purdue University, School of 

Industrial Engineering simulation study of corn stover logistics from satellite storage to an 

ethanol plant, to set up our feedstock harvesting and gathering operation. Purdue’s notional 

cellulosic ethanol plant was to be constructed next to an actual existing corn grain plant in 

northern Indiana. They used discrete event simulation software and GIS tools to study the 

transportation logistics associated with supplying the conversion facility directly from satellite 

storage. They identified 785,200 available acres out of 848,453 potential acres, on 2,052 actual 

farms, of 200-, 400-, or 800-acres, in 12 northern Indiana counties within 50-miles of the 

production facility (they disregarded fields or farms of less than 200-acres). We reproduced their 

original table as Table. 4.1-6. 

Table 4.1-6. 

Feedstock Availability at Various Distances From South Bend, IN 

 Average Farm Size 

Average Actual Cumulative 200 400 800 Available 

Acres 

Cumulative 

Acres 

bales/ 

day 

bales/day 

Distance /farm set County Acres Acres Acres 

12 St Joseph 69 69 74 51 35 63 63 4,956 4,956 

25 Elkhart 150 219 90 47 23 55 118 4,328 10,257 

 Marshall 110 52 41 76 194 5,928 

30 La Porte 113 332 113 73 70 108 302 8,453 8,453 

35 Starke 60 392 34 39 41 55 357 4,328 4,328 

40 Kosciusk 

o 93 485 108 66 43 82 439 6,461 6,461 

45 Lagrange 132 617 53 47 20 45 485 3,560 9,049 

Fulton 86 66 43 70 555 5,489 

50 Porter 225 842 76 59 34 66 621 5,175 18,224 

Noble 115 47 21 59 679 4,595 

Pulaski 39 72 64 108 787 8,453 

842 998 619 435 787 61,726 61,728 

We initially assumed that the stover had been harvested (square bales), gathered, fieldtransported, and stored at seven-satellite storage areas located near the corn fields.857 However, 

upon further study, we determined the counties that Purdue combined into each of the farm sets, 

weren’t anywhere near each other. In reality, it would have been far too costly to gather all the 

bales from the Porter, Noble, and Pulaski counties into one site, because these three counties are 

actually separated by other counties. Rather than try to construct seven satellite storage sites, we 

constructed a site at the center of each county. This was done in order to estimate the cost to 

collect the bales from all the fields in each county. We determined that the distance from the 

center of each of the Porter, Noble, and Pulaski counties, as well as the other two so-called 

farm-sets, to the ethanol plant was about equal, so regardless of whether we treat them as single 

sites, the transport costs for the bales to the ethanol plant will be the same. We ‘synthesized’ the 

feedstock system to harvest, gather, field transport, and store stover bales at the 11-notional 

520 
 

satellite storage units rather than the seven farm-set units used in the Purdue transportation model 

(our study was not done in conjunction with the Purdue study; rather we used their 

information/data as the basis from which to synthesize our notional operation). The format we 

chose to analyze was to shred, rake, square-bale, gather, field-side, and then load and haul the 

bales to satellite storage; then, as needed, haul the bales to the processing plant. 

Rather than guess at how such a system should look and function, we carefully studied 

several similar systems that were put forward by various agricultural and biological experts.858, 

859, 860, 861, 862, 863, 864, 865, 866 We used the American Society of Agricultural and Biological Engineers 

(ASABE), 2007 Standards, Engineering Practices, and Data as the primary source for our 

equipment capital and operating cost estimates. It has a machinery management section, ASE 

EP496.3, FEB2006, devoted to providing helpful information in making management decisions 

involving machine power requirements, capacities, cost, selection, and replacement, as well 

section ASAE D497.5 FEB2006, with data which includes representative values of farm 

machinery operating parameters, to aid managers, planners, and designers in estimating the 

performance of field machines. These data are intended for use with ASAE EP496 (some data 

are also presented in equation form for easier use with computers, etc.).867 We used these 

sections along with other examples by other experts to estimate the machinery capital and 

operating costs for our analysis.868, 869, 870, 871, 872 We were able to get some machinery purchase 

prices from vendors whose identities are confidential. We reduced the equipment listed price by 

10% to determine the purchase price, a standard industry estimating practice. Otherwise, most of 

the data used to calculate machinery costs were generated with equations and appropriate data 

from the ASABE 2007 Standards. We used the equipment, list and purchase prices, along with 

their power and size estimates, with the suggested data and equations, mentioned previously, to 

calculate the lifetime hours and years, annual use, field efficiency, salvage value, fuel and oil use 

and cost (we obtained vendor quotes for oil cost), capital charge, repairs, insurance, housing, 

taxes, and labor. We compared our data, where appropriate, with the USDA 2006 Price 

Summary, published July 2007.873 We also compared our results with those generated by the 

experts we listed earlier in this paragraph. 

The Purdue study was based on supplying a 100-million gallon per year ethanol 

production facility, which they assumed would convert the stover-to-ethanol at 72-gallons per 

ton; they assumed that the on-farm stover yield was 2-dry tons per acre, as did we. We used 

National Agricultural Statistical Service (NASS) data to determine the actual corn grain yield in 

2005 (the data year for the Purdue study) for the counties studied in the simulation. We 

determined how much corn each county produced and from that how much stover was produced, 

2,455,058 tons or 3.12 dry tons per acre, with an assumed harvest index (HI) of 1:1 (see Table. 

4.1.1.2.2.)874 HI is based on the assumption that, for a single corn plant, half of the above ground 

dry matter is made up of stover and the other half is made up of grain. This is a fairly common 

assumption, although more than one group of researchers has found that this 1:1 ratio may not be 

the most accurate under some conditions. When considering above ground dry matter before and 

after full grain physiological maturation, they found that a stover to grain ratio of 0.8 to 1 may be 

more realistic especially when grain moisture is between 18 and 31 percent.875 

521 
 

Table 4.1-7. 

Data Comparison: NASS Indiana Data with Purdue Data and with EPA Calculations 

USDA-NASS – Counties in State of Indiana - 2005 Purdue Model Year – 2005 

Planted Harvested Yield Production Model Available 

acres 

Prorated 

Production wet tons dry tons 

County acres x 103 acres 

x 103 

bu/ 

acre bu x 106 acres x 103 acres x 103 bu x 106

 x 103 x 103 

St Joseph 71 70 147 10.2 69 65 9.5 266 225 

Elkhart 60 53 142 7.6 150 52 7.4 206 174 

Marshall 94 89 150 13.4 0 87 13.1 366 309 

La Porte 117 112 137 15.3 113 104 14.2 398 336 

Starke 61 60 137 8.2 60 56 7.7 214 181 

Kosciusko 102 100 149 14.9 93 93 13.8 386 326 

Lagrange 55 51 113 5.8 132 45 5.0 141 119 

Fulton 90 89 159 14.1 0 78 12.3 345 291 

Porter 68 67 137 9.2 225 61 8.4 234 198 

Noble 65 62 142 8.8 0 57 8.0 225 190 

Pulaski 103 101 152 15.3 0 92 13.9 390 330 

855 842 787 3,172 2,455 

However, a professor of agricultural engineering at the University of Wisconsin found 

that several researchers, going back to 1973 reported a grain mass fraction of 45% to 55% of 

total corn crop DM yield. On average, the variations seem to confirm the common rule of thumb 

of one unit mass of stover for a unit mass of grain. However, differences among harvesting 

methods, stages of maturity, and harvest dates can no doubt lead to much of the variation the 

researchers found in this estimate. His research indicates that the ratio of grain dry mass to total 

mass increased from about 38% in late August to about 59% on in mid-October, during a recent 

harvest. Therefore, the stover to total ratio declined from 62% to 41%. During the typical 

harvest period in the Upper Midwest when grain moisture is between 20% and 30%, the ratio of 

stover to total dry mass was less than 45% and averaged 43%. These results are similar to those 

found by others.876 Mainly, because we have no information upon which to base a reason to use 

something different, we chose to use the 1:1 ratio for corn stover to corn grain. We also assumed 

56-lbs per wet bushel (15.5% moisture) and 47.3-lbs per dry bushel, for the corn grain, to make 

our stover yield calculations.877 Table 4.1-8 summarizes the general operating parameters for our 

study. 

522 
 

 

 

 

 

 

 

 

 

 

 

 

Table 4.1-8. Operating Parameters 

EtOH Operating Year 350-days/yr

 On Stream Factor 0.96 

 Hours per year 8,400-hr/yr 

EtOH Production Rate 100,000,000-gal/yr 

EtOH Yield 72-gal/dry ton 

Feedstock Required 

per year 1,388,889-dry tons/yr 

 per day 3,968-dry tons/day 

Expected Dry Matter Loss 11.8% 

 Feedstock Harvested 1,574,400-dry tons/yr 

 Feedstock Yield 2-dry tons/acre 

Harvest Period 

 Days, 50-days

 Hours per Day 16-hr/day

 Harvest Hours 800-hr 

Format: Shred/Rake, 

Bale - Lg. Sq. - 3'x4'x8' 

Field Side - Self-Propelled 

Wagon 

Satellite Storage – 

Pole Barn on Concrete 

Transport to EtOH Facility – 

Truck & Trailer 

At 72 gallons per dry ton, the processing plant would require 1,388,889 dry tons of stover 

per year. However, we believe storage and transportation losses can be significant and should be 

taken into account. If, as stated in the report, they harvested 2-tons per acre, they actually 

harvested 1,574,400 tons of stover, or 64% of the 2,455,058 tons of available dry stover. The 

quantity of stover used versus the quantity harvested represents an 11.8% loss.CCCCCCCCC Thus, we 

assumed that with an 11% loss, we would need to harvest 4,498- dry tons of stover per day, 

which by the time it reaches the plant will actually equal 3,968-dry tons – the amount required 

per day at the ethanol plant. During a 350-day production year, 1.574-million tons of stover 

would have be stored in about 3.499-million, 900-lb bales (Purdue study bale weight), at the 

various satellite storage areas. For this study, we assumed all the loss took place between the 

satellite storage areas and the ethanol plant, rather than guess what the losses would be at various 

points within the harvest/transport scheme. 

In the following analysis, we did not account for the extra time or equipment that would 

be necessary for inevitable break-downs. Nor was time and equipment factored in for driving 

between fields and for weather delays. Stover suppliers face several, in some cases, difficult 

problems. At best, the actual harvest period is nearly always too short; winter weather can 

suddenly set in, which in some cases may completely stop a potential stover or straw harvest. 

Once the grain is harvested and the stalks are mowed, stover usually must be left in the field for 

three or four days to dry to below 20% moisture before it’s baled, otherwise spoilage or rot as 

well as spontaneous combustion are possible. If it rains, additional time is required for drying 

and muddy roads and fields can be badly damaged and the field-soil compacted by the increased 

CCCCCCCCC We indicated in a previous section that there may be as little as 25% to 50% stover actually available; 

however, since we didn’t have the computer software and database Purdue used and therefore couldn’t rerun the 

simulation, we chose to use the data we had. 

523 
heavy-weight harvest and transport equipment traffic. One expert commented that, “If there’s a 

rainy harvest, you might as well forget about it. Also, the longer the wet material is left in the 

field, there’s more of a chance for microbes to eat away at the hemicellulose.”878 Also, delayed 

baling raises the chances of dry matter loss. The stover needs to field-dry, so the stover harvest 

can’t actually begin for at least a few days after the grain harvest starts. But, once it begins it can 

continue until either it’s finished or until winter weather stops it. For reasons that weren’t 

explained in the report, the researchers at Purdue chose 50-days for the harvest period, which at 

their 16-hr per day schedule, provided a total of 800-hrs to complete the harvest and store the 

stover. In this harvest format (800-hrs), most of the machinery will be stored for the balance of 

the year. Crop harvest schedules in the Midwest and upper-Midwest are determined by the 

length of the growing season, the time of year when the crops are mature enough to harvest, and 

the time when winter weather sets in. Under ordinary conditions, farmers use their harvesting 

machinery during just a few weeks each year. During the past few years, as machinery costs 

have risen, many farmers have turned to custom harvesters, that move into an area and harvest 

several farms. A farmer must always weigh the differences in the custom rates and what it 

would cost him to own the equipment and complete the harvest himself, but then store most of 

the harvesting machinery for the rest of the year. In the South, winters are milder and it’s 

possible to harvest some crops all year long. In such cases, feedstocks could conceivably be 

harvested and shipped to a conversion facility on an ‘as needed’ basis; storage costs could be 

saved and machinery would be used all year long. However, an important factor, when it comes 

to harvest machinery, is the usable-life of the equipment. The more hours used each year, the 

more often the machine will need to be replaced. A machine lasts only so many hours, whether 

it’s used 800-hrs per year or 8,000-hours per year. We obviously could have arbitrarily chosen 

some longer period, but in order to maintain at least some consistency with the Purdue study, we 

chose to use the 50-day schedule for our study. This short period means we must harvest and 

store a full year’s inventory within a few weeks. 

Mow, Shred, Rake: Modern corn combines strip most of the leaves from a corn stalk, but 

leave up to about half of the stalk standing when they cut it off just below the bottom ear. In the 

combine, the corn grain is stripped from the cob, and the top part of the stalk, the leaves, and the 

cobs are subsequently discharge out the spreader at the rear of the machine. According to a 

group of researchers, at the time of grain harvest, of the total stover dry mass, 16% resides in the 

cob, 7% in the husk, 16% in the leaves, and 60% in the stalk fractions. Of the stalk dry mass, 

roughly 45% is found in the bottom one-quarter and 80% in bottom one-half of the stalk. If 

stover yield is to be maximized, harvesting systems must be developed that allow the bottom half 

of the stalk to be fully harvested 879 We summarized the costs to shred and rake in Table 4.1-9 

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Table 4.1-9. Corn Stover Shredding & Raking Operation 

Tractor – 

245-hp 

FlailShredder -30’ Tractor 

75-hp MFWD 

Wheeled 

V-Rake - 20 ft 

Equipment Factors 

 Purchase price $ 144,502 28,733 59,383 3,660 

 Useful life yrs 11.3 3.1 11.3 15 

 Discounted Salvage value $ 11,736 0.00 7,861 

Annual use hr 800 800 800 800 

Fixed Costs $/hr 

 Depreciation and interest 25.47 14.51 10.06 1.87 

 Taxes Insurance Housing (THI) $/hr 3.97 0.79 1.63 0.10 

Total Fixed Costs $/hr 29.44 15.30 11.69 1.97 

Variable Costs 

 Repairs and maintenance $/hr 19.62 14.05 8.06 1.63 

 Fuel consumption gal/hr 9.6 8 5.6 

 Fuel and lubrication $/hr 23.82 19.87 13.81 4.27 

 Operating Interest 1.70 1.21 0.82 0.21 

Labor $/hr 15.91 15.91 15.91 4.00 

Total Variable Cost $/hr 61.05 51.04 38.60 10.11 

Total Costs 

 Total $/hr 90.49 66.34 50.29 12.08 

 Equipment capacity MT/hr 32.7 13.27 

Total $/ton 4.80 4.70 

It will likely be necessary to flail-cut or mow the standing-stalks, and then rake and bale 

the windrows. We estimated that it cost about $4.80 per ton of stover for shredding and about 

$4.70 per ton for raking. 

Bale: As previously discussed, large square bales will likely be the bale-format for this 

system, although large round bales could be used. There are currently more round balers than 

square balers in use, mainly because large square balers are more expensive. However, 

gathering, stacking, and transporting large, round bales is much less efficient. It is difficult to 

stack round bales more than about three high, since they tend to deform rather badly, during even 

short storage periods; square bale stacks can be stacked up to five or six bales high, which 

translates into a more efficient use of storage area as well as more stable stacks that are far less 

prone to deformation over extended storage periods. Although large round bales tend to weather 

better out in the open, for the reasons just stated as well as those given in the Purdue report, we 

used large square bales in this analysis. Table 4.1-10 summarizes the cost of the baling 

operation. 

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Table 4.1-10. Corn Stover Baling Operation 

Tractor -

 275-hp 

Lg. Sq. 

Baler - 3' x 4' x 8' 

Equipment Factors 

 Purchase price $ 147,102 110,723 

Useful life yrs 11.3 3.8 

 Discounted Salvage value $ 7,553 32,455 

Annual use hr 800 800 

Fixed Costs $/hr 

 Depreciation and interest 25.93 36.74 

 Taxes Insurance Housing (THI) $/hr 4.05 3.04 

Total Fixed Costs $/hr 29.98 39.78 

Variable Costs 

 Repairs and maintenance $/hr 19.98 45.11 

 Fuel consumption gal/hr 10 8 

 Fuel and lubrication $/hr 24.84 19.87 

 Operating Interest 1.71 2.38 

 Labor $/hr 15.91 10.66 

Total Variable Cost $/hr 62.44 78.02 

Total Costs 

 Total $/hr 92.42 117.80 

 Equipment capacity DMT/hr 19.4 

Total $/ton 10.87 

Another, sometimes overlooked issue, is that when stover is shredded, raked, and baled 

dirt tends to be to picked-up with the bales, which must be removed prior to processing. Dirt can 

usually be traced back to dirt clods left by the producer’s cultivation practices and when the 

pickup on the harvester is set too low in an attempt to pickup as much stover as possible. Some 

dirt sticks to the corn stover if the stalks are left on the ground and run over by equipment; 

occasionally roots, attached to the short, cut-off stalks that are left following the shredding 

operation may be tipped out of the ground by harvest equipment and end up in the bales. Exact 

amounts of dirt aren’t easily measured, but are thought to be in the 2% to 5% range. Areas that 

contain excessive weeds should be avoided, if possible. Some weed types also contribute to 

additional moisture and dirt and these are thought to be major factors in stover deterioration and 

overall shrinkage. Furthermore, dirt that’s carried through the harvesting process causes severe 

equipment wear; grinders, mills, valves, pipes, conveyors, and other associated equipment fail 

much sooner, which translates into increased maintenance costs and reduced on-stream operating 

time. We estimated that baling cost about $10.87 per ton.880, 881, 

Bale Pick-Up & Field Side: It is important to remove the stover bales from off the fields. 

Few farmers will tolerate bales left for long periods on their fields, especially if there is a chance 

spring planting will be negatively affected. Nor do we expect farmers will allow random piles of 

bales left at field edges, for retrieval over the winter and spring months. Aside from the 

likelihood that trucks and other equipment would get stuck in muddy roads and fields, thus 

slowing down deliveries and running up operating costs, farmers would have little tolerance for 

torn-up roads and fields. This may not be a big problem, if the farmer/grower intends to plow a 

field in the spring. However, it could be highly problematic for a farmer/grower who “no till” 

farms and would be forced to repair ruts and holes in fields and roads before Spring planting. 

Apart from this, dry matter losses from bales, left out in the open on dirt, can be as high as 10% 

526 
 

 

 

to 20%. At harvest time, the bales, regardless of format, must be picked up and hauled either to 

a satellite storage site for intermediate storage or hauled directly to the processing plant. 

Several variables must be taken into account for bale pickup and the field-side haul 

operation that could easily affect the cost. Because the exact location on a field where a bale 

lands as it falls from a baler varies, at a minimum, according to stover yield and harvest 

efficiency, there is no easy or accurate method for predicting the exact location of each bale on 

the field, either relative to each other or to the field edges or entry. The distance between bales 

and the potential variability in the area, shape, and relative dimensions of each field add to the 

difficulty of estimating bale pickup costs. If it was possible to somehow tag each bale with GPS 

coordinates as it fell to the ground, theoretically the coordinates could be used in some type of 

‘bale retrieval’ program to optimize the time and pickup distance traveled.882, 883 

For this study, we used the theoretical stover density on the field, the speed and width of 

the harvester to estimate the distance between bales. We used a spreadsheet with these data to 

position the bales in a variety of patterns on a notional rectangular 100-acre field. We devised 

three or four drive-patterns in which the bales could be retrieved, by using simple visual 

inspection. We calculated the time to pick up the bales using each pattern and the average speed 

of the self-propelled bale-wagon. There were a few variables for which we couldn’t adjust our 

numbers because we simply had no way of knowing their effect. For example, if the field was 

furrowed, it seemed that the less time spent driving across the furrows, at, as we assumed a 

slower speed than could be traveled along the furrows, the more efficient would be the pick up. 

Table 4.1-11 summarizes the information we used for our calculations. 

Table 4.1-11. Bale Pickup and Field-Side 

Ft. Between Each Bale 490 

Pickup One 10-Bale Load - Ft/Load 4,901 

Bales/Acre 4.4 

Bales/Load 10 

Tons/Load 4.5 

Loader Speed - mph 7.5 

Field Size - Acres 200 400 800 

 Number of Loads per Field Size 89 178 356 

 Bales/Field Size - Total 889 1,778 3,556 

 Miles Traveled per Load 1.74 2.05 2.51 

 Tons/Hour 26 22 18 

Cost per Ton – Pickup & Field-Side $2.82 $3.31 $ 4.05 

In any case, using our basic assumptions, the time it took to retrieve a 10-bale load didn’t 

vary significantly for any of our plots. Table 4.1-12 presents the operating data for the bale 

wagon. 

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Table 4.1-12 Self-Propelled Bale-Wagon 

Bale Wagon 

Equipment Factors 

 Purchase price $ 153,716 

 Useful life yrs 18.1 

 Discounted Salvage value 6,013 

 Annual use hr 800 

Fixed Costs $/hr 

 Depreciation and Interest $/hr 20.70 

 Taxes Insurance Housing (THI) $/hr 4.23 

Total Fixed Costs $/hr 24.93 

Variable Costs

 Repairs and Maintenance $/hr 12.96 

 Fuel Consumption gal/hr 7 

 Fuel and Lubrication $/hr 17.39 

 Operating Interest 1.21

 Labor $/hr 15.91 

Total Variable Cost $/hr 47.47 

Total Costs $/hr 72.40 

Total $/hr 72.40 

Equipment capacity DMT/hr 23 

Total $/ton 3.15 

Since the fields were no smaller than 200-acres, we piled the bales at one of the corners, 

which we assumed as the field-entry. We calculated the cost to haul bales for each of the 200-, 

400-, and 800-acre fields. We assumed the 20-ft rake made 148-passes across the 200-acre field; 

209-passes across the 400-ft field; and 295-passes across the 800-ft field. We used the number 

of windrows the rake left to determine the number of passes the baler would make. The baler 

dropped a bale every 490-ft; to collect a 10-bale load the loader would need to travel 4,900-ft. 

We estimated that the average distance every bale would need to travel to the corner of the field, 

e.g., the field entry, would be the distance from the field center to the corner (field-entry); we 

assumed the fields were square. The loader would need to travel that distance and then return 

empty, for the next load. Therefore, each loader would travel 4,900-ft to pickup the load, and 

then an additional 4,174-ft for the 200-acre field; 5,903-ft for the 400-acre field; and 8,348-ft for 

the 800-acre field to haul to the field edge (corner) and return. We chose to pick up 10-bales per 

load with a self-propelled bale wagon with an average speed of about 10-mph. We assumed the 

bales would be picked up, transported, and dumped at the field-edge at a cost of $2.82-per ton for 

the 200-acre fields; $3.31-per ton for the 400-acre fields; and $4.05-per ton for the 800-acre 

fields. We weighted the DM hauled for each field size by the total tons recovered from each 

size, to arrive at 23-weighted dry tons/hr hauled for $3.15-per ton 

Haul to Satellite Storage: Theoretically, we could store all the bales at the ethanol plant. 

If so, we would need to move 3,148,800-bales or about 101-loads per hour for 16 hours each day 

during the 50-day harvest. It would require 50-stacks, each, eight-bales wide by 5-bales high, by 

1,577-bales (12,615-ft.) long, with 51 x 20-ft aprons and isles, between each stack and along 

two-sides of the entire area, plus a 20-ft apron, across the entire front and rear. The area would 

total ~33-million square feet or 1.19-square miles. 

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We stored the bales at satellite facilities near the center of each county. As previously 

discussed, the Purdue study established ‘farm-sets,’ but did not describe how they were 

configured and how bales were to be hauled to each storage site, nor did the study specify 

exactly where each storage site was. Rather, they only estimated the distance between each 

storage area and the ethanol plant. The following table summarizes the cost factors used to 

estimate the costs to haul the bales to satellite storage. 

Table 4.1-13. 

Haul - Field Side to Satellite Storage
 

High-Speed 

Tractor 

Bale 

Wagon 

2­

Telescopic 

Handlers 

Equipment Factors 

 Purchase price $ 133,865 23,851 130,106 

 Useful life yrs 15 15 12.5 

 Discounted Salvage Value $ 10,782 4,803 6,490 

 Annual use hr 800 800 800 

Fixed Costs $/hr

 Depreciation and Interest $/hr 19.62 3.34 21.48 

Taxes Insurance Housing(THI) $/hr 3.68 0.66 3.58 

Total Fixed Costs $/hr 23.30 4.00 25.06 

Variable Costs

 Repairs and Maintenance $/hr 13.63 1.94 15.90 

 Fuel Consumption gal/hr 6 0 2 

 Fuel and Lubrication $/hr 14.90 0 9.94 

 Operating Interest $/hr 1.13 0.09 1.02 

 Labor $/hr 15.91 7.95 31.82 

Total Variable Cost $/hr 45.57 9.98 58.68 

Total Costs $/hr 68.87 13.98 83.74 

Total $/hr 166.59 

Equipment capacity DMT/hr 9.3 

Total $/ton 17.91 

We assumed that a telescopic loader would load the bales at the field-edges onto 20-bale, 

2-axle, 30-ft long wagons, each pulled by a high-speed tractor to the storage area located at the 

center of each county, where they were unloaded by another telescopic loader and the bales 

stacked for temporary storage. Several variables make the cost of this operation difficult to 

estimate. A cursory inspection of the general outline/shape of many of the counties in the study 

reveals that they are by no means square. However, to make our calculations manageable, we 

assumed they were in order to determine the average distance each bale would need to be 

transported to its respective storage area in each county. We estimated that the average distance 

any load would travel from any position in the counties, e.g., from the furthest to the nearest, 

would be equal to one-half the distance from the corner of the county to its center. We used the 

published area of each county, from which we determined the distance from one-corner to the 

center; that distance equaled the trip to the storage area and the return. We multiplied each by a 

30% winding factor (rather than a straight-line drive, this accounts for turns and other 

meanderings).884 We estimated the operation would cost about $17.91 per ton. 

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Satellite Storage: We assumed each storage unit would consist of a concrete slab with 

open sides and pole-supported tin roof. Smooth paved surfaces are safer and make work easier. 

Gravel and dirt do not stick to the bottoms of the bales. If winter (wet, muddy) access is 

necessary, this cost should be included in the overall costs for storage; particularly from the 

highway to the stack. Beyond the need to keep the area around the stack accessible and clean, 

the could be problems with local authorities, if trucks leaving the property carry significant 

quantities of mud onto a public highway. Ordinarily, in an agricultural area a certain amount of 

mud is expected to be left on highways during wet weather. However, at the truck and trailer 

volumes we’re anticipating, the amount being tracked onto highways and possibly through 

municipalities, would increase rapidly. We used 1% of construction costs for upkeep, and 2% of 

the construction cost for the storage unit to cover the cost of access. These are incurred costs 

within the overall maintenance of stored stacks of biomass. These costs are essentially 

insignificant in the overall storage costs, are subject to great fluctuations due to weather and 

equipment availability, and, therefore, were rolled up into a percentage of the overall storage 

costs of stacked bales. The following table summarizes our storage area construction cost factors 

and costs. 

Table 4.1-14. 

Satellite Storage Construction & Maintenance Costs – For Each of 11-Areas 

Land Rent $/acre/yr 100 

Land Preparation $/acre 30,000 

Construction $/sq ft 3.75 

Upkeep – 1% of 

Construction $/t 0.91 

Access – 

2% of Construction $/t 1.81 

Depreciation Period yrs 12 

Number 

of 

Bales 

Bale 

Storage 

Area 

sq ft 

Bale 

Storage 

Area 

acres 

Number 

of 

Bales 

per site 

Tons 

Stover 

per site 

Supply 

days 

Total 

Storage 

Cost 

$/dry ton 

St Joseph 280,889 2,943,716 280,889 280,889 126,400 28.1 1,123,463 

Elkhart 245,333 2,571,093 245,333 245,333 110,400 24.5 981,252 

Marshall 336,000 3,521,280 336,000 336,000 151,200 33.6 1,343,889 

La Porte 479,111 5,021,084 479,111 479,111 215,600 47.9 1,916,286 

Starke 245,333 2,571,093 245,333 245,333 110,400 24.5 981,252 

Kosciusko 366,222 3,838,009 366,222 366,222 164,800 36.6 1,464,768 

Lagrange 201,778 2,114,631 201,778 201,778 908,00 20.2 807,044 

Fulton 311,111 3,260,444 311,111 311,111 140,000 31.1 1,244,342 

Porter 293,333 3,074,133 293,333 293,333 132,000 29.3 1,173,236 

Noble 260,444 2,729,458 260,444 260,444 117,200 26.1 1,041,692 

Pulaski 479,111 5,021,084 479,111 479,111 215,600 47.9 1,916,286 

350 

Total Cost $/ton 8.89 

 With well-paved surfaces, equipment can be maneuvered regardless of weather, and 

surfaces can be sloped to enhance drainage. We also assumed the bales would be stored in 

multiple stacks, 8-bales wide and 5-bales high, and long enough to accommodate the number of 

bales we expect; there would 20-ft aprons along the outside of the stacks and 20-ft isles between 

stacks for stacking, stack management, and for general and fire safety.885 One researcher 

530 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

determined that the economics of size, in the current situation, did not really apply. In order to 

determine a cost per square foot, we assumed all 3,148,800 bales would be stored on a single 

slab/pole barn. Stacked five-high, it would require 758-acres or 1.18 sq. miles of concrete and 

roof. We estimated that storage would cost about $8.89 per ton.886 We used this as the cost per 

ton for the satellite storage as well as for storage at the plant. 

We estimated that to shred, rake, bale, field side, construct satellite storage, and haul to 

satellite storage plus pay the farmer/grower $10/t and replace the nutrients for $11.81/ton, it 

would cost about $72.20 per dry ton.887 888 

We used 11-telehandlers at the storage areas. (However, once the harvest is complete the 

telehandlers being used for loading and unloading bale wagons during the field-side to storage 

area operation could possibly be pressed into transport – load, unload service (see Table 4.1-15). 

If so, the cost to use the telehandlers could be reduced from $3.28 to $3.08 per ton.) Plus 11­

telehandlers at the plant to load and unload trucks and trailers that deliver the stover from 

satellite storage to the plant; extra telehandler time at the plant will be used to move feedstock as 

needed. The following table summarizes the cost associated with the transportation. The 

following table summarizes the cost associated with the transportation 

Table 4.1-15. Haul From Satellite Storage to Plant 

 Class 8 

Truck 

53-ft Flatbed 

Trailer 

22-Telescopic 

Handlers 

Equipment Factors 

 Purchase price $ 103,839 42,173 130,106 

 Useful life yrs 20 22 13 

 Discounted Salvage Value $ 4,025 931 6,490 

 Annual use hr 5,600 5,600 800 

Fixed Costs $/hr 

 Depreciation and Interest $/hr 1.91 0.74 236.28 

Taxes Insurance Housing(THI) $/hr 0.41 0.71 39.38 

Total Fixed Costs $/hr 2.31 1.45 275.66 

Variable Costs

 Repairs and Maintenance $/hr 1.13 3.16 174.90

 Fuel Consumption gal/hr 9 0 2 

 Fuel and Lubrication $/hr 33.95 0 109.34

 Operating Interest $/hr 0.37 0.14 11.22 

 Labor $/hr 17.46 350.02 

Total Variable Cost $/hr 52.91 2.31 $645.48 

Total Costs $/hr 55.22 3.76 921.14 

Total $/hr 58.97 921.14 

Equipment capacity DMT/hr 4.5 281 

Total, each $/ton 13.10 3.28 

Total $/ton 16.38 

To transport the bales to the ethanol plant, we calculated the ton-weighted average triptime to be 4.09 hr. We plan to ship 4,497-tons of stover to the plant on each of the 350-operating 

days. At 17.5-tons per load, we anticipate there will be about 256-loads per day. Using the 4.09­

ton weighted trip time, we estimated that it would require 63-trucks and trailers to haul 4 x 17.5­

531 
 

 

 

 

 

 

 

 

 

 

 

ton per day. The cost of transportation plus loading and unloading is estimated to be $16.38 per 

dry ton. The following table summarizes the total cost to harvest, bale, field-side, haul to 

satellite storage, store, and haul to the plant. The following table summarizes all the costs. 

Table 4.1-16. 

Ag Residue Cost Summary
 

Farm-Set Size, acres 200 400 800 Total Tons 

Tons per Farm-Set, t 756,4 

39 476,402 341,559 1,574,400 

Farmer/Grower $/t 10.00 10.00 10.00 

Nutrient Replace $/t 11.81 11.81 11.81 

Shred $/t 4.80 4.80 4.80 

Rake $/t 4.70 4.70 4.70 

Bale $/t 10.84 10.84 10.84 

Haul – Edge $/t 2.82 3.31 4.05 

Total Farm Edge Cost $/t 44.97 45.46 46.20 

Haul – SS $/t 17.91 17.91 17.91 

Storage $/t 8.89 8.89 8.89 

Haul to Ethanol Plant $/t 16.38 16.38 16.38 

Field to Plant – Total $/t 43.18 43.18 43.18 

Per Farm- Set – 

Total $/t 88.15 88.64 89.38 

Avg. Total Cost $/t 88.71 

The FASOM agricultural econometric model also estimated the farm edge price for corn 

stover. Like our analysis, the FASOM model accounted for harvesting, shredding, raking, baling 

and hauling the corn stover to the farm edge, and replenishing the soil with nutrients. However, 

FASOM did not add on a $10 farmer payment. Adding on a $10 farmer payment, FASOM’s 

farm edge price for baled corn stover was $42.70/ton. There was good agreement between our 

cost estimate and FASOM’s. 

As mentioned previously, a supply system organized in the near-term could look 

something like the one we’ve just described, but there are several potential drawbacks;. a 

comment, which we can’t attribute for confidentiality reasons was about the inefficiency of 

expending energy to package biomass just to expend more energy to unpackage this same 

biomass in order to meet the requirements of the conversion process. 

 We anticipate that industry will address most of these drawbacks by 2022 in order to 

improve the delivery and reduce the cost of feedstocks. The current harvest-system is usually 

referred to as a multipass system: the corn grain is first combined, and then the stover is 

shredded, raked, baled, and the bales hauled to the field side. Each field-pass adds to the final 

cost and further compacts the soil; soil compaction is especially critical if the soil is prone to 

compaction or in no-till situations.889 Because the combine-spreader drops the stover on to the 

ground, not only are fewer cobs collected, but dirt, dirt clods, and other debris, including metal, 

532 
 

 

 

are inevitably gathered up with the stover by the baler.890, 891 Thus, extra effort and money must 

be expended to remove the debris before processing can begin, apart from the fact that dry matter 

is also lost during this operation. In their 2002 study report, NREL included a wash table to 

remove dirt and grit and had magnets to remove tramp iron, e.g., wire, etc. from the stover.892 

We discussed many of these issues previously. 

According to a few sources, which for reasons of confidentiality, we can’t quote, there 

appears to be active interest in restructuring the system we just described to move the 

preprocessing (feedstock preparation) forward in the chain, away from the ethanol plant, and 

closer to the fields. Including the issues highlighted in the previous paragraphs, a major concern 

has to do with the use of standard hay and forage equipment, for which the overall collection 

efficiency of stover (ratio of stover collected to the total above-ground stover excluding grain) 

using flail choppers, rakes, and balers was less than 30%.893 Until now, most research has been 

based on a multipass system similar to the one we synthesized.894,895 In addition, the timeliness 

for collection (weather concerns) and moisture content issues are major problems associated with 

a multipass corn stover harvest.896 

The restructuring efforts also include exploring other methods to more efficiently gather 

the stover that avoids the need to pick it up from the ground, e.g., gather or catch it before it hits 

the ground.897 In one early case, a baler was hitched directly onto a combine, to capture the 

combine effluent and square-bale it. The problem was that there was a strict need to limit 

moisture to under 20% if bales are to be stored, plus the extra equipment slowed the grain 

harvest.898 Ideally, the stover harvest system should be capable of harvesting stover at any level 

of moisture even while the grain is being harvested. All the cobs would be collected, the stover 

wouldn’t touch the ground and a controlled amount of residue would be left to meet any 

conservation requirements (we believe finding a way to leave the correct amount of residue 

behind will be difficult, and should be a top priority). 

A modification of the system we previously described, would be to use a mobile tub 

grinder that could be towed from one satellite storage area to the next. A telehandler would feed 

the grinder to directly fill trucks for transport to the production facility. The ‘walking floor,’ 

rear-dump, or belly-dump trailers would unload the ground-up stover into silos or tanks at the 

facility. These silos or tanks could be sized to provide as much feed surge capacity as the facility 

required to maintain continuous operation.899 

Again, ideally, the corn stover harvest should be reduced to a single-pass operation 

during which the amount of residue left on the field will be less a function of harvest efficiency 

and more a function of the farmer/grower and the harvesting company being able to determine 

how much residue must be left to maintain soil health. In reality, most of the equipment doesn’t 

actually exists that could perform some of the operations we will describe. Nevertheless, we 

believe this reflects some of the forward thinking that is currently taking place. For example, a 

combine designed specifically for the job must still be constructed. A single-pass harvester 

would cut the whole stalk a few inches above the soil, leaving some stalk anchored to the 

ground. It would pull the entire plant, e.g., stalks, leaves, and cobs with grain into the combine, 

where they are mixed into a single, clean, grain and stover stream. It would then blow the entire 

stream into tractor-pulled grain-carts that run along-side the harvester. It is important to be able 

533 
 

 

to change full carts for empties without stopping the harvester. As a cart is filled, it is pulled 

from beneath the discharge tube, as an empty cart is pulled under it. The full cart is hauled to 

the field side, where the harvested material is unloaded directly into bulk ‘walking-floor’ semi 

trailers, for transport to a co-op or depot type elevator/facility. After the biomass stream is 

unloaded, equipment at the elevator/depot separates the stover from the grain, following which 

the stover is chopped, dried, and sent to tanks or silos for intermediate storage. Currently, there 

are no simple methods for drying wet corn stover, other than to let it field-dry. However, if the 

single-pass harvest is to become a reality, the stover will need to be dried or else stored in much 

the same way silage is stored.900 At harvest, corn grain has a moisture content of 25%, while at 

the same time, the stover ordinarily ranges from 35% to well over 50% moisture. There have 

been studies to artificially dry corn stover as well as other biomass types; there will likely be 

changes to the reported results of these and other studies, but, then we expect advancements and 

certainly changes in several parts of the feedstock supply system.901, 902, 903 Given that these 

changes take place, the stover, would have flowability characteristics similar to small cereal 

grains, and could be moved by standard grain loading and unloading systems into large 

corrugated steel bins (silos) for intermediate storage. In this harvest format, the stover is handled 

by only two machines before it reaches the roadside and never hits the ground. Dry matter losses 

should be significantly reduced.904 

Harvesting, storing, and transporting a denser feedstock should offer significant 

savings.905 Using this and other anticipated improvements, it appears possible that in the out 

years, e.g., by 2022, corn stover and other residues could be commoditized, much as is the case 

with grain, and then purchased by a processor on an as-needed basis. 

However, commoditization offers its own set of issues, among which are both tangible 

and non-tangible infrastructures. Although tangible infrastructure with regard to ethanol 

distribution are discussed in greater detail in Section 4.2, we believe the following comments fit 

within the context of our preceding information. The impact of both feedstock and finished 

ethanol on rural road, highway and railroad infrastructure is likely to be even greater than the 

current and anticipated impact of corn based ethanol. Raw cellulosic feedstocks have lower 

levels of concentrated fermentable carbohydrates and therefore require a greater mass of 

feedstock to produce an equivalent level of ethanol. Thus, public and private transportation 

infrastructure must move a greater volume of feedstock per gallon of ethanol produced. The 

magnitude of the impact will depend on the field density of feedstocks near the plant and 

whether feedstock densification will make it possible to ship more dense carbohydrate product to 

the cellulosic ethanol plant. 

Intangible infrastructure is essentially absent for crop residue type cellulosic feedstocks. 

Intangible infrastructure includes such things as uniform grade and quality standards, market 

price discovery mechanisms, collateral warehouse receipts, regulatory structure and other 

marketing institutions. Grain market institutions have been developed and fine-tuned over the 

past century that give corn ethanol plants a decided benefit. Daily price information, as well as a 

wealth of crop condition, and supply and demand information from a variety of public and 

private sources is available on corn grain. Well known institutions such Uniform Grade and 

Quality Standards, FGIS, Grain Warehouse Regulations, Collateral Warehouse Receipts, Trade 

Associations, Non-Recourse Government Commodity Loans, and a set of futures markets that 

534 
efficiently price grain over time and space are all readily available. This infrastructure is already 

in place, tested and readily accessible to corn grain ethanol producers. Although not highly 

visible and frequently taken for granted, it plays a critical role in efficient feedstock pricing, risk 

management, trading and financing. The cellulosic marketing infrastructure required for similar 

efficient commercial transactions will need to be established from top to bottom. 

Pricing infrastructure is one of the most pressing needs. Large daily volumes of corn and 

other grains are traded on well established exchanges with a great deal of confidence on the part 

of buyers and sellers that the other party will perform. Initially, it could be difficult, at best, to 

develop these infrastructure benefits for crop residues such as corn stover. Cellulosic feedstocks 

will be starting from a relatively small production base with no pricing institutions in place. 

There are no existing grades and quality standards to underpin transactions over distance and 

time. Nor are there any trade rules or established patterns for prompt and efficient settlement of 

trade disputes between buyers and sellers. The absence of these factors does not mean that they 

won’t develop, but there could be a stressful transition period. 

Also, there is no regulatory infrastructure to protect producers who wish to hold 

inventory after harvest in a public warehouse or handlers warehouse. This kind of infrastructure 

serves an important role in underpinning warehouse receipts and producer financing by creating 

a higher and more reliable collateral value for inventory. Nor are there equivalents to the U.S. 

grain grades and quality standards or Federal Grain Inspection Service. While there are other 

ways these functions can be provided some type of commodity grades and standards will be 

necessary to permit trading. Another possibility would be to have the production of cellulosic 

feedstocks and the production of ethanol vertically integrated in some fashion so that the 

responsibility for quality is internalized.906 

Energy Crops 

Energy crops such as switchgrass and miscanthus would be harvested, baled, stored and 

transported very similar to crop residues. Because of their higher production density per acre, 

though, we would expect that the “farm gate” costs to be slightly lower than crop residues (we 

estimate the costs to be about $1 per dry ton lower). Also, the higher production density would 

allow for fewer secondary storage facilities compared to crop residue and a shorter transportation 

distance. For example, we estimate that switchgrass would require less than 30 secondary 

storage facilities which would help to lower the feedstock costs for a 100 million gallon per year 

plant compared to crop residues As a result the secondary storage and transportation costs are 

estimated to be $9 per ton lower than crop residue such as corn stover. Thus, we estimate that 

cellulosic feedstock costs sourced from switchgrass would be about $77 per dry ton. Table 4.1­

17 contains a summary of our feedstock cost estimate for switchgrass. 

535 
 

 

 

 

 

 

 

 

 

 

Table 4.1-17. Switchgrass Cost Summary 

Farm-Set Size, acres 400 

Tons per Farm-Set, t 1,891,000 

Farmer/Grower $/t 10.00 

Nutrient Replace $/t 11.81 

Shred $/t 4.80 

Rake $/t 3.95 

Bale $/t 10.84 

Haul – Edge $/t 2.81 

Total Farm Edge Cost $/t 44.20 

Haul – SS $/t 15.3 

Storage $/t 7.89 

Haul to Ethanol Plant $/t 9.76 

Field to Plant – Total $/t 32.95 

Per Farm- Set – 

Total $/t 77.15 

Forestry Residue 

Harvest and transport costs for woody biomass in its different forms vary due to tract 

size, tree species, volumes removed, distance to the wood-using/storage facility, terrain, road 

condition, and other many other considerations. There is a significant variation in these factors 

within the United States, so timber harvest and delivery systems must be designed to meet 

constraints at the local level. Harvesting costs also depend on the type of equipment used, 

season in which the operation occurs, along with a host of other factors. Much of the forest 

residue is already being harvested by logging operations, or is available from milling operations. 

However, the smaller branches and smaller trees proposed to be used for biofuel production are 

not collected for their lumber so they are normally left behind. Thus, this forest residue would 

simply have to be collected and transported out of the forest, although it would still have to be 

chipped before transport to the biofuel plant. 

In general, most operators in the near future will chip at roadside in the forest, blowing 

the chips directly into a chip van. When the van is full it will be hauled to an end user's facility 

and a new van will be moved into position at the chipper. The process might change in the 

future as baling systems become economically feasible or as roll-off containers are proven as a 

way to handle logging slash. At present, most of the chipping for biomass production is done in 

connection with fuel-reduction treatments. This could change if the price of raw biomass 

increases to a point where it becomes feasible to recover logging residues associated with normal 

commercial operations. The major problem associated with collecting logging residues and 

biomass from small trees is handling the material in the forest before it gets to the chipper. 

Balers and roll-off containers offer some promise to reduce this cost. Whether the material is 

collected from a fuel-reduction treatment or a commercial logging operation, chips from residues 

536 
 

 

will be dirty and will require screening or some type of filtration at the end-user's 

facility.DDDDDDDDD 

Results from a study in South Georgia show that under the right conditions, a small 

chipper can be added to a larger operation to obtain additional chip production without adversely 

impacting roundwood production, and chips can be produced from limbs and tops of harvested 

trees at costs ranging from $11 per ton and up. Harvesting understory (the layer formed by 

grasses, shrubs, and small trees under the canopy of larger trees and plants) for use in making 

fuel chips is about $1 per ton more expensive. 

Per ton costs decrease as the volume chipped increases per acre. Some estimates suggest 

that if no more than 10 loads of roundwood are produced before a load of chips is made, that 

chipper-modified system could break even. Cost projections suggest that removing only limbs 

and tops may be marginal in terms of cost since one load of chips is produced for about every 15 

loads of roundwood. 

Instead of conducting our own detailed cost estimate for making forest residue chips 

available at the edge of the harvested forests, we instead relied upon the expertise of the U.S. 

forest service. The U.S. Forest Service provided us a cost curve for different categories of forest 

residue, including logging residue, other removals (i.e., clearing trees for new building 

construction), timberland trimmings (forest fire prevention strategy) and mill residues.907 The 

data was provided to us on a county-by-county basis. The national forest lands are omitted from 

consideration, and the urban forest residue is not considered here, but in the section discussing 

MSW. The information was also provided at different price points. The quantities of forest 

residue is summarized by source type in Tables 4.1-18, 4.1-19 and 4.1-20. To avoid presenting a 

huge amount of data, we aggregated the county data by state, and we are presenting the data at 

specific price points: $30/dry ton, $45/dry ton and $70/dry ton. 

DDDDDDDDD Personal Communication, Eini C. Lowell, Research Scientist, USDA Forest Service 

537 
 

Table 4.1-18. 

Volume of Forest Residue Available for Producing Biofuel 

Biomass Available at $30/ton (dry tons) 

Logging 

Residue 

Other 

Removals 

Timberland 

Thinnings 

Primary 

Mill Residue 

Total 

Quantity 

Alabama 2,405,083 507,240 867,038 7,117 3,786,478 

Arizona 17,698 44,871 66,171 1,351 130,091 

Arkansas 1,703,543 770,985 738,165 12,889 3,225,582 

California 669,740 0 1,742,702 65,088 2,477,530 

Colorado 18,405 14 0 2,302 20,721 

Connecticut 8,391 30,678 20,929 3,949 63,948 

Delaware 30,101 24,218 9,835 0 64,155 

Florida 1,070,430 515,407 481,893 2,202 2,069,932 

Georgia 3,113,907 993,262 1,107,254 45,138 5,259,561 

Idaho 253,145 0 83,095 6,006 342,247 

Illinois 278,202 235,178 230,863 18,523 762,766 

Indiana 562,483 104,173 396,225 10,627 1,073,508 

Iowa 112,098 55,160 97,983 159 265,400 

Kansas 14,658 88,405 19,353 8,720 131,136 

Kentucky 1,027,977 664,358 689,896 55,196 2,437,427 

Louisiana 2,634,279 880,585 601,848 30,075 4,146,788 

Maine 2,412,877 940 160,628 42,483 2,616,927 

Maryland 181,443 830 81,988 17,067 281,327 

Massachusetts 70,921 62,087 27,602 0 160,610 

Michigan 758,926 244,952 655,280 13,763 1,672,922 

Minnesota 697,614 662,985 265,424 26,878 1,652,900 

Mississippi 3,097,069 710,142 850,688 95,138 4,753,038 

Missouri 774,868 530,292 684,154 79,787 2,069,100 

Montana 262,670 0 133,185 9,136 404,990 

Nebraska 21,145 18,771 23,414 4,971 68,302 

Nevada 29 105 0 0 134 

New Hampshire 314,642 348 95,604 7,019 417,613 

New Jersey 5,918 77 4,847 1,437 12,279 

New Mexico 23,858 2,557 51,796 4,902 83,113 

New York 734,006 109,342 326,672 27,390 1,197,410 

North Carolina 2,026,330 1,259,265 1,121,627 12,811 4,420,033 

North Dakota 2,906 15,202 7,644 265 26,017 

Ohio 370,795 18,106 167,351 22,600 578,853 

Oklahoma 347,738 197,587 106,086 495 651,906 

Oregon 1,520,552 63 1,055,405 16,316 2,592,335 

Pennsylvania 1,087,327 1,372 449,956 170,972 1,709,626 

Rhode Island 1,769 45,721 5,600 389 53,478 

South Carolina 1,429,102 696,577 603,700 1,051 2,730,431 

South Dakota 13,944 28,873 5,986 2,294 51,096 

Tennessee 633,412 489,840 847,812 187,583 2,158,647 

Texas 1,233,553 436,927 371,437 3,021 2,044,938 

Utah 5,946 0 19,817 4,437 30,200 

Vermont 209,752 37,304 96,790 0 343,845 

Virginia 1,483,346 813,600 873,740 39,366 3,210,052 

Washington 1,282,288 44 1,850,958 21,446 3,154,736 

West Virginia 976,712 49,428 323,306 118,779 1,468,225 

Wisconsin 1,137,600 982,264 520,587 60,410 2,700,862 

Wyoming 22,685 0 28,100 34,014 84,799 

Total 37,061,885 12,330,137 18,970,435 1,295,560 69,658,018 

538 
Table 4.1-19. 

Tons of Forest Residue Available for Producing Biofuel 

Biomass Available at $45/ton (dry tons) 

Logging 

Residue 

Other 

Removals 

Timberland 

Thinnings 

Primary 

Mill Residue 

Total 

Quantity 

Alabama 2,405,083 507,240 1,012,090 7,117 3,931,530 

Arizona 27,131 49,020 69,934 1,351 147,436 

Arkansas 1,703,543 770,985 858,827 12,889 3,346,244 

California 1,166,955 0 1,898,937 65,088 3,130,980 

Colorado 20,112 22 61,238 2,302 83,674 

Connecticut 8,601 32,190 20,929 3,949 65,670 

Delaware 35,863 28,290 13,400 0 77,554 

Florida 1,070,430 515,407 533,194 2,202 2,121,234 

Georgia 3,113,907 993,262 1,288,591 45,138 5,440,898 

Idaho 432,605 0 105,188 6,006 543,799 

Illinois 278,305 235,178 230,863 18,523 762,869 

Indiana 562,928 104,173 443,691 10,627 1,121,419 

Iowa 112,100 55,215 99,102 159 266,576 

Kansas 14,658 88,405 19,353 8,720 131,136 

Kentucky 1,027,977 664,358 814,743 55,196 2,562,273 

Louisiana 2,634,279 880,585 661,023 30,075 4,205,963 

Maine 2,561,023 989 204,885 42,483 2,809,379 

Maryland 189,159 842 81,988 17,067 289,054 

Massachusetts 78,254 66,382 27,602 0 172,239 

Michigan 783,465 257,201 820,603 13,763 1,875,033 

Minnesota 717,037 683,787 319,980 26,878 1,747,683 

Mississippi 3,097,069 710,142 935,870 95,138 4,838,219 

Missouri 774,868 530,292 932,163 79,787 2,317,110 

Montana 431,194 0 141,549 9,136 581,879 

Nebraska 21,419 18,867 23,414 4,971 68,672 

Nevada 44 142 0 0 186 

New Hampshire 331,037 395 115,132 7,019 453,583 

New Jersey 6,368 79 4,847 1,437 12,731 

New Mexico 34,478 2,575 53,724 4,902 95,679 

New York 768,914 113,104 379,391 27,390 1,288,799 

North Carolina 2,026,330 1,259,265 1,336,840 12,811 4,635,245 

North Dakota 2,907 15,202 7,644 265 26,018 

Ohio 372,045 18,139 177,144 22,600 589,927 

Oklahoma 347,738 197,587 125,400 495 671,220 

Oregon 2,502,187 68 1,095,253 16,316 3,613,824 

Pennsylvania 1,092,836 1,386 604,355 170,972 1,869,549 

Rhode Island 1,913 50,079 5,600 389 57,981 

South Carolina 1,429,102 696,577 704,036 1,051 2,830,767 

South Dakota 23,743 31,161 6,505 2,294 63,704 

Tennessee 633,412 489,840 1,015,395 187,583 2,326,230 

Texas 1,233,553 436,927 438,374 3,021 2,111,876 

Utah 7,515 0 21,571 4,437 33,524 

Vermont 217,084 38,363 107,673 0 363,120 

Virginia 1,483,346 813,600 1,048,745 39,366 3,385,057 

Washington 2,135,174 46 1,963,678 21,446 4,120,344 

West Virginia 976,712 49,428 482,367 118,779 1,627,287 

Wisconsin 1,153,876 998,604 654,054 60,410 2,866,943 

Wyoming 36,327 0 36,405 34,014 106,745 

Total 40,084,609 12,405,402 22,003,291 1,295,560 75,788,862 

539 
Table 4.1-20. 

Tons of Forest Residue Available for Producing Biofuels 

Biomass available at $70/ton (dry tons) 

Logging 

Residue 

Other 

Removals 

Timberland 

Thinnings 

Primary 

Mill Residue 

Total 

Quantity 

Alabama 2,405,083 507,240 1,163,309 7,117 4,082,749 

Arizona 27,131 49,020 77,357 1,351 154,859 

Arkansas 1,703,543 770,985 984,188 12,889 3,471,605 

California 1,166,955 0 2,001,231 65,088 3,233,274 

Colorado 20,112 22 61,238 2,302 83,674 

Connecticut 8,601 32,190 20,929 3,949 65,670 

Delaware 35,863 28,290 13,400 0 77,554 

Florida 1,070,430 515,407 664,706 2,202 2,252,745 

Georgia 3,113,907 993,262 1,553,823 45,138 5,706,130 

Idaho 432,605 0 123,852 6,006 562,463 

Illinois 278,305 235,178 230,863 18,523 762,869 

Indiana 562,928 104,173 443,691 10,627 1,121,419 

Iowa 112,100 55,215 99,102 159 266,576 

Kansas 14,658 88,405 19,353 8,720 131,136 

Kentucky 1,027,977 664,358 927,808 55,196 2,675,339 

Louisiana 2,634,279 880,585 750,104 30,075 4,295,044 

Maine 2,561,023 989 332,233 42,483 2,936,728 

Maryland 189,159 842 81,988 17,067 289,054 

Massachusetts 78,254 66,382 27,602 0 172,239 

Michigan 783,465 257,201 1,066,214 13,763 2,120,643 

Minnesota 717,037 683,787 401,197 26,878 1,828,900 

Mississippi 3,097,069 710,142 1,033,196 95,138 4,935,545 

Missouri 774,868 530,292 1,287,857 79,787 2,672,803 

Montana 431,194 0 166,045 9,136 606,375 

Nebraska 21,419 18,867 23,414 4,971 68,672 

Nevada 44 142 0 0 186 

New Hampshire 331,037 395 116,195 7,019 454,646 

New Jersey 6,368 79 4,847 1,437 12,731 

New Mexico 34,478 2,575 64,375 4,902 106,330 

New York 768,914 113,104 385,701 27,390 1,295,109 

North Carolina 2,026,330 1,259,265 1,600,910 12,811 4,899,315 

North Dakota 2,907 15,202 7,644 265 26,018 

Ohio 372,045 18,139 177,144 22,600 589,927 

Oklahoma 347,738 197,587 163,268 495 709,088 

Oregon 2,502,187 68 1,133,187 16,316 3,651,758 

Pennsylvania 1,092,836 1,386 680,995 170,972 1,946,189 

Rhode Island 1,913 50,079 5,600 389 57,981 

South Carolina 1,429,102 696,577 791,111 1,051 2,917,842 

South Dakota 23,743 31,161 8,258 2,294 65,457 

Tennessee 633,412 489,840 1,033,100 187,583 2,343,935 

Texas 1,233,553 436,927 507,340 3,021 2,180,841 

Utah 7,515 0 29,434 4,437 41,386 

Vermont 217,084 38,363 142,210 0 397,658 

Virginia 1,483,346 813,600 1,260,733 39,366 3,597,045 

Washington 2,135,174 46 2,059,970 21,446 4,216,636 

West Virginia 976,712 49,428 575,278 118,779 1,720,198 

Wisconsin 1,153,876 998,604 841,550 60,410 3,054,440 

Wyoming 36,327 0 43,195 34,014 113,536 

Total 40,084,609 12,405,402 25,186,746 1,295,560 78,972,317 

540 
 

The U.S. Forestry Service recommended that we choose $45 per dry ton as the price 

point for our cost analysis.908 This seemed reasonable since this price point was roughly the 

same as farm gate crop residue discussed above, and so we used this price point for our analysis 

Assuming that the wood chips would be ground further in the field adds an additional $11 per 

dry ton to the feedstock cost. 

Delivery of woody biomass from the harvesting site to a conversion facility, like delivery 

of more conventional forest products, accounts for a significant portion of the delivered cost. In 

fact, transportation of wood fiber (including hauling within the forest) accounts for about 25 to 

50 percent of the total delivered costs and highly depends on fuel prices, haul distance, material 

moisture content, and vehicle capacity and utilization. Also, beyond a certain distance, 

transportation becomes the limiting factor and the costs become directly proportional to haul 

distance.EEEEEEEEE We used the Class 8 over-the-road hauling costs estimated in Table 4.1-15 for 

estimating the hauling costs for forest residue. As a feedstock, forest residue is expected to be 

available at a higher density per area than corn stover. Thus, its hauling costs would potentially 

be lower than those for corn stover because the forest residue would be hauled a shorter distance. 

However, forest residue is often located in more remote locations, so it may have to be hauled a 

further distance to reach the plant site. We anticipate hauling forest residue to a plant will cost 

about $14 per ton. Totalling up the feedstock cost at the forest edge, the grinding cost and the 

hauling costs results in a total delivered price of $70 per dry ton. 

Municipal Solid Waste 

Million of tons of municipal solid waste (MSW) continue to be disposed of in landfills across 

the country, despite recent large gains in waste reduction and diversion. The biomass fraction of 

this total stream represents a potentially significant resource for renewable energy (including 

electricity and biofuels). Because this waste material is already being generated, collected and 

transported (it would solely need to be transported to a different location), its use is likely to be 

less expensive than other cellulosic feedstocks. One important difficulty facing those who plan 

to use MSW fractions for fuel production is that in many places, even today, MSW is a mixture 

of all types of wastes, including biomaterials such as animal fats and grease, tin, iron, aluminum, 

and other metals, painted woods, plastics, and glass. Many of these materials can’t be used in 

biochemical and thermochemical ethanol production, and, in fact, would inflate the 

transportation costs, impede the operations at the cellulosic ethanol plant and cause an expensive 

waste stream for biofuel producers. 

Thus, accessing sorted MSW would likely be a requirement for firms planning on using 

MSW for producing cellulosic biofuels. In a confidential conversation, a potential producer who 

plans to use MSW to produce ethanol indicated that their plant plans are based on the obtaining 

cellulosic biowaste which has already been sorted at the waste source (e.g., at the curbside, 

where the refuse hauler picks up waste already sorted by the generating home-owner or 

business). For example, in a tract of homes, one refuse truck would pick up glass, plastic, and 

perhaps other types of waste destined for a specific disposal depot, whereas a different truck 

EEEEEEEEE Ashton, S.; B. Jackson; R. Schroeder. Cost Factors in Harvesting and Transporting Woody Biomass, 

2007. Module 4: Introduction to Harvesting, Transportation, and Processing :: Fact Sheet 4.7 

541 
would follow to pick up wood, paper, and other cellulosic materials to be hauled to a depot that 

supplies an ethanol plant. However, only a small fraction of the MSW generated today is sorted 

at the curbside. 

Another alternative would be to sort the waste either at a sorting facility, or at the landfill, 

prior to dumping. There are two prominent options here. The first is that there is no sorting at 

the waste creation site, the home or business, and thus a single waste stream must be sorted at the 

facility. This operation would likely be done by hand or by automated equipment at the facility. 

To do so by hand is very labor intensive and somewhat slower than using an automated system. 

In most cases the ‘by-hand’ system produces a slightly cleaner stream, but the high cost of labor 

usually makes the automated system more cost-effective. Perhaps the best approach for low cost 

and a clean stream is the combination of hand sorting with automated sorting. 

The third option is a combination of the two which requires that there is at least some 

sorting at the home or business which helps to prevent contamination of the waste material, but 

then the final sorting occurs downstream at a sorting site, or at the landfill. 

We have little data and few estimates for the cost to sort MSW. One estimate we 

generated within our Office of Solid Waste for a combination of mechanically and manually 

sorting a single waste stream downstream of where the waste is generated puts the cost in the 

$20 to $30 per ton range. There is a risk, though, that the waste stream could still be 

contaminated and this would increase the cost of both transporting and using this material at the 

biofuel plant due to the toxic ash produced which would require disposal at a toxic waste facility. 

If a less contaminated stream is desired it would probably require sorting at the generation site – 

the home or business - which would likely be more costly since many more people in society 

would then have to be involved and special trucks would need to be used. Also, widespread 

participation is difficult when a change in human behavior is required as some may not be so 

willing to participate. Offering incentives could help to speed the transition to curbside recycling 

(i.e., charging fee for nonsorted waste, or paying a small amount for sorted tree trimmings and 

construction and demolition waste). Assuming that curbside sorting is involved, at least in a 

minor way, total sorting costs might be in the $30 to $40 per ton range. We request comment on 

the costs incurred for sorting cellulosic material from the rest of MSW waste. 

These sorting costs would be offset by the cost savings for not disposing of the waste 

material. Most landfills charge tipping fees, the cost to dump a load of waste, a societal cost that 

would be avoided. In the United States, the national average nominal tipping fee increased 

fourfold from 1985 to 2000. The real tipping fee almost doubled, up from a national average (in 

1997 dollars) of about $12 per ton in 1985 to just over $30 in 2000. Equally important, it is 

apparent that the tipping fee is much higher in densely populated regions. For example, in 2004, 

the trend differed by municipality level, from $9 a ton in Denver to $97 in Spokane. Statewide 

averages also varied widely, from $8 a ton in New Mexico to $75 in New Jersey. Tipping fees 

ranged from $21 to 98 per ton in 2006 for MSW and $18/ton to $120/ton for construction and 

demolition waste. It is likely that the tipping fees are highest for waste contaminated by toxic 

materials that require the disposal at Resource Conservation and Recovery Act (RCRA) certified 

toxic waste sites as opposed to a composting site. However, this same contaminated material 

would not be desirable to biofuel producers. Presuming that only the noncontaminated cellulosic 

542 
 

 

 

waste (yard trimmings, building construction and demolition waste and some paper) is collected 

as feedstocks for biofuel plants, the handling and tipping fees are likely much lower, in the $30 

per ton range.FFFFFFFFF 

The avoidance of tipping fees, however, is a complex issue since landfills are generally 

not owned by municipalities anymore. Both large and small municipalities recognized their 

inability to handle the new and complex solid waste regulations at a reasonable cost. Only 38 

out of the 100 largest cities own their own landfills. To deal with the solid waste, large private 

companies built massive amounts of landfill capacity. The economic incentive is for private 

landfill operators to fill their landfills with garbage as early as possible to pay off their capital 

investment (landfill site) quickly. Also, the longer the landfill is operating the greater is its 

exposure to liability due to leakages and leaching. Furthermore, landfills can more costeffectively manage the waste as the scale of the landfill is enlarged. As a result, there are fewer 

landfills and landfill owners, and an expansion of market share by large private waste 

management firms, thus decreasing the leverage an ethanol producer may have.GGGGGGGGG 

Hence, MSW-ethanol plants could be opposed by landfill operators. This may also be true in the 

case of a waste-to-energy (WTE) facility, which burns as much garbage as possible to produce 

electricity. For sustainable operation, a certain amount of daily waste supply should be 

guaranteed. A MSW-ethanol plant may therefore be seen as an unwelcome competition to both 

landfill owners and WTE facilities. This competition may increase the cost of cellulosic biomass 

to the biofuel producers. We request comment on the costs avoided for diverting cellulosic 

material from landfills and WTE facilities. 

Once the cellulosic biomass has been sorted from the rest of MSW, it would have to be 

transported to the biofuels plant. Transporting is different for MSW biomass compared to forest 

and crop residues. Forest and crop residues are collected from a forests and farms, which are 

both rural sites, and transported to the biofuel plant which likely is located at a rural site. The 

trucks which transport the forest and crop residues can be large over-the-road trucks which can 

average moderate speeds because of the lower amount of traffic that they experience. 

Conversely, MSW is being collected from throughout the urban areas and would have to 

transported through those urban areas to the plant site. If the cellulosic biomass is being 

collected at curbside, it would likely be collected in more conventional refuse trucks. If the plant 

is nearby, then the refuse trucks could transport the cellulosic biomass directly to the plant. 

However, if the plant is located far away from a portion of the urban area, then the refuse trucks 

would probably to be offloaded to more conventional over-the-road trucks with sizable trailers to 

make transport more cost-effective. We believe that in most cases, MSW will be transported by 

class 8, over-the-road trucks with operating characteristics like those summarized in Table 4.1­

15. The trucks would likely need to pick up the sorted MSW at a MSW sorting facility and haul 

the MSW to the cellulosic biofuel plant. The cellulosic biofuel plant would likely be located on 

the outskirts of the medium or large city, and so the MSW feedstock would have to be hauled 

through the urban area to reach the plant. Some of the trucks may not have to travel very far and 

would avoid most of the urban traffic since the MSW would be available on the same side of city 

FFFFFFFFF A much more thorough analysis of tipping fees by waste type is planned for the final rulemaking analysis. GGGGGGGGG Osamu Sakamoto, The Financial Feasibility Analysis of Municipal Solid Waste to Ethanol Conversion, 

Michigan State University, Plan B Master Research Paper in partial fulfillment of the requirement for the degree of 

Master of Science, Department of Agricultural Economics, 2004 

543 
as the plant. However, another portion of the MSW may be located on the opposite side of city 

from the plant and the trucks may have to endure significant traffic from time-to-time. We 

estimate that the cost to transport the cellulosic biomass sourced from MSW to the biofuel plant 

would average $15 per ton. 

Cellulosic biomass sourced from MSW can be generated year-round in many parts of the 

U.S. If a steady enough stream of this material is available, then secondary storage would not be 

necessary, thus avoiding the need to install secondary storage. We assumed that no secondary 

storage costs would be incurred for MSW-sourced cellulosic biomass. 

The total costs for MSW-sourced cellulosic biomass is estimated to be $30 -$40 per ton 

for sorting costs, $30 per ton for tipping costs avoided, $15 per ton for transportation costs and 

$11 per ton for grinding the cellulose to prepare it as a feedstock - resulting in a total feedstock 

cost of $26 to $36 per ton. In our cost analysis, we assumed an average cost of $31 per ton. 

Table 4.1-21 below summarizes major cost components for each cellulosic feedstock.. 

Table 4.1-21. 

Summary of Cellulosic Feedstock Costs ($53/bbl crude oil costs) 

Ag Residue Switchgrass Forest Residue MSW 

60% of Total 

Feedstock 

1% of total 

Feedstock 

25% of Total 

Feedstock 

14% of Total 

Feedstock 

Mowing, 

Raking, Baling, 

Hauling, 

Nutrients and 

Farmer 

Payment 

$43/ton 

Mowing, 

Raking, Baling, 

Hauling, 

Nutrients and 

Farmer 

Payment 

$42/ton 

Harvesting, 

Hauling to 

Forest Edge, 

Chipping 

$45/ton 

Sorting, 

Contaminant 

Removal, 

Tipping Fees 

Avoided $0 – 

$10/ton 

Hauling to Hauling to Grinding, Grinding, 

Secondary Secondary Hauling to Hauling to 

Storage, Storage, Plant $25/ton Plant $26/ton 

Secondary Secondary 

Storage, Storage, 

Hauling to Hauling to 

Plant $45/ton Plant $37/ton 

Total $88/ton Total $77/ton Total $70/ton Total Avg 

$31/ton 

Weighting the cellulosic feedstock costs by their supply quantities results in an average 

cellulosic feedstock cost of $71 per ton which we used at the reference crude oil price of $53/bbl. 

We also estimated the feedstock costs assuming that crude oil is priced at $92/bbl. We 

adjusted the transportation costs higher by 10 percent based on our analysis of how ethanol 

544 
distribution costs would be affected by the higher crude oil price. We adjusted the farm gate 

costs upwards by about $2 per ton based on FASOM agricultural market modeling at the higher 

crude oil price. We also increased grinding costs upwards by 10 percent. Table 4.1-22 

summarized our estimated feedstock costs at $93 per barrel crude oil prices. 

Table 4.1-22. 

Summary of Cellulosic Feedstock Costs ($92/bbl crude oil costs) 

Ag Residue Switchgrass Forest Residue MSW 

60% of Total 

Feedstock 

1% of total 

Feedstock 

25% of Total 

Feedstock 

14% of Total 

Feedstock 

Mowing, 

Raking, Baling, 

Hauling, 

Nutrients and 

Farmer 

Payment 

$45/ton 

Mowing, 

Raking, Baling, 

Hauling, 

Nutrients and 

Farmer 

Payment 

$42/ton 

Harvesting, 

Hauling to 

Forest Edge, 

Chipping 

$47/ton 

Sorting, 

Contaminant 

Removal, 

Tipping Fees 

Avoided $3 – 

$13/ton 

Hauling to Hauling to Grinding, Grinding, 

Secondary Secondary Hauling to Hauling to 

Storage, Storage, Plant $28/ton Plant $28/ton 

Secondary Secondary 

Storage, Storage, 

Hauling to Hauling to 

Plant $49/ton Plant $39/ton 

Total $94/ton Total $77/ton Total $75/ton Total Avg 

$36/ton 

We estimate that at the crude oil price of $92 per barrel, the average feedstock cost 

increases to $76 per ton 

Cellulosic Ethanol Production Costs 

We contracted with the National Renewable Energy Laboratory (NREL) to estimate the 

cost to convert corn stover into ethanol for the years 2010, 2015, and 2022. It is of particular 

importance for the following discussion, to note the following: NREL used the same feedstock 

mass (772,168 dry tons of corn stover) in all three cases. 

For the three cases, NREL assumed the feedstock, ‘as-needed,’ was hauled to the plant by 

trucks and trailers from satellite storage, already shredded to the appropriate size for processing, 

and free of dirt, iron, and other contaminates; in other words – process ready. The transport 

vehicles were unloaded into surge tanks, large enough to hold feedstock for three days of 

operation. The pretreatment and hydrolysis reactors are charged from these feed surge tanks. 

545 
 

 

The following is background information for our discussion of both operating and capital 

costs, some of which is also included in our brief discussion of the process flow description and 

capital equipment charges. The first step was to develop a set of process flow diagrams that set 

the arrangement of the equipment. Based on the desired production volume, these diagrams, 

were used within an ASPEN Plus4© model to develop complete mass and energy balance. The 

model consists of 164 unit operation blocks, 457 streams (247 material and 210 heat or work), 63 

components, and 82 control blocks. 

The overall model is thermodynamically rigorous and uses physical properties for the 

feedstock and process chemicals included in the ASPEN software as well as property data 

developed at NREL. The individual unit models are also thermodynamically consistent and can 

be either rigorous (for example, the simulation of the distillation) or simple. The reactors could 

be modeled with kinetic expressions, but because of the level of development of the 

experimental data, they were modeled as experimentally determined conversions of specific 

reactions. This type of model still satisfies the rigorous mass and energy balance. Other unit 

operations, such as liquid-solid separations, are typically modeled with fixed solids removal and 

liquid retention (in the solids stream) data from vendor tests.HHHHHHHHH Using the process flow 

diagrams and the mass and energy balance information, NREL estimated stream flows and 

conditions, along with the estimated quantities of raw materials and other process chemicals. 

The following table presents NREL’s summary of each of the three year’s total project 

investment. For each year’s total project investment, NREL provided capital charge, which 

includes income tax, depreciation, and average return on investment, the cost of raw materials, 

waste handling charges, and by-product credits. 

HHHHHHHHH A. Aden, M. Ruth, K. Ibsen, J. Jechura, K. Neeves, J. Sheehan, and B. Wallace 

National Renewable Energy Laboratory (NREL); L. Montague, A. Slayton, and J. Lukas Harris Group, Seattle, 

Washington, Ethanol Process Design and Economics Utilizing Co-Current Dilute Acid Prehydrolysis and Enzymatic 

Hydrolysis for Corn Stover; June 2002; NREL is a U.S. Department of Energy Laboratory Operated by Midwest 

Research Institute • Battelle • Bechtel; Contract No. DE-AC36-99-GO10337 

546 
 

 

 

Table 4.1-23. Summary of NREL’s Capital Charges and Operating Costs 

Year Technology 2010 2015 2022 

Plant Size 

MMgal/yr 56 69 71 

Capital Cost $MM 

(TPI) 232 220 199 

 $MM/yr ¢/gal $MM/yr ¢/gal $MM/yr ¢/gal 

Capital Charge 

10% after tax ROI 42 75 39 56 35 50 

Fixed Costs 9 16 9 12 8 12 

Feedstock Cost 84 46 51 35 50 35 

Other Raw Matl. 

Costs 17 30 4 5 16 16 

Enzyme Cost 18 32 7 10 5 8 

Enzyme Nutrients 8 14 2 3 2 2 

Electricity -6 -10 -7 -9 -12 -16 

Waste Disposal 1 2 3 4 1 1 

Total Costs 173 205 108 116 105 108 

The quantities of all raw material, generated electricity, and produced wastes were 

determined using the ASPEN mass and energy balance model. These costs include: Feedstock – 

corn stover, CSL – purchased corn steep liquor (a nutrient); Cellulase – purchased cellulase 

enzymes; Other Raw Materials – sulfuric acid, diammonium phosphate, make-up water, boiler 

feed water chemicals, cooling water chemicals. Waste Disposal – waste water chemicals, waste 

water polymers, ash disposal, gypsum disposal. Electricity – marketing and distribution of 

surplus electricity to the grid for credit. 

We note that the percent change in total project investment from year to year is not 

insignificant and reflects improvements in mechanical process efficiencies among other general 

improvements in the process technology, including the automatic distributed process control 

system, all of which are off-set to some extent by increases in the real cost of the technology 

improvements, as well as those of constructions materials. We discuss capital costs following 

this discussion of operating costs. 

The most notable reductions in NREL’s operating costs are in the price per dry ton of the 

corn stover feedstock and in the cost of cellulase enzyme. NREL anticipates significant 

improvement in the efficiency of these enzymes, especially those that saccharify glucan to 

547 
 

 

 

glucose and xylose oligomersIIIIIIIII generated during hydrolysis. They also expect improvement 

in the yeasts that ferment xylose. According to the 2007 NREL – State of Technology report, 

they anticipate that as a first step,,the relationship between corn stover hydrolysate conditioning 

and fermentation will be better defined and understood. Commercial cellulase preparations will 

continue to be analyzed for baseline performance (specific activity), and due to increased 

research efforts, cellulase function will be better understood, which should lead to efficiency 

improvements. Integrated testing of whole slurry and recycle options will also be conducted 

resulting in potential improvements in that area. Last, the efficacy of advanced enzyme 

preparations (including oligomerases and/or hemicellulases) will continue to be tested in 

conjunction with alternative pretreatment technologies. NREL expects that the cost of 

pretreatment will deminish, hydrolysis time will decrease, and the sugar (xylose and glucose) 

yields will increase.JJJJJJJJJ 

As the process costs decline over time, the feedstock costs become a larger fraction of the 

overall costs. We also note that in the following table that the cost of the feedstock makes up 

50% of the total cost in 2010; 67% in 2015; and 68% in 2022. The reduction in feedstock cost, 

from $60 per dry ton in 2010, to $45.90 per dry ton in both 2015 and 2022 also has a significant 

effect on operating costs. In addition, NREL did not include payments to the farmers/growers 

nor for soil nutrients (fertilizer, etc.) that were removed with the harvested corn stover. The cost 

of the cellulase enzyme is the next highest contributor, with percent reductions contributed to 

total cost that reduced from ~19% in 2010, to 13% in 2015 and 10% in 2022. It should be 

obvious that any reductions in these costs have significant effects on the total operating cost. 

The majority of research going forward will be focused on these two items, although some work 

will be done to reduce the cost of the others. Table 4.1-24 summarizes NREL’s operating costs 

for a biochemical cellulosic ethanol plant. 

IIIIIIIII Xylan polymer chains, with considerably fewer residue numbers in the chain than were in the original xylan 

polymer; they were broken off the polymer as these short chains rather than as single molecule sugars. 

JJJJJJJJJ Andy Aden, National Renewable Energy Laboratory, Golden, Colorado, Biochemical Production of Ethanol 

from Corn Stover: 2007 State of Technology Model, Technical Report NREL/TP-510-43205, Task No. BB07.2410; 

May 2008 

548 
 

 

 

Table 4.1-24. 

Percent of the total operating cost for each actual operating cost item

 2010 2015 2022

 ¢/gal % of 

Total ¢/gal % of Total ¢/gal % of Total 

Feedstock 84 50 51 67 50 68 

Biomass to 

Boiler 0.0 0.0 0.0 0.0 0.0 0.0 

CSLa 14 8 3 4 2 3 

Cellulase 32 19 9 13 8 10 

Other Raw 

Matl. Costs 31 18 5 7 16 22 

Waste Disposal 2 1 4 5 2 2 

Electricity -10 -6 -9 -12 -16 -22 

Fixed Costs 16 10 12 16 12 16 

168 76 72 

a

Corn steep liquor – provides nutrients for the enzymes. 

The following table includes our adjustments to NREL’s variable or operating cost data 

for the three years studied. We note that the two main differences between NREL’s and our 

estimates are in the feedstock costs and in the way we calculate capital charges. We adjusted 

NREL’s capital charges which were calculated using a 10% after tax return on investment, to 

reflect a 7 percent before tax rate of return, which is the capital cost basis for our cost analyses. 

We also adjusted the NREL feedstock costs to those that we estimated in Table 4.1-21, which 

was $71.23 per ton. This significant difference between their and our feedstock cost estimates is 

due to our including payments to farmers/growers plus covering the cost to replace nutrients 

(fertilizer, etc.) removed at the time the stover was harvested. According to a personal 

communication, NREL used unpublished data from the Idaho National Laboratory that indicate 

feedstock costs will be significantly reduced between 2010 and 2015. 

549 
 

 

 

 

Table 4.1-25. Adjusted Capital Charges and Operating Costs 

Year 

Technology 2010 2015 2022 

Plant Size 

MMgal/yr 56 69 71 

Capital Cost $MM 232 220 199 

 $MM/yr ¢/gal $MM/yr ¢/gal $MM/yr ¢/gal 

Capital Cost 7% 

ROI before taxes 25 46 24 35 22 31 

Fixed Costs 9 16 9 12 8 12 

Feedstock Cost 55 99 55 79 55 77 

Other Raw Matl. 

Costs 17 30 4 5 16 16 

Enzyme Cost 18 32 7 10 5 8 

Enzyme Nutrients 8 14 2 3 2 2 

Electricity -6 -10 -7 -9 -12 -16 

Waste Disposal 1 2 3 4 1 1 

Total Costs 127 229 96 139 84 131 

The changes in the minimum ethanol selling prices for the three years studied are 

partially due to the changes in necessary capital investments. In order to determine capital costs, 

NREL developed specifications pieces of equipment that fall within different areas of a 

biochemical plant. A biochemical plant is divided up into 8 different areas (Area 200 through 

Area 900)._ For each equipment specification, they developed individual purchased equipment 

and installation costs. Vendors supplied installation costs where possible; in other cases 

installation factors were used. Equipment costs were obtained from vendor quotations when 

possible, especially for uncommon equipment such as pretreatment reactors. These costs reflect 

the base case for which the equipment was designed. If process changes were made and the 

equipment size changed, the equipment is not generally re-costed, in detail. Rather, the cost was 

adjusted by scaling using the following exponential scaling expression, [New Cost = Original 

Cost x (New Size/Original Size)^exp]. They also scaled the size of equipment that was known to 

change linearly with a change in inlet flow. The scaling exponents (exp) were obtained from 

vendor quotes, or from a standard reference, such as Garrett.KKKKKKKKK 

KKKKKKKKK Garrett, D.E., Chemical Engineering Economics, Van Nostrand Reinhold, New York, 1989 

550 
Installation costs were taken primarily from Delta-T, a process consultant’s experience. 

Once the scaled, installed equipment costs (total installed capital costs) were determined, they 

applied overhead and contingency factors to determine a total plant investment cost. That cost, 

along with the plant operating expenses (generally developed from the ASPEN model) was used 

in a discounted cash flow analysis to determine the cost of ethanol production, using a set 

discount rate. NREL use a discount rate of 10%, whereas we used 7%, a factor generally used in 

our financial calculations. For this analysis, the minimum ethanol selling price was the primary 

value used to compare cases. 

The total project investment was briefly discussed previously in our summary discussion 

of operating costs; we used NREL’s total project investment for our estimates. The following 

summarizes the capital expenditures that account for that capital investment. 

Area 200: Pretreatment and Hydrolysis. The equipment in this area consists of an 

assortment of pipe, pumps, tanks, tank-agitators, tank-mixers, coolers, 3-pneumapress filters, as 

well as three separate process trains, each of which includes a presteamer, a blow tank, and a 

reactor. The presteamer uses low-pressure steam to heat the feedstock to about 212 oF. It 

discharges the hot, saturated mix into a blow tank that serves as a seal between the presteamer 

and the hydrolysis reactor. The mix is charged to the reactor and dilute sulfuric acid is added; 

the reactor operates at 191 psia and 547 o

F. Most of the hemicellulose, e.g., primarily xylose, 

mannose, arabinose, and galactose are converted into sugars. Glucan in the hemicellulose and a 

small portion of the glucan in the cellulose are converted to glucose. These conditions also 

solubilize some of the lignin in the feedstock and ‘expose’ the cellulose for subsequent 

enzymatic hydrolysis, in a downstream section. In addition, acetic acid is liberated from the 

hemicellulose hydrolysis. Degradation products of pentose sugars (primarily furfural) and hexose 

sugars (primarily hydroxymethyl furfural (HMF)) are also formed. 

Following the pretreatment reactor, the hydrolyzate liquid and solids are flash cooled, 

which vaporizes a large amount of water, a portion of the acetic acid, and much of the furfural 

and HMF, which can be toxic to downstream fermentation microorganisms. 

In addition to the flash removal of aldehydes, the solids are washed and filter-pressed to 

remove the liquid portion of the hydrolyzate, which contains sulfuric acid. The liquid is then 

neutralized to pH 10 with ammonia and held until the gypsum precipitates and is filtered out. 

The hydrolyzate, which contains the hydrolyzed xylose sugars and some glucose sugars, is 

mixed back with dilution water and the filter cake, which contains the unhydrolyzed cellulose 

and is sent to saccharification and co-fermentation (Area 300) 

An important issue on an industrial scale is accurate pH control. By pH 11, as much as 

30% of the glucose may be lost to HMF and other side reactions. Several factors increase the 

probability of overshooting pH endpoints during neutralization. The natural buffering capacity 

of hydrolyzates causes neutralization reactions to be slow. Plus, measurements using pH 

membrane probes are affected by temperature and the presence of dissolved organic compounds 

(sugars and lignin). 

551 
Since we are handling the same mass of feedstock in each of the modeled years, we don’t 

expect the cost of the equipment for pretreatment and hydrolysis will change much over the 

2010-2022 time period. The equipment costs for Area 200 – Pretreatment & Hydrolysis are 

2010: $23-million; 2015: $22.7-million; and 2022: $18.9-million. Neutralization and 

Conditioning costs were separated out from the Pretreatment & Hydrolysis costs, even though 

the NREL’s design report includes both cost centers in Area 200. Neutralization and 

Conditioning costs are as follows: 2010: $8.4-million; 2015: $9.4-million; and 2022: $7.7­

million. The combined cost for Area 200 is as follows: 2010: $31.4-million; 2015: $32.1­

million; and 2022: $26.6-million. In total, this area contributed about 23.5% to the total installed 

capital cost of the project in 2010; about 25.3% in 2015; an 23.2% in 2022 

Area 300: Saccharification and Co-Fermentation. The equipment in this area consists of 

pumps, tanks, tank-agitators, coolers, and heaters. Two different operations take place in this 

process area — the saccharification of the cellulose to glucose using cellulase enzymes, and the 

fermentation to ethanol of that glucose plus the xylose and glucose sugars from the dilute acid 

pretreatment of hemicellulose from Area 200. 

Glucan from the cellulose undergoes hydrolysis or saccharification, at about 149 o

F, prior 

to fermentation. This slightly higher temperature increases enzyme activity and reduces the time 

and amount of enzyme required for saccharification. Saccharification or cellulase enzymes, 

purchased from an enzyme manufacturer, and the diluted, detoxified hydrolyzate are 

continuously added to a train of five 1-million gallon saccharification vessels; residence time is 

estimated to be 36-hours. 

Cellulase enzyme is actually a ‘cocktail’ of enzymes, comprised of: (1) endoglucanases, 

which attack randomly along the cellulose fiber to reduce polymer size rapidly; (2) 

exoglucanases, which attack the ends of cellulose fibers, allowing it to hydrolyze highly 

crystalline cellulose; and (3) β-glucosidase, which hydrolyzes cellobiose to glucose. Several 

bacteria and fungi naturally produce these enzymes, including bacteria in ruminant and termite 

guts and white rot fungus. The most common organism used to produce cellulase industrially is 

Trichoderma reesei. Genencor International and Novozymes Biotech are developing more cost 

effective cellulase enzymes. DOE is funding this important work, which should improve the 

economic viability of biomass conversion. 

The recombinant Z. mobilis bacterium is used as the biocatalyst to ferment glucoses and 

xyloses to ethanol. Several research institutions are genetically engineering strains, such as Z. 

mobilis, to treat additional sugars and identifying other naturally occurring organisms that 

metabolize hemicellulosic sugars. 

The Z. mobilis must be ‘grown’ in increasingly higher volume stages. Initially, a small 

amount of saccharified slurry and nutrients are combined in a very small vessel with a seed 

inoculum, that’s been grown in the laboratory. This initial seed batch is used as the inoculum for 

the next larger size seed batch, and so on. This series of batch scale-ups continues until the last 

batch is large enough to support the actual production fermentation. 

552 
Finally, the seed inoculum, nutrients (corn steep liquor) & (diammonium phosphate – a 

source of nitrogen for the yeast), and saccharified slurry are cooled to about 106 o

F and added to 

a train of five 1-million gallon continuous fermentors. At this point, the process actually 

becomes a simultaneous saccharification and co-fermentation (SSCF) process. Even though the 

temperature in the fermentation tanks has been reduced to account for the ethanologen’s 

intolerance to heat, the enzymes do continue to hydrolyze cellulose, albeit at a slightly reduced 

rate. The main byproduct, produced during fermentation is carbon dioxide (CO2), which is 

removed in a later process stage. The ethanol broth called ‘beer’ is collected in a storage tank, 

called a beer well, before it’s pumped to distillation. 

NREL anticipates significant capital savings for saccharification and co-fermentation 

between 2010 and 2015, with fewer between 2015 and 2022. We note that this area contributed 

15.4% to the total installed capital cost in 2010, but only 8.8% in 2015 and 8.8% in 2022. The 

equipment costs for Area 300 – Saccharification and Fermentation are 2010: $20.5-million; 

2015: $11.2-million; and 2022: $10.1-million. 

Area 400 – In earlier studies, NREL included plans to produce enzymes in Area 400. For 

the current studies, Area 400 has been removed and enzymes will be purchased and grown on 

site under licensing agreements with enzyme suppliers. 

Area 500 – Product, Solids, and Water Recovery (Distillation, Dehydration, Evaporation, 

and Solid-Liquid Separation). The equipment in this area includes distillation and rectification 

columns, pumps, condensers and coolers, pumps, pipe, filter-presses, and evaporators. 

Beer, from the beer well in Area 300, is preheated and fed to a distillation column. The 

column overhead containing all the CO2 and about 0.2% of the ethanol and a small quantity of 

water is sent to a scrubber, which recovers and recycles about 99% of the vented ethanol. In the 

tower bottoms, about 90% of the water has been removed and it contains approximately 0.7% of 

the total volume of ethanol fed to the tower. Over 99% of the total ethanol fed to the tower is 

removed as a 39.4% w/w mixture with water vapor through a side draw and fed directly to a 

rectification column for further ethanol enrichment. We discuss the distillation column bottoms 

in the evaporation and solid-liquid separation section of this area. 

The rectification tower operating conditions are set to produce an overhead 92.5% w/w 

ethanol/water saturated vapor mixture. The tower bottoms are a 0.05% w/w ethanol/water 

mixture. In fact, only 0.1% of the total ethanol from the fermentation area is lost to the bottoms. 

The rectification column overhead is superheated and fed to one of two adsorption 

columns in a molecular sieve adsorption unit. The two columns operate alternately; while one 

bed is operated to remove water from the ethanol, the other is regenerated by passing a very 

small slipstream of pure ethanol vapor back through the loaded bed that strips the water off the 

adsorbent, while the column is under a vacuum. The mixture is condensed and returned to the 

rectification column feed stream. The adsorption column removes 95% of the water and a small 

quantity of ethanol. The 99.5% pure ethanol vapor is condensed, cooled, and pumped to storage. 

553 
Evaporation, and Solid-Liquid Separation: The beer column bottoms, with about 5.8% 

insoluble solids, are fed to the first effect evaporator, where 24% of the water in the feed is 

evaporated. The evaporator bottom slurry, cooled from ~243 o

F to ~189 oF, is sent to a filterpress, from which the filtrate is returned to the second evaporator effect; the filter cake is not 

washed. In the second effect evaporator, 44% of the feed water is evaporated. The third effect 

evaporates 76% of the remaining water. The final vapor is condensed and fed to a condensate 

drum. Of the total feed to the evaporation/separation system, 10.5% remains as syrup, 11.5% is 

removed as a wet cake in the pressure filter, 17% is recycled back to the process as recycle 

water, and 61% is evaporated. The syrup from the third evaporator bottoms is 60% water, e.g., 

the maximum dissolved solids level that can be achieved without rapid fouling of the evaporator; 

the flow of very low-pressure steam to the evaporator is set to achieve this level. This syrup is 

mixed with the cake from the filter-press and sent to the combustor for disposal. Air from the 

filter-press is used for combustion air. 

The equipment costs for Area 500 – Product, Solids, and Water Recovery (Distillation, 

Dehydration, Evaporation, and Solid-Liquid Separation) are for 2010: $23.4-million; 2015: 

$26.1-million; and 2022: $23.3-million. This area’s contribution to the total installed capital 

cost in 2010 is 17.5%; in 2015, 20.6%; and in 2022, 20.3%. We believe that some of the 

increase from 2010 to 2015 has to do with the increased liquid flow due to the conversion 

improvements; larger pipe, pumps, tanks, etc may be necessary to handle the increased flow. 

The changes from 2015 to 2022 are not that significant, as reflected by the percent contribution 

of the area to total installed equipment cost. 

Area 600 – Wastewater Treatment: The equipment in Area 600 consists mainly of 

aerobic and anaerobic digesters, digester agitators, tanks (basins), a biogas emergency flare, 

coolers, and pumps. The main purpose of the wastewater treatment section is to reduce the plant 

makeup water requirement by recovering, treating and recycling as much process water as 

possible. The feed to the wastewater treatment section consists of: condensed pretreatment flash 

vapor, condensate from the hydrolyzate filter-press vent, boiler blowdown, cooling tower 

blowdown, clean-in-place waste, and the non-recycled evaporator condensate. Rain and snow 

run-off, equipment washing, and other non-process wastewater are assumed to flow to the 

municipal wastewater treatment system. The stream is screened to remove large waste particles 

that are sent to a landfill; any remaining organic matter is anaerobically and aerobically digested. 

Anaerobic digestion produces a methane rich (75%-methane, 25%-carbon dioxide) biogas that’s 

fed to the combustor. Aerobic digestion produces relatively clean water that’s recycled back to 

the process and sludge that’s burned in the combustor. 

NREL didn’t expect much change over the 2010 to 2022 time period. In 2010 the 

installed capital cost for this area was $3.4-million; in 2015, $3.7-million; and in 2022 it was 3.1­

million. As important as this area is to the entire operation its contribution to the total project 

installed capital cost is relatively minor. In 2010 the contribution was 2.5%; in 2015, 2.9%; and 

in 2022 it was 2.7%. 

Area 700: Bulk Storage of Chemicals. This section of the plant stors chemicals in bulk 

for the process and for finished, fuel-grade ethanol. The feedstock feed surge tanks we discussed 

just prior to the discussion of Area 200 are not included in this area. Process chemicals stored in 

554 
 

 

 

this area include: corn steep liquor (a nutrient), sulfuric acid, cellulase enzyme, gasoline (used as 

a denaturant finish the fuel grade ethanol), and water for fire suppression. 

There is approximately five-days of SS316-stainless steelLLLLLLLLL tank sulfuric acid 

storage. Corn steep liquor (CSL), a nutrient for fermentation seed growth and ethanol 

production, also has about five-days of SS304-stainless steelMMMMMMMMM storage; NREL 

expects the plant will require about three-25,000 gallon rail cars of CSL every three-days. There 

are seven-days of storage for diammonium phosphate (DAP), delivered as pellets via rail car. 

Appropriate quantities of CSL and DAP are mixed in a day-tank and used in Area 300 for 

fermentation seed production and ethanol production. A producer that supplies cellulase 

enzymes is expected to set up an enzyme production operation either on site or on a nearby 

location. Liquid enzyme storage is set for four-days in SS304 stainless steel tanks. The carbon 

steel fire-fighting water storage tanks provide about four-hours of operating time; the firewater 

pump delivers 2,500 gpm. Other pumps are sized per process requirements 

There is seven-days of ethanol product storage in two 600,000 gallon carbon steel tanks. 

Five percent gasoline (v/v), a denaturant, is added to the ethanol as it’s loaded for shipment to 

customers. The pumps in this section are generally sized to load a 10,000 gallon truck and trailer 

in about 15 min. to 20 min. maximum filling time. They can also be used to fill process day 

tanks. 

The installed capital costs for bulk storage are, for 2010, $3.8-million; for 2015, $2.4­

million; and for 2022, $2.4-million. The contribution to total project installed capital costs are, 

for 2010, 2.8%; for 2015, 1.9%; and for 2022, 2.1%. 

Area 800: Combustor, Boiler, and Turbogenerator. The purpose of the combustor, 

boiler, and turbogenerator is to burn various by-product or waste streams to produce steam and to 

generate electricity. All of the feedstock lignin and some of the cellulose and hemicellulose are 

not hydrolyzed in Area 300. 

As previously discussed, a high soluble, solids syrup is generated in Area 600 and 

anaerobic and aerobic digestion of the remaining wastewater produced biogas and a small 

quantity of biomass sludge which are burned to generate steam and produce electricity. This 

contributes to over-all plant energy self-sufficiency, reduces solid waste disposal costs, and 

generates additional revenue through sales of excess electricity. Because of heightened interest 

in using biomass, pulping wastes, and sewage sludge in place of fossil fuels, new methods are 

being developed to handle higher moisture feeds. Traditional methods include blending the wet 

feed with dry material or adding auxiliary fuel to maintain the combustion temperature. When 

the dry solids from the filter-press cake are combined with the high soluble, solids syrup, it helps 

LLLLLLLLL SS316 is an improved version of SS304, with the addition of molybdenum and a slightly higher nickel 

content. The resultant composition of 316 gives it much increased corrosion resistance in many aggressive 

environments. The molybdenum makes the steel more resistant to pitting and crevice corrosion in chloridecontaminated media, sea water and acid vapors.

MMMMMMMMM SS304-stainless steel is the most versatile and the most widely used of all stainless steels. Its 

chemical composition, mechanical properties, weldability and corrosion/oxidation resistance provide the best allround performance stainless steel at relatively low cost. 

555 
 

ensure a stable combustion bed temperature and improved boiler efficiency. In these studies 

NREL used a circulating fluidized bed combustor that is suitable for varying feeds and feed 

characteristics; however, this flexibility makes the unit more expensive than a grate or pile 

combustor. A Lower Heating Value (LHV) of 2,000-2,500 BTU/lb is considered the minimum 

for maintaining combustion.NNNNNNNNN The combined feed to the combustor has a LHV of 

4,179 Btu/lb. Thus, the total higher-heating value energy of the combined feed streams to the 

combustor is 706 MMBtu/hr. The solids contribute 59% of this energy and the syrup contributes 

37%. A baghouse removes particulates from the combustion flue gas after it preheats the 

incoming combustion air and before it’s discharged through the stack. 

The boiler feed water (BFW) system includes a softener for makeup and condensate 

water, a deaerator to remove air and other non-condensables, surge tanks and pumps. The 

amount of water pretreatment necessary depends on the incoming water quality, metallurgy of 

the boiler, and the ratio of makeup to condensate in the feed water. Pretreatment chemicals for 

pH control, scale removal, and oxygen removal are added. Treated well water used for makeup 

and condensate are softened, deaerated, preheated and mixed to provide BFW that’s converted to 

steam that’s superheated to 950 o

F at 1,265 psia at the rate of 407,420 lb/hr. Support equipment 

includes BFW pumps, deaerator, automatic water pretreatment chemical injection, and 

condensate gathered from the various heat exchangers in the process. Boiler efficiency, the 

percentage of the feed heat converted to steam heat, is estimated to be 68%. Boiler blowdown is 

3% of steam production. The turbine efficiency was estimated to be 85%. 

The turbogenerator consisting of a multistage turbine with extraction ports, a generator, 

and condenser is used to generate electricity. After high pressure steam drives the multistage 

turbines, it is extracted at three different conditions for injection into the pretreatment reactor and 

heat exchange in distillation and evaporation. Twenty-eight percent of the steam is extracted 

from the turbine at 191 psia and 514°F, 60% at 65 psia and 327°F, and 3% at 25 psia and 239°F 

for process needs, as described. The remaining steam (9%) is condensed at 1.5 psia with cooling 

water and returned to the BFW system. For this design, a total of 30.4 megawatts (MW) of 

power is generated from the system. The process uses 11.7 MW, leaving 18.7 MW that is sold to 

the grid. 

The installed capital cost for Area 800 are, for 2010, $45.5-million; for 2015, $46­

million; and for 2022, $43.3-million. This area’s contribution to the total installed capital cost is, 

for 2010, 34.1%; for 2015, 36.2%; and for 2022, 37.7%. 

Area 900: Utilities. All utilities, except steam and electricity, necessary for the 

production of ethanol are accounted for in this area. The utilities provided include cooling water, 

chilled water, plant and instrument air, process water, and the clean-in-place (CIP) system. No 

chilled water is used in the plant; the required process temperatures can be achieved by cooling 

water year-round. 

NNNNNNNNN Steam and Electricity Generation Options For the Biomass-To-Ethanol Process, NREL Subcontract 

ACO-8-18019-01, Reaction Engineering International, Salt Lake City, UT, March 16, 1998. 

http://www.ott.doe.gov/biofuels/process_engineering.html 

556 
The plant and instrument air systems provide compressed air for air-driven equipment, 

instrument operation, for clean up, and the filter-press units in the post-distillation dewatering. 

The process water system mixes fresh well water with treated wastewater and provides water at a 

constant pressure to the facility. Water is provided to seed production, boiler feed water, cooling 

tower make-up, the CIP system, and the scrubber. It is also mixed with recycle water for dilution 

before saccharification. Process water is also used throughout the facility for cleaning on an asneeded basis. The CIP system provides a solution that can be heated and includes cleaning and 

sterilization chemicals to saccharification and co-fermentation, seed vessels, and the distillation 

system. 

The installed capital costs for the utilities area are, for 2010, $5.6-million; for 2015, $5.5­

million; and for 2022, $6.1-million. This area’s contribution to the total project installed 

equipment costs are, for 2010, 4.2%; for 2015, 4.3%; and for 2022, 5.3%. 

Table 4.1-26 summarizes the total projected capital costs for a biochemical cellulosic 

ethanol plant for the years 2010, 2015 and 2022. 

557 
 

Table 4.1-26. Projected Capital Costs for a Biochemical Cellulosic Ethanol Plant 

($million/yr) 

2010 2015 2022 

Total Capital 

Investment 

133.5 127 114.8 

Added Costs* 98.2 93.1 83.8 

Total Project 

Investment 

231.7 220.1 198.6 

*

Added costs include the following: 

Warehouse: This is estimated to be 1.5% of total installed cost 

Site Development: This includes fencing, curbing, parking, lot, roads, well drainage, rail system, 

soil borings, and general paving. This factor allows for minimum site development assuming a 

clear site, with no unusual problems such as right-of-way, difficult land clearing, or unusual 

environmental problems, usually calculated as 9% of the installed cost of process equipment. 

Prorateable Costs: This includes fringe benefits, burdens, and insurance of the construction 

contractor, usually calculated as 10% of total installed cost. 

Field Expenses: This includes consumables, small tool equip. rental, field services, temporary 

construction facilities, and field construction supervision, usually calculated as 10% of total 

installed cost. 

Home Office and Const.: This includes engineering plus incidentals, purchasing, and 

construction, usually calculated as 25% of total installed cost. 

Project Contingency: These costs are small because of the detail included in the process design 

usually calculated as 3% of total installed cost. 

Other Costs: This includes start-up and commissioning costs; land, rights-of-way, permits, 

surveys, and fees; piling, soil compaction/dewatering, unusual foundations; sales, use, and other 

taxes; freight, insurance in transit and import duties on equipment, piping, steel, instrumentation, 

etc.; overtime pay during construction; field insurance; project team; transportation equipment, 

bulk shipping containers, plant vehicles, etc.; escalation or inflation of costs over time; interest 

on construction loan. These other costs are usually calculated as 10% of total capital investment. 

4.1.1.3 Imported Sugarcane Ethanol Costs 

Our analysis of imported ethanol costs began with a literature search of recent estimates 

for production costs for sugar cane ethanol in Brazil. Since the liberalization of ethanol prices in 

Brazil, few cost estimation studies have been made and most of the cost analyses refer to the 

same study.909 This study was carried out by the Brazilian Ministry of Science and Technology 

(MC&T), based on 1990 data, and referred to a production cost of $0.87/gallon. Table 4.1-27 

gives a breakdown of costs based on this data. 

558 
 

Table 4.1-27. Sugarcane Ethanol Production Costs in Brazil, circa 1990 

Average cost 

(US$ per gallon) 

Operating costs

 Labor 

Maintenance 

 Chemicals 

Energy 

 Other 

Interest payments on working capital 

 Feedstock (cane) 

$0.64 

$0.02 

$0.02 

$0.01 

$0.01 

$0.02 

$0.08 

$0.48 

Fixed costs 

Capital at 12% depreciation rate 

 Other 

$0.23 

$0.19 

$0.04 

Total $0.87 

Since then, there have been significant variations in exchange rates, costs of sugarcane 

and oil products, etc. For example, earlier estimates may underestimate crude and natural gas 

costs which influence the cost of feedstock as well as energy costs at the plant. Another possible 

difference in production cost estimates is whether or not the estimates are referring to hydrous or 

anhydrous ethanol. Costs for anhydrous ethanol (for blending with gasoline) are typically 

several cents per gallon higher than hydrous ethanol (for use in dedicated ethanol vehicles in 

Brazil).910 It is not entirely clear from the majority of studies whether reported costs are for 

hydrous or anhydrous ethanol. Yet another difference could be the slate of products the plant is 

producing, for example, future plants may be dedicated ethanol facilities while others involve the 

production of both sugar and ethanol in the same facility. Due to economies of scale, production 

costs are also typically smaller per gallon for larger facilities. Table 4.1-28 summarizes the 

various estimates reported by others. Production costs range from as low as $0.57 per gallon of 

ethanol to as high as $1.48 per gallon of ethanol. 

559 
 

Table 4.1-28. Other Sugarcane Ethanol Production Cost Estimates 

Reference Cost (US$ per gallon) 

AgraFNP. 2007. Sugar and Ethanol in 

Brazil: A Study of the Brazilian Sugar Cane, 

Sugar and Ethanol Industries. 

$0.80-$1.07 per gallon (in 2006 $’s 

depending on region in Brazil), avg. is 

$0.78 per gallon for cane production cost 

and $0.13 per gallon for industrial costs 

IEA. 2004. Biofuels for Transport: An 

International Perspective. 

$0.87 per gallon (in 1990 $’s) references 

MC&T study; also reports recent 

production cost estimates for hydrous 

ethanol as low as $0.57 per gallon (at the 

prevailing exchange rate in Jan. 2004) 

USDA. 2006. The Economic Feasibility of 

Ethanol Production from Sugar in the United 

States. 

Avg. is $0.81 per gallon 

Von Lampe, Martin. OECD. 2006. Working 

Party on Agricultural Policies and Markets: 

Agricultural Market Impacts of Future 

Growth in the Production of Biofuels. 

$0.83 per gallon 

Brazil Institute. April 2007. The Global 

Dynamics of Biofuels: Potential Supply and 

Demand for Ethanol. Issue No. 3. 

$0.83 per gallon. 

ESMAP. October 2005. Potential for 

Biofuels for Transport in Developing 

Countries. 

$.87-$1.10 per gallon 

OECD, March 2008. ITF Round Tables No. 

138. Biofuels: Linking Support to 

Performance. 

Avg. is $1.40 per gallon 

Bain, R. December 2007. World Biofuels 

Assessment Worldwide Biomass Potential: 

Technology Characterizations. NREL/MP510-42467. 

$1.04-$1.48 per gallon depending on size 

of plant, i.e. 100 MGY-4.6 MGY; 

Sugarcane feedstock costs $0.68 per 

gallon, Variable operating costs $0.27 per 

gallon, Fixed costs $0.02-0.13 per gallon, 

and Capital costs $0.07-0.40 per gallon 

Macedo, I.C. and L.A.H. Nogueira. 2005. 

“Biocombusíveis”. Cadernos NAE, No. 2. 

Núcleo de Assuntos Estratégicos da 

Presidência da República, Brasilia; As sited 

in OECD, op. sit. 

$0.79 per gallon in the Center-South 

Brazil 

Kojima, M. and T. Johnson. 2006. “Potential 

for Biofuels for Transport in Developing 

Countries”. ESMAP Knowledge Exchange 

Series, No. 4.; As sited in OECD, op sit. 

$0.87-$1.09 per gallon 

Smeets, E. 2008. The Sustainability of 

Brazilian Ethanol-An Assessment of the 

Possibilities of Certified Production. 

Biomass and Bioenergy 

$1.18 assuming exchange rate of $1.20= 1 

Euro 

560 
 

The study by OECD (2008) entitled “Biofuels: Linking Support to Performance”, appears 

to provide the most recent and detailed set of assumptions and production costs. As such, our 

estimate of sugarcane production costs primarily relies on the assumptions made for the study, 

which are shown in Table 4.1-29. The estimate assumes an ethanol-dedicated mill and is based 

off an internal rate of return of 12%, a debt/equity ratio of 50% with an 8% interest rate and a 

selling of surplus power at $57 per MWh. 

Table 4.1-29. Cost of Production in a Standard Ethanol Project in Brazil 

Sugarcane Productivity 71.5 t/ha 

Sugarcane Consumption 2 million tons/year 

Harvesting days 167 

Ethanol productivity 85 liters/ton (22.5 gal/ton) 

Ethanol Production 170 million liters/year (45 MGY) 

Surplus power produced 40 kWh/ton sugarcane 

Investment cost in mill USD 97 million 

Investment cost for sugarcane production USD 36 million 

O & M (Operating & Maintenance) costs $0.26/gal 

Sugarcane costs $0.64/gal 

Capital costs $0.49/gal 

Total production costs $1.40/gal 

The estimate above is based on the costs of producing ethanol in Brazil on average, 

today. However, we are interested in how the costs of producing ethanol will change by the year 

2022. Although various cost estimates exist, analysis of the cost trends over time shows that the 

cost of producing ethanol in Brazil has been steadily declining due to efficiency improvements in 

cane production and ethanol conversion processes. Between 1980 and 1998 (total span of 19 

years) ethanol cost declined by approximately 30.8%.911 This change in the cost of production 

over time in Brazil is known as the ethanol cost “Learning Curve”. See Figure 4.1-2. 

Figure 4.1-2. Ethanol Cost “Learning Curve” 

The change in ethanol costs will depend on the likely productivity gains and 

technological innovations that can be made in the future. As the majority of learning has already 

occurred, it is likely that the decline in ethanol costs will be less drastic as the production process 

561 
 

 

and cane practices have matured. In fact, there are few perspectives for substantial efficiency 

gains with the sugarcane processing technology. Industrial efficiency gains are already at about 

85% and are expected to increase to 90% in 2015.912 Most of the productivity growth is 

expected to come from sugarcane production, where yields are expected to grow from the current 

70 tons/ha, to 96 tons/ha in 2025.913 Sugarcane quality is also expected to improve, with sucrose 

content growing from 14.5% to 17.3% in 2025. 914 All productivity gains together could allow 

the increase in the production of ethanol from 6,000 liters/ha (at 85 liters/ton sugarcane) to 

10,400 liters/ha (at 109 liters/ton sugarcane) in 2025. 915 

Assuming that ethanol productivity increases to 100 liters/ton by 2015 and 109 liters/ton 

by 2025, sugarcane costs are be expected to decrease to approximately $0.51/gal from $0.64/gal 

since less feedstock is needed to produce the same volume of ethanol using the estimates from 

Table 4.1-29, above. Table 4.1-30 shows the calculated decrease for the years 2005-2025. We 

assumed a linear decrease between data points for 2005, 2015, and 2025. Adding operating 

($0.26/gal) and capital costs ($0.49/gal) from Table 4.1-29, to a sugarcane cost of $0.51/gal, total 

production costs are $1.26/gal in 2022. 

Table 4.1-30. 

Estimated Decrease in Sugarcane Production Cost by 2022 

Due to Increases in Ethanol Productivity 

Sugarcane 

Production Cost 

$/gal liters/ton gal/ton 

2005 0.64 85 22.46 

2006 0.63 86.5 22.85 

2007 0.62 88 23.25 

2008 0.61 89.5 23.65 

2009 0.60 91 24.04 

2010 0.59 92.5 24.44 

2011 0.58 94 24.83 

2012 0.57 95.5 25.23 

2013 0.56 97 25.63 

2014 0.55 98.5 26.02 

2015 0.54 100 26.42 

2016 0.54 100.9 26.66 

2017 0.53 101.8 26.90 

2018 0.53 102.7 27.13 

2019 0.53 103.6 27.37 

2020 0.52 104.5 27.61 

2021 0.52 105.4 27.85 

2022 0.51 106.3 28.08 

2023 0.51 107.2 28.32 

2024 0.50 108.1 28.56 

2025 0.50 109 28.80 

Brazil sugarcane producers are also expected to move from burned cane manual 

harvesting to mechanical harvesting. See Figure 4.1-3.916 As a result, large amounts of straw are 

562 
expected to be available. Costs of mechanical harvesting are lower compared to manually 

harvesting, therefore, we would expect costs for sugarcane to decline as greater sugarcane 

producers move to mechanical harvesting. However, it is import to note that diesel use increases 

with mechanical harvesting, and with diesel fuel prices expected to increase in the future, costs 

may be higher than expected. Therefore, we have not assumed any changes to harvesting costs 

due to the switchover from manual harvesting to mechanical harvesting. 

Figure 4.1-3. Phase-out Schedule for Trash Burning Practices 

As more straw is expected to be collected at future sugarcane ethanol facilities, there is 

greater potential for production of excess electricity. The production cost estimates in the OECD 

study assumes an excess of 40kWh per ton sugarcane, however, future sugarcane plants are 

expected to produce 135 kWh per ton sugarcane.917 Assuming excess electricity is sold for $57 

per MWh, the production of an additional 95 kWh per ton would be equivalent to a credit of 

$0.22 per gallon ethanol produced. We did not include this potential additional credit from 

greater use of bagasse and straw in our estimates at this time. Our cost estimates do include, 

however, the excess electricity produced from bagasse that is currently used today (40 kWh/ton). 

It is also important to note that ethanol production costs can increase if the costs of 

compliance with various sustainability criteria are taken into account. For instance, using 

organic or green cane production, adopting higher wages, etc. could increase production costs for 

sugarcane ethanol.918 Such sustainability criteria could also be applicable to other feedstocks, 

for example, those used in corn- or soy-based biofuel production. If these measures are adopted 

in the future, production costs will be higher than we have projected. 

563 
In addition to production costs, there are also logistical and port costs. We used the 

report from AgraFNP to estimate such costs since it was the only resource that included both 

logistical and port costs. The total average logistical and port cost for sugarcane ethanol is 

$0.19/gal and $0.09/gal, respectively, as shown in Table 4.1-31. 

Table 4.1-31. 

Imported Ethanol Cost at Port in Brazil (2006 $’s) 

Logistical Costs Port Cost 

Region US ($/gal) US ($/gal) 

NE Sao Paulo 0.146 0.094 

W Sao Paulo 0.204 0.094 

SE Sao Paulo 0.100 0.094 

S Sao Paulo 0.170 0.094 

N Parana 0.232 0.094 

S Goias 0.328 0.094 

E Mato Grosso do sul 0.322 0.094 

Triangulo mineiro 0.201 0.094 

NE Cost 0.026 0.058 

Sao Francisco Valley 0.188 0.058 

Average 0.192 0.087 

Total fuel costs must also include the cost to ship ethanol from Brazil to the U.S. In 

2006, this cost was estimated to be approximately $0.15 per gallon of ethanol.919 Costs were 

estimated as the difference between the unit value cost of insurance and freight (CIF) and the 

unit value customs price. The average cost to ship ethanol from Caribbean countries (e.g. El 

Salvador, Jamaica, etc.) to the U.S. in 2006 was approximately $0.12 per gallon of ethanol. 

Although this may seem to be an advantage for Caribbean countries, it should be noted that there 

would be some additional cost for shipping ethanol from Brazil to the Caribbean country. 

Therefore, we assume all costs for shipping ethanol to be $0.15 per gallon regardless of the 

country importing ethanol to the U.S. 

The total imported ethanol fuel costs (at U.S. ports) over the time period of 2010 to 2022 

are shown in Table 4.1-32. In 2022, the total sugarcane ethanol cost estimate prior to tariffs and 

taxes is $1.69/gallon. Direct Brazilian imports are also subject to an additional $0.54 per gallon 

tariff, whereas those imports arriving in the U.S. from Caribbean Basin Initiative (CBI) countries 

are exempt from the tariff. In addition, all imports are given an ad valorem tax of 2.5% for 

undenatured ethanol and a 1.9% tax for denatured ethanol. We assumed an ad valorem tax of 

2.5% for all ethanol. Thus, including tariffs and ad valorem taxes, the average cost of imported 

ethanol is shown in Table 4.1-33 in the “Brazil Direct w/ Tax & Tariff” and “CBI w/ Tax” 

columns for the years 2010-2022. 

564 
 

 

Table 4.1-32. Average Imported Ethanol Costs Prior to Tariff and Taxes 

Sugarcane Operating Capital Logistical Port Transport Cost Total 

Production Cost Cost Cost Cost from Port to US Cost 

Cost ($/gal) ($/gal) ($/gal) ($/gal) ($/gal) ($/gal) ($/gal) 

2010 0.59 0.26 0.49 0.19 0.09 0.15 1.77 

2011 0.58 0.26 0.49 0.19 0.09 0.15 1.76 

2012 0.57 0.26 0.49 0.19 0.09 0.15 1.75 

2013 0.56 0.26 0.49 0.19 0.09 0.15 1.74 

2014 0.55 0.26 0.49 0.19 0.09 0.15 1.73 

2015 0.54 0.26 0.49 0.19 0.09 0.15 1.72 

2016 0.54 0.26 0.49 0.19 0.09 0.15 1.72 

2017 0.53 0.26 0.49 0.19 0.09 0.15 1.71 

2018 0.53 0.26 0.49 0.19 0.09 0.15 1.71 

2019 0.53 0.26 0.49 0.19 0.09 0.15 1.71 

2020 0.52 0.26 0.49 0.19 0.09 0.15 1.70 

2021 0.52 0.26 0.49 0.19 0.09 0.15 1.70 

2022 0.51 0.26 0.49 0.19 0.09 0.15 1.69 

2023 0.51 0.26 0.49 0.19 0.09 0.15 1.69 

2024 0.50 0.26 0.49 0.19 0.09 0.15 1.68 

2025 0.50 0.26 0.49 0.19 0.09 0.15 1.68 

Table 4.1-33. Average Imported Ethanol Costs 

Brazil 

Direct 

($/gal) 

Brazil Direct w/ 

Tax & Tariff ($/gal) 

CBI 

($/gal) 

CBI w/ Tax 

($/gal) 

2010 1.77 2.35 1.77 1.81 

2011 1.76 2.34 1.76 1.80 

2012 1.75 2.33 1.75 1.79 

2013 1.74 2.32 1.74 1.78 

2014 1.73 2.32 1.73 1.78 

2015 1.72 2.31 1.72 1.77 

2016 1.72 2.30 1.72 1.76 

2017 1.71 2.30 1.71 1.76 

2018 1.71 2.29 1.71 1.75 

2019 1.71 2.29 1.71 1.75 

2020 1.70 2.28 1.70 1.74 

2021 1.70 2.28 1.70 1.74 

2022 1.69 2.27 1.69 1.73 

2023 1.69 2.27 1.69 1.73 

2024 1.68 2.27 1.68 1.73 

2025 1.68 2.26 1.68 1.72 

565 
 

 

 

 

4.1.2 Biodiesel Production Costs 

Biodiesel production costs for this rule were estimated using two variations of a model 

generated by USDA for a 10 million gallon per year transesterification biodiesel plant. One 

version uses degummed soy oil as feedstock, and a second version includes acid pre-treatment 

steps required to utilize feedstocks such as rendered fat and yellow grease, which have 

considerable free fatty acid content. USDA used the SuperPro Designer chemical process 

simulation software to build up a process flow with estimates of heat and material flowrates and 

equipment sizing. Outputs from this software were then combined in a spreadsheet with capital, 

energy, labor, and feedstock costs to generate a final estimate of production cost. Additional 

details on the model are given in a 2006 publication in Bioresource Technology, a peer-reviewed 

scientific journal.920 At 10 million gallons per year, the modeled plant size is between the mean 

and median plant sizes (13 million and 5 million gal/yr, respectively) given in our industry 

characterization. Therefore, the model cost estimate is believed to be sufficiently accurate for 

our analyses and no further work was done to determine the effect of scale on production cost. 

Soy oil feedstock price was taken from the FASOM agricultural commodity modeling 

done for this proposal, described in more detail in section 5.1 of this DRIA. Distressed corn oil 

from ethanol plants was assumed to have a value 70% that of soy oil, consistent with historical 

yellow grease prices. A co-product stream produced by the model is crude glycerin valued at 

$0.03/lb. Table 4.1-34 shows the feedstock prices and resulting biodiesel price. Energy inputs 

included natural gas for steam generation, and electricity. The prices used for these were the 

same as those given in Table 4.1-4 in the corn ethanol production cost section. 

Table 4.1-34. Biodiesel feedstock and production costs used in this analysis, 2006$ 

 Soy Oil Yellow Grease a 

Reference Case

 Feedstock $/lb $0.23 $0.16 

 Biodiesel $/gal $2.11 $1.99 

Policy Case 

 Feedstock $/lb $0.32 $0.22 

 Biodiesel $/gal $2.75 $2.47 a Includes corn oil extracted from thin stillage/DGS, rendered fats, recycled greases, etc. 

Production cost for biodiesel is primarily a function of feedstock price, with other process 

inputs, facility, labor, and energy comprising much smaller fractions. Table 4.1-35 shows the 

production cost allocation for the soy oil-to-biodiesel facility as modeled in the 2022 policy case. 

Table 4.1-35. Production cost allocation for soy biodiesel derived from this analysis 

Cost Category Contribution to Cost 

Soy Oil 87% 

Other Materials a

 5% 

Capital & Facility 4% 

Labor 3% 

Utilities 1% a Includes acids, bases, methanol, catalyst 

566 
 

 

To arrive at a final weighted average for biodiesel production cost for the 2022 policy 

case, we weighted together the fraction of biodiesel produced from virgin oil (660 million 

gallons of soy and commodity-grade corn oil) and yellow grease (150 million gallons, primarily 

extracted corn oil) to arrive at $3.18/gal (2006$). 

4.1.3 Renewable Diesel Production Costs 

Renewable diesel can be produced using three processing options; 1.) a new standalone 

unit located in a refinery, 2.) co-processing in an existing refinery diesel hydrotreater and 3.) a 

standalone unit at a rendering plant (or another location outside of a refinery). 

 The renewable diesel production process converts vegetable oils and animal fats into a 

diesel type fuel using thermal depolymerization, which is similar to refinery hydro-treating to 

remove sulfur. The process uses hydrogen and catalyst to remove oxygen from the triglyceride 

molecules in the feedstocks oils via a decarboxylation and hydro-oxygenation reaction, yielding 

some light petroleum products and water as byproducts. The reactions also saturate the olefin 

bonds in the feedstock oils, converting them to paraffins. All of these reactions consume 

significant amounts of hydrogen. The extent of these reactions however, depends on the process 

conditions, as some of the carbon backbone of the oils can be cracked to naphtha and lighter 

products with higher severity. For our analysis though, we assume no such cracking and predict 

yields resulting in ninety nine percent diesel fuel with the balance as propane and water. 

We derive our production cost estimates from those presented by UOP and Eni’s at a 

2007 industry conference to make renewable diesel in a grass roots standalone production 

process inside a refinery.OOOOOOOOO The process has a pre-treating unit that removes alkali and 

acidic producing compounds from feed streams, which removes the catalyst poisons. We also 

use the UOP engineering estimate to derive costs for co-processing renewable diesel in an 

existing refinery’s diesel hydrotreater. For this, we assume that refiners will; 1) revamp their 

existing diesel hydrotreater to add capacity and 2) add a pre-treater to remove feedstock 

contaminants. Lastly, we derive costs for a standalone unit at a location outside a refinery at a 

rendering plant other facility, using a capital cost estimate from Syntroleum Corp.PPPPPPPPP We 

assume that all of the renewable diesel production will take place in PADD 2, as feedstock 

shipping cost are reduced since most of the sources for feedstock supply are located primarily in 

the Midwest. 

At the moment, we do not have a exact way of predicting the how industry will develop 

to build processing capacity using the three processing methods, as only a few known projects 

have been announced. We therefore base our estimate for future renewable processing capacity 

on current public project announcements and our production cost estimates, along with feedstock 

availability. In early 2007, Tyson and ConocoPhillips entered into a strategic alliance to produce 

175 MM gallons per year of renewable diesel at Conoco’s refineries located in the Midwest, 

either through co-processing or as a standalone unit. Tyson also announced this fall start of 

construction for a 75 MM gal/yr standalone plant at rendering plant in location in Geismar, 

OOOOOOOOO A New Development in Renewable Fuels: Green Diesel, AM-07-10 Annual Meeting NPRA, March 18­

20, 2007.

PPPPPPPPP From Securities and Exchange Commission Form 8-K for Syntroleum Corp, June 25th 07. 

567 
 

 

Louisiana. We assume that future capacity additions will mirror these announcements, and that a 

large fraction of the capacity for refinery installation will be produced using the co-processing 

method, as the production costs are lower than those for a new standalone unit in a refinery. 

Using this, we speculate that about 50% of renewable diesel being produced by the refinery coprocessing route, 17% from a new stand alone unit at a refinery and 33% at rendering plants or 

as a new site installation. 

We derive an average processing cost to make renewable diesel as 39.6 cents per gallon 

using yellow grease/animal fats, while processing cost from soy oil feedstock are 37.1 cents per 

gallon. Both of these costs are the resulting average from using the processing industry 

capacities listed above, along with our cost estimates. It is advantageous, however to convert 

yellow grease and animal fats into renewable diesel, as the resulting diesel fuel has improved 

blending, cold flow, storage and shipping capabilities over yellow grease converted via the 

biodiesel process. Additionally, since the process-related costs for producing renewable diesel 

from yellow grease are considerably lower than for converting yellow grease to biodiesel, we 

assume that all of our projected feedstock supplies of yellow grease and animal fats will be 

converted using the renewable diesel process, yielding 375 million gallons per year in 2022. As 

such, we assume that future renewable processing capacity will mirror the volume produced 

from yellow grease. Considering the uncertainties with subsidies and that there is considerable 

capacity for processing soy oil in biodiesel plants, we assume that all soy oil will be processed in 

existing and announced biodiesel plants. 

The specifics of our cost estimation are outlined in the sections that follow. 

i. New Standalone Unit in Refinery 

Capital costs: 

We derived new standalone renewable diesel production costs based on the UOP estimate 

for a new unit built inside an existing petroleum refinery. The total capital cost from the UOP 

estimate included ISBL and OSBL equipment outlays, which were $33.9 and $6.8 MM in 2005 

dollars, respectively for an 8,000 BPSD unit. We adjusted the original UOP capital estimates, 

which were assumed to be in 2006 dollars to 2005 dollars using CPI. Additionally, for our 

analysis, we assumed that the process was designed to accommodate a throughput flow rate to 

maintain an average of 8000 BPSD per day on an annual basis. To get installed costs, we 

escalated the above total capital costs by 20 percent, so as to account for unknown contingencies 

for installation and adjusted the resulting costs for locating the process in PADD 2, multiplying 

by a 1.3 factor. We amortized the resulting cost, assuming 7% return on capital after taxes, 

depreciation, and amortization to derive a cost for capital of 5.9 c/gal. All of the economic 

factors used for amortizing the capital costs are summarized in Table 4.1-36. 

568 
 

 

 

 

Table 4.1-36. Economic Factors Used in Deriving the Capital Cost Amortization Factor 

Amortization 

Scheme 

Depreciation 

Life 

Economic and 

Project Life 

Federal and 

State Tax Rate 

Return on 

Investment 

(ROI) 

Resulting 

Capital 

Amortization 

Factor 

Societal Cost 10 Years 15 Years 0% 7% 0.11 

Operating Costs: 

For fixed costs, we assumed this is 7% of the total installed capital, resulting in a cost of 

4.3 cents per gallon of renewable diesel fuel. For hydrogen operating costs, we used the UOP 

analysis and guidance from Conoco PhilipsQQQQQQQQQ, to derive our estimate to make renewable 

diesel, assuming that the feedstock oils were not cracked to other products. The UOP paper 

presents a range of 1000 to 2000 SCF per barrel for converting the various feedstock to 

renewable diesel. We derived feedstock specific hydrogen requirements, weighting hydrogen 

needs for feedstock oxygen saturation, along with cost for hydrogen and UOP’s total variable 

operating cost. The resulting renewable hydrogen needs are presented in the Table 4.1-37 below. 

Table 4.1-37. Feedstock Hydrogen Demands for Renewable Diesel (std. ft3/gallon) 

Feedstock Oil Hydrogen (std ft3) 

Soy Oil 1410 

Animal Grease and Yellow Grease 1590 

Hydrogen costs were generated using annual projected hydrogen prices from Jacob’s 

along with the quantities listed above, resulting in a cost of 18.0 and 21.0 c/gal for soy oil and 

yellow grease, respectively. All other remaining operating variable costs are estimated as 6.5 

c/gal, based on the UOP paper. This figure represents cost for manpower, electricity, catalyst, 

utility requirements, etc. 

The resulting total production costs are 34.5 and 37.4 cents per gallon for soy oil and 

yellow grease, respectively for new unit co-located in a refinery. 

ii. Co-Processing in Existing Refinery Diesel Hydrotreater 

Co-processing in a refinery appears to be the most cost effective, though feedstock pretreating equipment may be needed to remove impurities, so as to prevent degradation of refinery 

diesel hydrotreater catalyst. The advantage of co-processing in a hydrotreater, are that the capital 

cost are reduced as the existing diesel hydrotreater reactor, heat exchangers, pumps, process lines 

etc., can be used for the depolymerization reaction. Since the depolymerization reaction is 

highly exothermic, though there is a limit on the amount of oil feedstock that can be routed 

through an existing diesel hydrotreater. We derived our estimate for co-processing using the cost 

information form UOP’s standalone processing in the preceding section. 

Capital costs: 

QQQQQQQQQ Per EPA phone discussion July 23, 2007. 

569 
We estimate that pre-treater capital costs will be 40% of the total capital cost of a 

standalone unit, per guidance from UOP. We assume that this estimate includes capital costs to 

account for any needed refinery diesel hydrotreater modifications. The capital costs are 

amortized assuming 7% return on capital after taxes, depreciation, and amortization to derive a 

cost 2.7 cents. 

Operating Costs: 

For the fixed cost, we assume this is 8% of the total capital listed above, which equates to 

1.9 c/gal. All other remaining operating costs were assumed to be the same as those listed for the 

UOP standalone unit in the preceding section. The resulting total operating costs are 26.1 and 

29.2 c/gal for soy oil and yellow grease, respectively. 

For co-processing in a refinery, the resulting total production costs are 28.5 and 30.6 

c/gal for soy oil and yellow grease, respectively. 

iii. Standalone Unit at Rendering Plant 

For a standalone unit, not installed in a refinery, the capital cost are higher than a refinery 

new unit, as offsite and utility investments are needed to support the renewable processing 

equipment. These units, therefore require capital for these additional items, since there are little 

existing infrastructure at the site such as buildings, roads, tanks, pipelines, etc. and utility 

processes for steam generation, cooling water, etc. For our estimation of these extra costs, we 

used the total installed capital cost from Syntroleum, which is for a grass roost unit and accounts 

for offsite items. For operating costs, we assume this will be the same as those in a UOP unit. 

Capital costs: 

Syntroleum estimated that the total installed capital cost for new process is $135 MM for 

a 4800 BPSD unit, located in the South. This figure includes capital costs for offsite and utility 

investments. We estimated capital cost assuming 7% rate of return, after taxes and depreciation, 

resulting in 20.0 cents per gallon. 

Operating Costs: 

We estimated fixed costs as 6% of the total installed capital outlay listed above, which 

equates to 10.9 c/gal. All other remaining operating costs were assumed to be the same as those 

listed for the UOP standalone unit. 

The resulting overall production costs are 55.2 and 58.3 c/gal for soy oil and yellow 

grease for a standalone unit, respectively. 

Table 4.1-38 summarizes the renewable processing costs outlined in this section. Note 

that these are per-gallon costs to be added to the cost of the feedstock. Also note that only the 

570 
 

production cost from yellow grease is presented, since this is the feedstock we project will be 

used in our policy case. 

Table 4.1-38. Summary of Renewable Diesel Processing Costs (2006$/gal) 

Installation Type Processing Cost from Yellow Grease Volume Share in Policy Case 

New unit at refinery 0.37 17% 

Existing unit at refinery 0.31 50% 

Stand-alone unit at rendering plant 0.58 33% 

Weighted average 0.41 100% 

4.1.4 BTL Diesel Production Costs 

Biofuels-to-Liquids (BTL) processes, which are also thermochemical processes, convert 

biomass to liquid fuels via a syngas route. The primary product produced by this process is 

diesel fuel. 

There are many steps involved in a BTL process which makes this a capital-intensive 

process. The first step, like all the cellulosic processes, requires that the feedstocks be processed 

to be dried and ground to a fine size. The second step is the syngas step, which 

thermochemically reacts the biomass to carbon monoxide and hydrogen. Since carbon monoxide 

production exceeds the stoichiometric ideal fraction of the mixture, a water shift reaction must be 

carried out to increase the relative balance of hydrogen. The syngas products must then be 

cleaned to facilitate the following Fischer-Tropsch reaction. The Fischer-Tropsch reaction reacts 

the syngas to a range of hydrocarbon compounds – a type of synthetic crude oil. This 

hydrocarbon mixture is then hydrocracked to maximize the production of high cetane diesel fuel, 

although some low octane naphtha is also produced. The many steps of the BTL process 

contribute to its high capital cost. One report by Iowa State University estimated that diesel fuel 

produced by a 35 million gallon per year cellulosic Fischer Tropsch plant would cost $2.37 per 

gallon.921 This cost seems to be based on amortizing the capital costs using a 7 percent before 

tax rate of return which is the basis for our cost analyses. The report’s estimate for capital cost 

was $341 million. This cost was estimated in the year 2002, and adjusting this cost to a 2006 

investment environment increases the cost to $484 million. When we amortize this capital cost 

assuming a 7 percent rate of return before taxes, the yearly cost is $53 million, or about $1.51 per 

gallon of diesel fuel produced. The report estimates the operating costs to be $1.48 per gallon, 

and adjusting the operating costs to reflect 2006 dollars increases the operating cost to $1.48. 

Adding the adjusted operating cost to the adjusted capital cost results in a total cost of $2.99 per 

gallon. Almost $1.00 of the total operating cost is due to the feedstock costs, which seems to be 

assuming about $75 per dry ton of feedstock. After we adjusted to 2006 dollars, the report 

would estimate the feedstock to cost $84 per dry ton, which is higher than our average feedstock 

cost estimate of $71 per dry ton. Adjusting to an average estimated feedstock cost of $71 per dry 

ton reduces the total cost to $2.85 per gallon of diesel fuel. 

Initially, the estimated cost of $2.85 per gallon seems high relative to the projected cost 

for a year 2015 biochemical cellulosic plant, which is $1.39 per gallon of ethanol in 2006 dollars. 

However, ethanol provides about half the energy content as Fischer Tropsch diesel fuel. So if we 

double the biochemical cellulosic ethanol costs to $2.78 per diesel fuel-equivalent gallon, the 

571 
 

estimated costs are very consistent between the two. The cellulosic biofuel tax subsidy favors 

the biochemical ethanol plant, though, because it is a per-gallon subsidy regardless of the energy 

content, and it therefore offsets twice as much cost as the BTL plant producing diesel fuel. 

There is one more issue worth considering and that is the relative price of diesel fuel to that of 

E10 or E85. Recently diesel fuel has been priced much higher than gasoline, and if this trend 

continues to hold, it would provide a better market for selling the BTL diesel fuel than for selling 

biochemical ethanol into the E85 market, which we believe will be a challenging pricing market 

for refiners. 

4.2 Renewable Fuel Distribution Costs 

Our analysis of the costs associated with distributing the volumes of renewable fuels that 

we project would be used under RFS2 focuses on: 1) the capital cost of making the necessary 

upgrades to the fuel distribution infrastructure system directly related to handling these fuels, and 

2) the ongoing additional freight costs associated with shipping renewable fuels to the point 

where they are blended with petroleum-based fuels. Our analysis considers distribution costs 

within the U.S. only. The costs associated with bringing ethanol imports to the U.S. are 

considered in the context of the cost of the imports themselves.RRRRRRRRR The following 

sections outline our estimates of the distribution costs for the additional volumes of ethanol, 

biodiesel, and renewable diesel fuel that we project would be used in response to the RFS2 

standards. There will be ancillary costs associated with upgrading the basic rail, marine, and 

road transportation nets to handle the increase in freight volume due to the RFS2. We have not 

sought to quantify these ancillary costs because 1) the growth in freight traffic that is attributable 

to RFS2 represents a minimal fraction of the total anticipated increase in freight tonnage 

(approximately 2% by 2022, see Section 1.6.5 of this DRIA), and 2) we do not believe there is an 

adequate way to estimate such non-direct costs. 

The biofuels used in response to the RFS2 standards would displace petroleum-based 

fuels that would otherwise be used. Thus, it would be appropriate to subtract the distribution 

costs for the displaced petroleum-based fuels from the distribution costs attributed to the biofuels 

that replace these petroleum-based fuels. However, we choose not to do so to for our primary 

analysis in order to help ensure a conservatively high estimate of biofuel distribution costs given 

the uncertainties in our analysis.SSSSSSSSS 

A discussion of the changes that would be needed in the biofuels distribution system to 

accommodate the increased volumes of biofuels that we project would be used in response to the 

proposed RFS2 standards is contained in Section 1.6 of this DRIA. In this chapter, we further 

detail the nature of these projected changes and estimate the associated costs. Distribution 

capital costs associated with the additional volume of ethanol, biodiesel, and renewable diesel 

that we project would be used by 2022 in response to the RFS2 standards relative to a 13 BGY 

2022 reference case total 12.448 billion dollars in the U.S., 97% of which is attributed to ethanol. 

4.2.1 Ethanol Distribution Costs 

RRRRRRRRR The cost of imported ethanol is discussed in Section 4.1.1.3 of this DRIA. SSSSSSSSS This was the approach taken in the RFS1 final rule. 

572 
As discussed in the following sections, we estimate that the total capital costs in the U.S 

to support distribution of the additional volume of ethanol that would be used in response to the 

RFS2 standards would be 12.1 billion dollars by 2022. When amortized, this translates to 6.9 

cents per gallon of additional ethanol attributed to the RFS2 standards. Amortization of capital 

costs was done over 15 years at a 7% annual cost of capital except in the case of the cost of tank 

trucks where a 10 year amortization schedule was used. These costs were calculated relative to 

the AEO 2007 baseline which projects that 13.2 BGY of ethanol would be used in 2022 absent 

the RFS2 standards. Under the RFS2 standards, we project that 34.1 BGY of ethanol would be 

used by 2022. Ethanol freight costs are estimated to be 11.3 cents per gallon on a national 

average basis. Thus, we estimate that total ethanol distribution costs would be 18.2 cents per 

gallon of ethanol attributed the RFS2 standards. The way in which we estimated these costs is 

detailed in the following sections. 

As noted previously, we choose not to subtract the distribution costs for the petroleumbased fuels that would be displaced by the use of biofuels from our estimated biofuel distribution 

costs to help ensure a conservatively high estimate of biofuel distribution costs given the 

uncertainties in our analysis. We believe that the freight costs to ship petroleum-based fuels to 

the terminal are approximately 4 cents per gallon. If we were to subtract these costs from the 

estimated ethanol distribution costs, the result would be 14.2 cents per gallon. 

We currently have a study underway through Oakridge National Laboratories (ORNL) to 

model the transportation of ethanol from production/import facilities to petroleum terminals. 

The ORNL model optimizes freight flows over the rail, marine, and road distribution net while 

addressing the use of multiple shipping modes. We plan to use the results of the ORNL study to 

adjust our ethanol freight and capital cost estimates for the final rule. 

4.2.1.1 Capital Costs to Upgrade the Ethanol Distribution System 

4.2.1.1.1 Summary of Ethanol Distribution Capital Costs 

A summary of ethanol distribution capital costs is contained in Table 4.2-1. Our 

estimation of these costs is detailed in the following sections. 

573 
Table 4.2-1. 

Summary of Estimated Ethanol Distribution Infrastructure Capital Costs* 

 Million $ 

Fixed Facilities 

Marine Import Facilities 49 

 Ethanol Receipt Facilities at Rail Terminals 

 Rail Car Handling and Miscellaneous Equipment 1,264 

Ethanol Storage Tanks 354 

 Petroleum Terminals 

Rail Receipt Facilities 2,482 

Ethanol Storage Tanks 1,611 

 Ethanol Blending and Miscellaneous Equipment 545 

E85 Retail Facilities 2,957 

Mobile Facilities 

Rail Cars 2,938 

Barges 183 

Tank Trucks 223 

Total Ethanol Distribution Capital Costs 12,066 

* Relative to the AEO 2007 13.2 BGY 2022 reference case 

4.2.1.1.2 Petroleum Terminal Ethanol Distribution Capital Costs 

The facility upgrades that we project would be needed at petroleum terminals to facilitate 

the distribution of the volume of ethanol that we project would be used in response to the RFS2 

standards are discussed in Section 1.6.9 of this DRIA. Total capital costs at terminals by 2022 

relative to the 13 BGY 2022 reference case are estimated at 4.637 billion dollars. These capital 

costs are detailed in the following sections. 

4.2.1.1.2.1 Capital Cost of Additional Ethanol Rail Receipt Capability 

at Petroleum Terminals 

A discussed in Section 1.6.9 of this DRIA, we estimate that an additional 21 unit train 

and 148 manifest rail car receipt facilities would be built at petroleum terminals by 2022 to 

handle the additional volumes of ethanol that project would be transported to petroleum 

terminals via these modes (relative to the 13 BGY reference case). Based on input from 

industry, we estimate the cost of installing ethanol rail receipt capability at 600 thousand dollars 

per rail car slot. This figure is meant to include various ancillary costs associated with the 

necessary track and rail car handling facilities within the terminal gates. We believe that this is 

an upper bound regarding the potential costs of installing rail receipt capability at terminals, 

particularly with respect to unit train installations. We hope to receive additional input from 

industry with which to refine this estimate for the final rule. We assumed that ethanol unit train 

receipt facilities would need room for 100 rail cars, and that ethanol manifest rail car receipt 

facilities would accommodate 8 rail cars. Ethanol unit trains are typically composed of 70 to 100 

574 
rail cars. Our assumption of an 8 ethanol manifest rail car receipt facility is based on an 

evaluation of how much ethanol could be handled by such a facility on an annual basis. 

Assuming 60 deliveries per year (5 per month), translates to an annual throughput at a manifest 

rail car receipt facility of approximately 14.2 million gallons per year, which we believe to be a 

reasonable volume for the terminals that would be served primarily by manifest rail. To 

accommodate contingencies associated with adding ethanol receipt capability, we added 1 

million dollars per unit train facility and 500 thousand dollars per manifest rail car facility. Thus, 

within the gates of the terminal, the cost of a unit train receipt facility is estimated at 61 million 

dollars and the cost of a manifest rail car receipt facility is estimated at 5.3 million dollars. This 

does not include the cost of linking the petroleum terminal to a rail line to the extent that such 

linkage does not already exist. 

There is no comprehensive data on the number of terminals that have rail access and the 

logistical considerations in adding rail access to terminals where proximity to a rail line makes 

this an option. Lacking such information, we assumed that 50% of terminals that add ethanol rail 

receipt capability would already have rail access and 50% would need to install a rail spur to 

bring rail access to their facility. Based on input from industry, we estimate the cost of installing 

track for a rail spur at 2 million dollars per mile. We assumed that a 4 mile spur would be 

needed to connect the rail line to the petroleum terminal for unit train receipt and that a 2 mile 

long spur would be needed to connect the terminal for manifest rail car receipt. This is based on 

the premise that the length of unit trains may require more gentle curves and/or limit placement 

of the link to the rail line, whereas accommodating connections for the short manifest rail car 

shipments would be less demanding. Ancillary costs associated with establishing a linkage to a 

rail line to allow rail receipt capability are estimated at 4 million dollars per unit train facility. 

This is meant as a contingency to cover costs that we could not foresee such as the potential need 

to acquire additional land in certain cases. Again, this is based on the premise that 

accommodating a long unit train would present additional logistical challenges. The actual cost 

could be less. Based on the above, we estimate that the cost of providing linkage to a rail line 

would be 12 million dollars to allow unit train receipt capability and 4 million dollars to support 

manifest rail car receipt capability at a petroleum terminal. 

Summing the above, we arrived at the estimates contained in Table 4.2-2 for the total cost 

of providing rail receipt capability at terminals including the cost of providing rail access where 

needed. 

575 
Table 4.2-2. 

Estimated Cost of Installing Ethanol Rail Receipt Capability 

at Petroleum Terminals 

Cost Per Facility 

(million $) 

Unit Train Receipt Capability 

at a Terminal that Already had Rail Access 

61 

Unit Train Receipt Capability 

at a Terminal that Needed to Install New Rail Access 

73 

Manifest Rail Car Receipt Capability 

at a Terminal that Already had Rail Access 

5.3 

Manifest Rail Car Receipt Capability 

at a Terminal that Needed to Install New Rail Access 

9.3 

The total cost of the additional unit train receipt facilities (21) that we project would be 

installed at petroleum terminals by 2022 to support the distribution of the additional volume of 

ethanol that would be used in response to the RFS2 standards (relative to the 13 BGY reference 

case) is estimated at 1.4 billion dollars. The total cost of the additional manifest rail car receipt 

facilities (148) that we project would be needed by 2022 to support the distribution of the 

additional volume of ethanol that would be used in response to the RFS2 standards (relative to 

the 13 BGY reference case) is estimated at 1.08 billion dollars. These costs were amortized over 

15 years at a 7% annual cost of capital to derive the cents-per-gallon distribution capital cost 

estimate in Section 4.2.1 of this DRIA. 

As discussed in Section 1.6.9 of this DRIA, there is considerable uncertainty regarding 

the extent to which additional rail receipt facilities would be placed at petroleum terminals versus 

at rail terminals. This has implications not only with respect to whether the costs would be 

incurred by petroleum terminals or rail terminals but also the extent to which secondary 

transportation of ethanol is needed to reach petroleum terminals and the extent to which ethanol 

storage and handling capability would be needed at rail terminals. The projected modes of 

transporting ethanol to petroleum terminals are discussed in Section 1.6.2 of this DRIA. The 

projected capital costs at rail terminals to facilitate the distribution of ethanol are discussed in 

Section 4.2.1.1.3 of this DRIA. 

4.2.1.1.2.2 Capital Cost of Additional Ethanol Storage Tanks at Petroleum Terminals 

A discussion of how we estimated the volume of new ethanol storage that would be 

needed by 2022 as a result of the RFS2 standards (relative to the 13 BGY 2022 reference case) is 

contained in Section 1.6.9 of this DRIA. The breakdown of the amount of new ethanol storage 

that we believe could be accommodated through the retrofitting of existing tanks currently in 

gasoline service versus the amount that would require the construction of new storage tanks is 

also discussed in Section 1.6.9. We estimate that a total of 97.3 million barrels of new ethanol 

storage would be needed at petroleum terminals due to the RFS2 standards, 65.2 million barrels 

of which would be existing gasoline storage tanks retrofitted to ethanol service and 32.1 million 

barrels of which would be new construction. As discussed in Section 4.2.1.1.3.2, we estimate 

576 
that an additional 8.85 million barrels of new ethanol storage would also be needed at rail 

terminals, all of which would be satisfied with new construction. Based on information from 

industry with respect to the effect of increased steel prices on storage tanks costs, we estimate 

that the cost of constructing new ethanol storage tanks would be 40 dollars per barrel. The cost 

of installing an ethanol compatible liner and making other modifications to existing gasoline 

storage tanks to make them compatible for storing ethanol is estimated to be 5 dollars per barrel 

on average. Thus, we estimate that the total cost at petroleum terminals of new ethanol storage 

would be 1.61 billion dollars, 1.28 billion dollars of which is attributed to the construction of 

new tanks, and 326 million dollars of which is attributed to the conversion of existing gasoline 

tanks to ethanol service. These costs were amortized over 15 years at a 7% annual cost of capital 

to derive the cents-per-gallon distribution capital cost estimate in Section 4.2.1 of this DRIA. 

4.2.1.1.2.3 Capital Cost of Ethanol Blending and Other Miscellaneous Equipment at 

Petroleum Terminals 

As discussed in Section 1.6.9 of this DRIA, petroleum terminals would need to install 

additional equipment to blend ethanol with gasoline as well as making other miscellaneous 

upgrades to, piping, pumps, seals, and vapor recovery systems to ensure ethanol compatibility. 

As detailed in Section 1.6.9 of this DRIA, we projected that 164 terminals would need to install 

ethanol blending equipment by 2022 as a result of the RFS2 standards (relative to the 13 BGY 

2022 reference case). We further project that 90% of all terminals (931) would need to install 

E85 blending capability by 2022 as a result of the RFS2 standards. The remaining terminals 

(132 out of a total of 1,063) were projected to have only E10 blending capability by 2022. We 

estimated that the terminals which would have installed E10 blending capability absent the RFS2 

standards would be the ones that upgrade their ethanol blending capability to accommodate 

blending E85 as well as E10. We also estimated that the 164 terminals that would not have 

received ethanol absent the RFS2 standards would need to upgrade their vapor recovery systems 

and make other miscellaneous changes to handle ethanol blended fuel for the first time. 

We estimated the costs of the changes needed at petroleum by 2022 relative to the 13 

BGY 2022 reference case based on input from terminal operators and various other industry 

sources. The cost of upgrading the vapor recovery systems at petroleum terminals that would not 

have handled ethanol absent the RFS2 standards is estimated at 1 million dollars per terminal, 

and the miscellaneous costs associated with handling ethanol for the first time are estimated at 

20,000 per terminal. This equates to a total of 176.3 million dollars for the 164 terminals that we 

project would not have handled ethanol absent the RFS2 standards. We estimate that all 1,063 

petroleum terminals would incur 300 thousand dollars per facility on average to upgrade their 

piping, electrical, and other miscellaneous equipment in order to handle the increased ethanol 

throughput that they would experience due to the RFS2 standards. This is based on our 

engineering judgment and contains substantial contingency costs. Actual costs could be less. 

This would total 318.9 million dollars by 2022. 

In addition, the cost of installing E10 blending equipment is estimated to average 300 

thousand dollars for the 164 terminals that we estimate would not have installed ethanol blending 

capability in the absence of the RFS2 standards. The does not include the needed ethanol storage 

capability discussed in Section 4.2.1.1.2.2 of this DRIA and the miscellaneous piping and other 

577 
work needed that is discussed above. Input from terminal operators indicates that retrofitting 

E10 blending equipment to dispense E85 as well as E10 (apart from ethanol storage and delivery 

concerns) primarily involves changes to computer software. Based on this input, we estimate 

that E85 blending equipment would cost 10 thousand dollars more than E10 blending equipment. 

We applied this 10 thousand dollar differential to new installations of E85 blending equipment as 

well as retrofits of existing E10 blending equipment. Based on this, we estimate the total cost of 

the ethanol blending equipment that would be needed at petroleum terminals as a result of the 

RFS2 standards to be 58.5 million dollars. 

Summing all of these estimated costs, we arrived at an estimate of the total cost by 2022 

for the ethanol blending and other miscellaneous equipment that would be needed at petroleum 

terminals as a result of the RFS2 standards of 544.7 million dollars. These costs were amortized 

over 15 years at a 7% annual cost of capital to derive the cents-per-gallon distribution capital 

cost estimate in Section 4.2.1 of this DRIA. 

4.2.1.1.3 Rail Terminal Ethanol Distribution Capital Costs 

The facility upgrades that we project would be needed at rail terminals to facilitate the 

distribution of the volume of ethanol that we project would be used in response to the RFS2 

standards are discussed in Section 1.6.3 of this DRIA. Total capital costs at terminals by 2022 

relative to the 13 BGY 2022 reference case are estimated at 1.618 billion dollars. These capital 

costs are detailed in the following sections. 

4.2.1.1.3.1 Capital Cost of Ethanol Unit Train Receipt Capability at Rail Terminals 

As discussed in Section 1.6.3 of this DRIA, we project that 21 ethanol unit train receipt 

facilities would be located at rail terminals to facilitate the delivery of ethanol to petroleum 

terminals. Consistent with the approach taken in the estimation of the cost of installing a unit 

train facility at a petroleum terminals (as discussed in Section 4.2.1.1.2.1 of this DRIA), we 

estimated the cost of installing ethanol rail receipt capability at a rail terminal to be 600 thousand 

dollars per rail car slot. This translates to 60 million dollars for a facility capable of receiving a 

100 rail car unit train. In the case of rail terminals, we believe this figure is sufficient to cover 

various ancillary costs associated with the necessary track and rail car handling facilities within 

the rail terminal gates. Given that rail terminals are already in the business of handling large 

numbers of rail cars, we believe that there would be significantly less ancillary costs associated 

with handling ethanol rail cars themselves compared to a petroleum terminal. Thus, we believe 

that the 600 thousand per rail slot is also sufficient to cover whatever truck loading, piping, and 

other miscellaneous costs that would be incurred at rail terminals (with the exception of the need 

for ethanol storage tanks that is discussed in the following section). Nevertheless, we added a 1 

million dollar per rail terminal contingency cost to help ensure that these ancillary costs are 

accounted for. Consistent with our estimate of the cost of unit train facilities at petroleum 

terminals, we assumed the need to accommodate a 100 car ethanol unit train. 

Based on the above, we project that the total cost of installing ethanol unit train receipt 

capability at a rail terminal to be 61 million dollars per facility. This totals 1.264 billion dollars 

for the 21 ethanol unit train rail receipt facilities that we project would be installed as a result of 

578 
the RFS2 standards by 2022 (relative to the 13 BGY 2022 reference case). These costs were 

amortized over 15 years at a 7% annual cost of capital to derive the cents-per-gallon distribution 

capital cost estimate in Section 4.2.1 of this DRIA. 

A discussed in Section 1.6.9 of this DRIA (and noted in Section 4.2.1.1.2.1), there is 

considerable uncertainty regarding the extent to which additional rail receipt facilities would be 

placed at petroleum terminals versus at rail terminals. To the extent that logistical constraints 

prevent the placement of some of the 21 additional ethanol unit train receipt facilities and/or 148 

manifest rail car facilities that we project would be installed at petroleum terminals (see Section 

4.2.1.1.2.1), we expect that additional unit train receipt facilities would be placed at rail terminals 

to compensate. 

4.2.1.1.3.2 Capital Cost of Ethanol Storage Tanks at Rail Terminals 

As discussed in Section 1.6.3 of this DRIA, we project that 17.7 million gallons of new 

ethanol storage would be needed at rail terminals to support unit train deliveries. This equates to 

a total of 371.7 million gallons or 8.85 million barrels of new ethanol storage tanks for the 21 

ethanol unit train receipt facilites that we project would be installed to support use of the volume 

of ethanol that we estimate would be use in response to the RFS2 standards (relative to the 13 

BGY 2022 reference case). We used the same estimate of 40 dollars per barrel to construct new 

ethanol storage tanks that we used to estimate the cost of new ethanol storage tanks at petroleum 

terminals (in Section 4.2.1.1.2 of this DRIA). Thus, we estimate that the total cost of the 

additional ethanol storage tankage that would be needed due to the RFS2 standards at 354 

million dollars. These costs were amortized over 15 years at a 7% annual cost of capital to 

derive the cents per gallon distribution capital cost estimate in Section 4.2.1 of this DRIA. 

Should some of the ethanol rail receipt facilities that we project would be installed at petroleum 

terminals instead be installed at rail terminals, ethanol storage at additional rail terminals would 

be needed instead. 

4.2.1.1.4 Import Facility Ethanol Distribution Capital Costs 

As discussed in Section 1.6.4 of this DRIA, we estimate that a total of 28 port facilities 

would receive imported ethanol by 2022, 12 of which had not received ethanol before. We 

believe that all such port facilities also serve as petroleum terminals. Thus, the cost of additional 

ethanol storage, ethanol blending equipment, and other miscellaneous equipment related to 

handling ethanol from the standpoint of terminal operations at such facilities is accounted for in 

the context of the costs at petroleum terminals (see Section 4.2.1.1.2 of this DRIA). However, 

there would be additional costs at the port facilities which had not received ethanol in the past. 

Input from industry indicates that offloading large marine transport containers of ethanol requires 

significantly upgraded vapory recovery equipment. Based on this input, we estimated the cost of 

making the needed upgrades to vapor recovery equipment at 2.5 million dollars per facility. We 

further estimated miscellaneous costs associated with delivery of ethanol into storage tanks from 

marine vessels at 1 million dollars per facility. This is meant to include new piping, pumps, 

various other fittings, and a contingency cost. The actual cost could be significantly lower. 

Thus, we estimate that the total cost to prepare for delivery of ethanol at a port that had not 

received ethanol before at 3.5 million dollars per facility. The total for the 12 ports that we 

579 
project had received imported ethanol before is 42 million dollars. As discussed in Section 1.6.4, 

we are considering whether 2 additional ports that have not received ethanol before should be 

added to the list of ports that we expect would receive ethanol imports by 2022. Including these 

2 additional ports would increase the total cost for ports that had not received ethanol before to 

49 million dollars. These costs were amortized over 15 years at a 7% annual cost of capital to 

derive the cents-per-gallon distribution capital cost estimate in Section 4.2.1 of this DRIA. 

4.2.1.1.4 Ethanol Rail Car Capital Costs 

As discussed in Section 1.6.3 of this DRIA, we estimate that an additional 26,644 ethanol 

tank cars would be needed by 2022 to transport the additional volume of ethanol that we project 

would be used to meet the RFS2 standards (relative to the 13 BGY 2022 reference case). Based 

on input from industry, we estimate that the cost of a new ethanol tank car of 30 thousand gallon 

nominal capacity at 90 thousand dollars. Thus, we estimate that the total cost of the ethanol rail 

tanks cars needed due to the RFS2 standards by 2022 would be 2.398 billion dollars. These costs 

were amortized over 15 years at a 7% annual cost of capital to derive the cents-per-gallon 

distribution capital cost estimate in Section 4.2.1 of this DRIA. 

4.2.1.1.5 Ethanol Barge Capital Costs 

As discussed in Section 1.6.4, we estimate that an additional 131 10,000 barrel capacity 

barges would be needed by 2022 to transport the additional volume of ethanol that we project 

would be used to meet the RFS2 standards (relative to the 13 BGY 2022 reference case). Based 

on input from industry, we estimate the cost of a new 10,000 barrel barge capable of transporting 

ethanol at 1.4 million dollars. Thus, we estimate that the total cost of barges needed to transport 

ethanol due to the RFS2 standards by 2022 would be 183 million dollars. These costs were 

amortized over 15 years at a 7% annual cost of capital to derive the cents-per-gallon distribution 

capital cost estimate in Section 4.2.1 of this DRIA. 

We understand that the tank barge industry is trending towards the use of tank barges 

with a carrying capacity of 30,000 barrels which tend to less expensive on a per-barrel basis than 

10,000 barrel capacity barges. Thus, our assumed use of a 10,000 barrel capacity barges likely 

results in a conservatively high estimate of ethanol barge costs. 

4.2.1.1.6 Ethanol Tank Truck Capital Costs 

As discussed in Section 1.6.5 of this DRIA, we estimate that an additional 1,241 8,000 

gallon capacity tank trucks would be needed by 2022 to transport the additional volume of 

ethanol that we project would be used to meet the RFS2 standards (relative to the 13 BGY 2022 

reference case). Based on input from industry, we estimate that the cost of a new 8,000 gallon 

tank truck capable of transporting ethanol at 180 thousand dollars. This is based on a 110 

thousand dollar cost for the tractor and a 70 thousand dollar cost for the tank trailer. Thus, we 

estimate that the total cost of tank trucks needed to transport ethanol due to the RFS2 standards 

by 2022 would be 223 million dollars. These costs were amortized over 10 years at a 7% annual 

cost of capital to derive the cents-per-gallon distribution capital cost estimate in Section 4.2.1 of 

580 
 

 

this DRIA. We used a 10 year amortization schedule for tank trucks as opposed to the 15 year 

schedule used for other capital equipment to reflect their likely shorter service life. 

4.2.1.1.6 E85 Retail Facility Costs 

As discussed in Section 1.6.10 of this DRIA, we estimate that an additional 24,250 E85 

retail facilities would be needed by 2022 as a result of the RFS2 standards (relative to the 13 

BGY 2022 reference case). We estimated that 40% of these new facilities would install 2 new 

E85 pumps with four nozzles. We assumed that no existing equipment would be retrofitted to 

meet this demand. On average, we estimate the cost per E85 facility would be 122,000 dollars 

as detailed below. This cost estimate includes the use of E85 compatible hardware and 

compliance with applicable regulations regarding the storing/dispensing fuels. 

The following cost estimates are based on input from gasoline retailers and other parties 

with experience in the requirements and costs associated with installing E85 retail equipment. 

The total cost of installing a two nozzle E85 dispenser is estimated at 23,000 dollars. This is 

composed of 17,000 dollars for the dispenser itself, 750 dollars for hanging hardware, 950 for 

refueling island hardware, 3,000 for installation, and a 1,300 dollar contingency cost. Hanging 

hardware costs are composed of 310 dollars for 2 nozzles, 135 dollars for 2 breakaway 

connections, 135 dollars for 2 swivel connections, and 170 dollars for 2 hoses. Refueling 

hardware costs are composed of 450 dollars for the dispenser island, 250 for an island sump 

pump, and 250 dollars for bumper posts. Installation costs are composed of 1,500 dollars for 

concrete removal and replacement, and 1,500 dollars for wiring and piping. 

The cost of automatic tank level gauging equipment is estimated at 6,500 dollars. It is 

estimated that 65% of retailers would install automatic tank gauging (ATG) equipment and the 

remainder would rely on manual means of determining the amount of fuel remaining in their 

underground storage tank. Thus, the average cost per facility would be 4,225 for ATG 

equipment. We estimate the cost of installing a canopy addition to provide cover for an 

additional dispenser at 15,000. We estimated that only 10% of facilities would need to install 

additional canopy coverage in order to accommodate the new E85 retail dispenser. Thus, the 

average canopy cost per facility is estimated at 1,500 dollars. The cost of installing a new 8,000 

underground E85 storage tank system is estimated at 84,000 dollars. The cost of connecting the 

tank to the dispenser(s) is included in this cost along with other miscellaneous storage tank 

related costs. 

We proposed that a level be placed near each E85 nozzle which states the E85 is for use 

only flex-fuel vehicles.TTTTTTTTT Based on input from industry, the cost of compliance with this 

proposal would be approximately 5 dollars per label. New labels would be needed on all E85 

dispensers, which totals approximately 385,000 dollars for the 76,900 E85 nozzles that we 

project would be in operation by 2022 under the RFS2 standards. 

Based on the above, we estimate the cost of installing a new single dispenser E85 facility 

would be 113,000 dollars and the cost for a 2 dispenser facility would be 136,000 dollars. Based 

on our projection that 40% of facilities would install 2 dispensers, we estimate an average cost of 

TTTTTTTTT See proposed regulatory Section 80.1469. 

581 
 

122,000 per new E85 facility. Thus, the total cost of the 24,250 new E85 facilities that we 

project would be needed by 2022 due to the RFS2 program would be 2.96 billion dollars. These 

costs were amortized over 15 years at a 7% annual cost of capital to derive the cents-per-gallon 

distribution capital cost estimate in Section 4.2.1 of this DRIA. As discussed in Section 1.6.10 

of this DRIA, this cost estimate is based on our assessment that it would be sufficient for one in 

four retail facilities to offer E85 in 70% of the country. 

As discussed in Section 1.6.10, we performed several sensitivity analyses to evaluate the 

potential that additional dispensers or retail facilities might be needed to facilitate the use of the 

volume of E85 that we project would be needed by 2022 to support compliance with the RFS2 

standards. Under one scenario, we assumed that 3 E85 dispensers would be needed at each 

facility that sells E85 in order to provide a less aggressive throughput per nozzle level. Under 

this scenario, the 4,500 E85 retail facilities that we estimate would be in place by 2022 absent the 

RFS2 requirements would need to install an additional 2 dispensers.UUUUUUUUU Based on the 

above, the cost to these facilities would be 46,000 dollars. We also assumed that 50% of new 

E85 facilities would convert one of its gasoline storage tanks to E85 service in addition to 

installing a new E85 storage tank.VVVVVVVVV Based on these assumptions and the cost 

information discussed above, the cost per new E85 facility would be 166,000 dollars. The total 

cost under this scenario would rise to 4.24 billion dollars. 

We evaluated 3 additional sensitivity cases under which the total number of E85 facilities 

needed was increased by varying our estimates regarding what fraction of retailers would need to 

offer E85 in a given area to provide reasonable access and the fraction of the country that would 

need to have reasonable access to E85. In all cases, we maintained the assumption that 40% of 

new E85 retail facilities would install two dispensers while the remainder would install only one 

dispenser. Under the first such scenario, we assumed that one-in-three retail facilities in a given 

area would need to offer E85 to provide reasonable access, while maintaining our estimate that 

reasonable access would be needed in 70% of the county. Under this scenario, an additional 

33,835 E85 retail facilities would be needed by 2022 relative to the 13 BGY 2022 reference case 

at a total cost of 4.13 billion dollars. Under the second such scenario, we assumed that one-infour retail facilities in a given area would need to offer E85 to provide reasonable access 

consistent with our primary case, but that reasonable access would be needed in 100% of the 

county. Under this scenario, an additional 36,573 E85 retail facilities would be needed by 2022 

relative to the 13 BGY 2022 at a total cost of 4.46 billion dollars. Under the third such scenario 

we assumed that one-in-three retail facilities in a given area would need to offer E85 to provide 

reasonable access and that reasonable access would be needed in 100% of the county. Under this 

scenario, an additional 50,264 E85 retail facilities would be needed by 2022 relative to the 13 

BGY 2022 at a total cost of 6.13 billion dollars. 

4.2.1.2 Ethanol Freight Costs 

Our estimation of the cost of transporting ethanol from production/import facilities to the 

various locations where it would be used is based on the freight cost estimates developed for the 

UUUUUUUUU As discussed in Section 1.6.10 of this DRIA we assumed that these facilities would install only a single 

E85 dispenser (with 2 nozzles) absent the RFS2 program. 

VVVVVVVVV This cost includes all the necessary changes to make the tank and associated equipment E85 compatible. 

582 
 

 

RFS1 final rule922 A comprehensive study of the infrastructure requirements for an expanded 

fuel ethanol industry conducted for the Department of Energy (DOE) in 2002 provided the 

foundation for our estimate of the freight costs to handle the increased volume of ethanol needed 

under the RFS1 program.923 As noted earlier, we currently have a study underway through 

Oakridge National Laboratories (ORNL) to model the transportation of ethanol from 

production/import facilities to petroleum terminals. The ORNL model optimizes freight flows 

over the rail, marine, and road distribution net while addressing the use of multiple shipping 

modes. We plan to use the results of the ORNL study to adjust our ethanol freight cost estimates 

for the final rule. 

Our estimation of ethanol freight costs is based on our evaluation of where ethanol would 

be produced/imported and where it would be used under the RFS2 standards. Section 1.5 of this 

DRIA contains a discussion of our projections regarding where ethanol would be produced and 

the points of entry for ethanol imports to satisfy the RFS2 requirements. Section 1.7 of this 

DRIA contains a discussion of where we project ethanol would be used under the proposed 

RFS2 program. Overall ethanol freight costs were minimized by first filling demand within a 

state with ethanol produced within or imported into that state and then reaching out to areas that 

had an excess production capacity compared to in-state demand. We developed ethanol freight 

costs on a state-by-state basis for ethanol that is produced within and imported into the state, and 

ethanol that is shipped in from PADD2. A higher freight cost was assessed to rural versus urban 

areas for ethanol brought in from out-of-state. This is based on the premise that ethanol shipped 

to rural areas from out-of-state would typically either first be delivered to a hub terminal in an 

urban area (typically by unit train) for further shipment to terminals in rural areas or would be 

shipped directly to terminals in rural areas via manifest rail car.WWWWWWWWW 

In-state shipment of ethanol was assumed to be done by tank truck. Such in-state ethanol 

freight costs were developed based on a review of shipping distances and topography with the 

state and the trucking costs developed for the RFS1 final rule. Ethanol freight costs from PADD 

2 production facilities to meet out-of-state demand were also based on the estimates developed 

for the RFS1 final rule for such shipments.924 We made several changes to the RFS1 freight cost 

estimates for the purpose of our RFS2 analysis. The freight cost estimates for shipment to rural 

areas in several states (California, Hawaii, and Michigan) were increased relative to those in the 

RFS1 rule based on our reanalysis of the difficulties in meeting all of the rural demand in these 

states. In part, this is based on the premise that ethanol would need to travel farther and more 

widely to satisfy the volume requirements under the RFS2 standards in comparison to the RFS1 

standards. We also considered freight costs for the upper and lower peninsulas of the State of 

Michigan separately for the purposes of our RFS2 analysis, whereas the State of Michigan was 

treated as a whole under the RFS1 analysis. 

Following is a discussion of our derivation of the freight costs for ethanol shipped from 

PADD2 production centers to meet out-of-state demand. The 2002 DOE study contains 

estimated ethanol freight costs for each of the 5 PADDs. These estimated costs are summarized 

in the following Table 4.2-3.925 A map of the PADDs is contained in Figure 4.2-1. 

WWWWWWWWW A discussion of our assessment of which areas are rural versus urban is contained in Section 1.7 of 

this DRIA. 

583 
Table 4.2-3. 

Estimated Ethanol Freight Costs from the 2002 DOE Study 

PADD 

5.1 billion gallons per year 

(cents per gallon) 

10.0 billion gallons per year 

(cents per gallon) 

1 11.1 7.2 

2 4.3 2.4 

3 6.6 5.8 

4 4.7 7.4 

5 12.7 10.7 

National Average 7.7 5.7 

Figure 4.2-1. 

PAD District Definitions. 

The Energy Information Administration (EIA) translated the cost estimates from the 2002 

DOE study to a census division basis.926 A summary of the resulting (EIA) ethanol distribution 

cost estimates are contained in the following Table 4.2-4. A map of the census divisions is 

contained in Figure 4.2-2. 

584 
 

 

Table 4.2-4. 

EIA Estimated Ethanol Freight Costs 

(Derived from the 2002 DOE Study) 

Census Division Freight Cost 

From To (cents per gallon) 

East North Central New England 9.8 

East North Central Middle Atlantic 9.8 

East North Central East North Central 4 

East North Central South Atlantic 9.8 

East North Central East South Central 4.7 

East North Central Pacific 14.0 

West North Central New England 11.4 

West North Central Middle Atlantic 11.4 

West North Central East North Central 4 

West North Central West North Central 4 

West North Central South Atlantic 11.4 

West North Central East South Central 4.7 

West North Central West South Central 4.7 

West North Central Mountain 4.5 

West North Central Pacific 13.0 

585 
Figure 4.2-2. 

Census Divisions 

We took the EIA projections and translated them into state-by-state freight costs for 

shipment of the ethanol produced in the East and West North Central Census Divisions 

(corresponding closely to PADD 2). Distribution outside of PADD2 was assumed to be by rail, 

or marine vessel. In the case of Alaska and Hawaii, differences in ethanol delivery prices from 

the mainland were inferred from gasoline prices. A single average freight cost for each 

destination census division was generated by weighting together the freight costs given for each 

mode in both source census divisions according to their volume share. These cents per gallon 

figures were first adjusted upward by 10% to reflect the increased cost of transportation fuels 

used to ship ethanol between the 2002 DOE study and the publication of the RFS1 FRM, and 

then additional adjustments were applied to some individual states based on their position within 

the census division. We believe that these estimates reasonably correspond to the 53 dollar per 

barrel of crude case that we used in other areas of our analysis. We were unable to develop an 

estimate of how an increase in crude cost would affect ethanol freight costs for this proposal. 

586 
 

Freight costs are correlated to the cost of the transportation fuel used by the transportation modes 

employed. Transportation fuel costs represent a different fraction of overall freight costs for 

each of the different modes (rail, barge, tank truck). We were unable to obtain sufficient data 

with which to assess the effects on ethanol freight costs of increased crude costs for all of the 

modes employed. There are significant competitive issues with respect to how these costs are 

passed along to customers, and the extent to which increases in transportation fuel costs must be 

absorbed by the shipper as opposed to being passed along to the customer due to market 

conditions. We intend to pursue this issue further so that we can develop an estimate of ethanol 

freight costs under the 92 per barrel of crude case that was used in other areas of our analysis. 

For some states, different freight costs for ethanol supplied to large hub terminals versus 

small satellite terminals were estimated. The reasoning behind this is that large shipments of 

ethanol shipped from the Midwest by barge, ship, and/or unit train will often be initially 

unloaded at hub terminals for further distribution to satellite terminals. In cases where 

redistribution from a hub to a satellite terminal doesn’t take place, the volume of ethanol shipped 

directly from the producer to a lesser volume (“satellite”) terminal would also incur a higher 

freight rate than ethanol shipped to a larger-volume “hub” terminal. The largest adjustment was 

applied to the Rocky Mountain States since they are generally large in area and additional 

expense is required to transport freight through higher elevations and rugged terrain. Smaller 

adjustments were applied to states that are smaller, flatter, or have access by navigable 

waterways. The states to which an adjustment was not applied were generally in the Midwest or 

were so small as to not warrant different distribution costs. The estimated additional freight cost 

of shipping ethanol to satellite terminals versus hub terminals is contained in the following Table 

4.2-5. All areas were not assigned both hub and satellite terminal ethanol distribution costs. For 

example, all shipment to of ethanol to the upper peninsula of the State of Michigan was assumed 

to be to smaller volume terminals, since there is insufficient population density in the area to 

support a hub terminal. 

Table 4.2-5. 

Additional Freight Cost to Deliver Ethanol to a Satellite Terminal
 

Compared to a Hub Terminal 

States* cents per gallon 

OH, MI (lower peninsula) 2 

AL, AR, CA, FL, GA, KY, LA, MD, ME, MS, 

NC, NH, NY, OK, OR, PA, SC, TN, VA, VT, 

WA, WV 

4 

AK, AZ, CO, ID, NM, NV, TX, UT, WY 5 

* States not listed were not assigned separate hub and satellite freight costs. 

We also made adjustments to the DOE study derived freight cost estimates to better 

account for the cost of shipping ethanol from the production plant to the rail head / marine 

terminal either for large volume shipment by unit train or marine shipment to hub terminals, or 

for shipment at single car rates via multiple-product trains directly to satellite terminals. Chicago 

is a primary ethanol gathering point from producers for further distribution. A 4 cent per gallon 

conveyance fee is charged to account for delivery of ethanol from the production plant gate to 

587 
the Chicago Board of Trade delivery point for taking ethanol. This includes train shipments, 

loading costs, and other miscellaneous fees. Based on this information, we added 4 cents per 

gallon to our ethanol freight estimates. 

We assumed that these freight costs do not include the costs associated with the recovery 

of capital for the distribution facility changes that are necessary to accommodate the increased 

volume of ethanol. This may tend to overstate distribution costs to some extent because some 

capital recovery may already be incorporated into the 4 cent per gallon conveyance fee. The 

inclusion of rail tank car lease fees also suggests that these estimated freight costs may be 

conservatively high given that rail car lease fees incorporate a capital recovery and a profit 

margin. 

Our resulting estimates of the state-by-state ethanol freight costs in 2022 are contained in 

Table 4.2-6. Based on these estimates and our projections regarding where ethanol would be 

produced/imported and used, we estimate that the national average ethanol freight cost would be 

11.3 cents per gallon. 

Ethanol freight costs will vary from year-to-year based on where ethanol would be 

shipped versus where it would be produced. As the volumes of ethanol used increase over time, 

more ethanol would be used in rural areas that have higher distribution costs. Therefore, we 

believe that average ethanol freight costs would increase over time. Thus, basing our evaluation 

of ethanol freight costs on the 2022 case should provide a conservatively high estimate of freight 

costs for earlier years. A discussion of how we estimated the volumes of ethanol used in each 

state from in-state versus out-of-state production/imports and the estimation of volume that 

would be shipped to urban versus rural areas is contained in Section 1.7.1 of this DRIA. 

588 
Table 4.2-6. 

2022 Estimated Ethanol Freight Costs 

Destination % of Use From 

In-State Supply 

(vs. Out-ofState Supply) 

Freight 

Cost 

for InState 

Supply 

(cpg) 

% of Out-ofState Supply 

Shipped to 

Urban Areas 

(vs. Rural 

Areas) 

Freight Cost 

for Out-ofState Supply 

Shipped to 

Urban Areas 

(cpg) 

Freight Cost 

for Out-ofState Supply 

Shipped to 

Rural Areas 

(cpg) 

Alabama 68 4.4 46 11.2 15.2 

Alaska 0 NA 53 45.4 50.5 

Arizona 5 5.4 76 19.4 24.4 

Arkansas 76 5.4 37 11.3 16.3 

California 26 4.4 94 20.5 24.5 

Colorado 22 5.4 64 14.4 19.4 

Connecticut 18 4.4 100 15.4 NA 

Delaware 0 NA 100 15.4 NA 

District of 

Columbia 

0 NA 100 15.4 NA 

Florida 29 4.4 84 12.4 16.4 

Georgia 44 5.4 68 15.4 19.4 

Hawaii 15 5.4 60 40.5 44.5 

Idaho 34 5.4 29 19.4 24.4 

Illinois 100 4.4 NA NA NA 

Indiana 100 4.4 NA NA NA 

Iowa 100 3.4 NA NA NA 

Kansas 100 4.4 NA NA NA 

Kentucky 16 5.4 47 6.2 10.2 

Louisiana 100 4.4 NA NA NA 

Maine 96 5.4 61 17.4 21.4 

Maryland 0 NA 89 15.4 15.4 

Massachusetts 18 4.4 100 15.4 NA 

Michigan –LP 69 5.4 68 6.2 10.2 

Michigan –UP 0 NA 0 NA 10.2 

Minnesota 100 4.4 NA NA NA 

Mississippi 38 4.4 27 10.2 14.2 

Missouri 98 4.4 58 6 8 

Montana 64 5.4 9 17.4 22.4 

Nebraska 100 4.4 NA NA NA 

Nevada 6 5.4 77 20.4 25.4 

589 
Table 4.2-6. (continued)
 

2022 Estimated Ethanol Freight Costs 

Destination % of use from 

in-State Supply 

(vs. Out-ofState Supply) 

Freight 

Cost for 

in-State 

Supply 

(cpg) 

% of Out-ofState Supply 

Shipped to 

Urban Areas 

(vs. Rural 

Areas) 

Freight Cost 

for out-ofstate supply 

to urban areas 

(cpg) 

Freight Cost 

for out-ofstate supply 

to rural areas 

(cpg) 

New Hampshire 91 4.4 67 16.4 16.4 

New Jersey 18 4.4 100 15.4 NA 

New Mexico 8 4.4 33 16.4 21.4 

New York 28 5.4 85 15.4 19.4 

North Carolina 40 4.4 61 15.4 19.4 

North Dakota 100 5.4 NA NA NA 

Ohio 77 5.4 74 6.2 10.2 

Oklahoma 100 4.4 NA NA NA 

Oregon 84 5.4 57 20.5 24.5 

Pennsylvania 20 5.4 72 12.4 16.4 

Rhode Island 18 4.4 100 15.4 NA 

South Carolina 45 4.4 49 15.4 19.4 

South Dakota 100 5.4 NA NA NA 

Tennessee 34 5.4 58 6.2 10.2 

Texas 39 5.4 88 14.3 19.3 

Utah 0 NA 72 17.4 22.4 

Vermont 0 NA 0 NA 16.4 

Virginia 17 5.4 68 15.4 19.4 

Washington 38 5.4 60 20.5 24.5 

West Virginia 67 5.4 28 15.4 19.4 

Wisconsin 100 4.4 NA NA NA 

Wyoming 8 5.4 0 NA 21.4 

4.2.2 Biodiesel Distribution Costs 

As discussed in the following sections, we estimate that the total capital costs to support 

distribution of the additional volume of biodiesel that would be used in response to the RFS2 

standards would be 381 million dollars by 2022. When amortized, this translates to 9.8 cents per 

gallon of additional biodiesel attributed to the RFS2 standards. Amortization of capital costs was 

done over 15 years at a 7% annual cost of capital except in the case of the cost of tank trucks 

were a 10 year amortization schedule was used. These costs were calculated relative to the AEO 

2007 baseline which projects that 380 MGY of biodiesel would be used in 2022 absent the RFS2 

standards. Under the RFS2 standards, we project that an additional 430 MGY of biodiesel would 

590 
 

 

 

 

be used by 2022 for a total of 810 MGY. Biodiesel freight costs are estimated to be 9.3 cents per 

gallon on a national average basis.XXXXXXXXX Thus, we estimate that total biodiesel distribution 

costs would be 19.1 cents per gallon of biodiesel attributed the RFS2 standards. The way in 

which we estimated these costs is detailed in the following sections. 

As noted previously, we choose not to subtract the distribution costs for the petroleumbased fuels that would be displaced by the use of biofuels from our estimated biofuel distribution 

costs to help ensure a conservatively high estimate of biofuel distribution costs given the 

uncertainties in our analysis. We believe that the freight costs to ship petroleum-based fuels to 

the terminal are approximately 4 cents per gallon. If we were to subtract these costs from the 

estimated biodiesel distribution costs, the result would be 15.1 cents per gallon. 

4.2.2.1 Capital Costs to Upgrade the Biodiesel Distribution System 

4.2.1.1.1 Summary of Biodiesel Distribution Capital Costs 

A summary of biodiesel distribution capital costs is contained in Table 4.2-7. Our 

estimation of these costs is detailed in the following sections. 

Table 4.2-7. 

Summary of Estimated Biodiesel Distribution Infrastructure Capital Costs* 

 Million $ 

Fixed Facilities 

 Petroleum Terminals 

 Biodiesel Storage Tanks 129 

 Biodiesel Blending and Miscellaneous Equipment 192 

Mobile Facilities 

 Rail Cars 35 

Barges 17 

Tank Trucks 8 

Total Biodiesel Distribution Capital Costs 381 

* Relative to the AEO 2007 380 MGY 2002 reference case. 

4.2.1.1.2 Petroleum Terminal Biodiesel Distribution Capital Costs 

The facility upgrades that we project would be needed at petroleum terminals to facilitate 

the distribution of the increased volume of biodiesel in response to the RFS2 standards are 

discussed in Section 1.6.9 of this DRIA. Total capital costs at terminals by 2022 relative to the 

BGY 2022 reference case are estimated at 321 million dollars. 

XXXXXXXXX The projected shorter transportation distances on average for biodiesel compared to ethanol resulted in a 

lower per gallon freight cost for biodiesel compared to ethanol (11.3 cpg). 

591 
As discussed in Section 1.6.9 of this DRIA, we estimate that a total of 1.84 million 

barrels of new biodiesel storage would be needed at petroleum terminals due to the RFS2 

standards, all of which would need to be satisfied by new construction. Based on information 

from industry with respect to the effect of increased steel prices on storage tanks costs, we 

estimate that the cost of constructing new biodiesel storage tanks would be 70 dollars per barrel. 

This is considerably higher than the 40 per barrel cost we estimated for construction of new 

ethanol tanks for two reasons. Biodiesel tanks need to be heated/insulated in colder climes. 

Biodiesel tanks tend to be of considerably smaller size compared to ethanol tanks. Both of these 

factors contribute significantly to the cost per barrel of constructing a new storage tank. We 

estimate that the total cost at petroleum terminals of new biodiesel storage tanks would be 129 

million dollars. 

As discussed in Section 1.6.9 of this DRIA, we projected that 200 terminals would need 

to install biodiesel blending equipment by 2022 as a result of the RFS2 standards (relative to the 

380 MGY 2022 reference case). Based on input from industry, we estimated that the cost of 

biodiesel blending equipment would be 400 thousand dollars per terminal. The cost of additional 

piping is estimated at 60,000 per terminal. Miscellaneous costs associated with 

receiving/blending/storing biodiesel for the first time are estimated at 500 thousand dollars per 

terminal. Estimated equipment costs for handling biodiesel are higher than those for similar 

equipment designed to handle ethanol due to the need for insulated/heated equipment in colder 

climes. 

Summing all of these estimated costs, we arrived at an estimate of the total cost for the 

biodiesel blending, storage, and other miscellaneous equipment that would be needed at 

petroleum terminals as a result of the RFS2 standards by 2022 of 321.1 million dollars. These 

costs were amortized over 15 years at a 7% annual cost of capital to derive the cents-per-gallon 

distribution capital cost estimate in Section 4.2.2 of this DRIA. 

4.2.1.1.3 Biodiesel Rail Car Capital Costs 

As discussed in Section 1.6.3 of this DRIA, we estimate that an additional 353 biodiesel 

tank cars would be needed by 2022 to transport the additional volume of ethanol that we project 

would be used to meet the RFS2 standards (relative to the 380 MGY 2022 reference case). 

Based on input from industry, we estimate that the cost of a new biodiesel tank car of 25,600 

gallon capacity at 99,000 dollars. The estimated cost for a biodiesel rail car is 10% higher than 

that of an ethanol rail car to accommodate the need for insulated/heated tanks in colder climes. 

Thus, we estimate that the total cost of the biodiesel rail tanks cars needed due to the RFS2 

standards by 2022 would be 35 million dollars. These costs were amortized over 15 years at a 

7% annual cost of capital to derive the cents-per-gallon distribution capital cost estimate in 

Section 4.2.2 of this DRIA. 

4.2.1.1.4 Biodiesel Barge Capital Costs 

As discussed in Section 1.6.4, we estimate that an additional 11 10,000 barrel capacity 

barges would be needed by 2022 to transport the additional volume of biodiesel that we project 

would be used to meet the RFS2 standards (relative to the 380 MGY 2022 reference case). 

592 
Based on input from industry, we estimate that the cost of a new 10,000 barrel barge capable of 

transporting biodiesel at 1.54 million dollars. This estimated cost is 10% higher than the cost of 

a barge designed to transport ethanol due to the need for an insulated/heated tank in colder 

climes. Thus, we estimate that the total cost of barges needed to transport biodiesel due to the 

RFS2 standards by 2022 would be 16.6 million dollars. These costs were amortized over 15 

years at a 7% annual cost of capital to derive the cents-per-gallon distribution capital cost 

estimate in Section 4.2.2 of this DRIA. 

While the tank barge industry is trending towards the use of tank barges with a carrying 

capacity of 30,000 barrels (which tend to be less expensive on a per-barrel basis than 10,000 

barrel capacity barges), we believe the assumed use of 10,000 barrel barges is appropriate for 

biodiesel transport due to the relatively smaller volumes of biodiesel that we project would be 

used. 

4.2.1.1.5 Biodiesel Tank Truck Capital Costs 

As discussed in Section 1.6.5 of this DRIA, we estimate that an additional 1,241 8,000 

gallon capacity tank trucks would be needed by 2022 to transport the additional volume of 

biodiesel that we project would be used to meet the RFS2 standards (relative to the 380 MGY 

2022 reference case). Based on input from industry, we estimate that the cost of a new 8,000 

gallon tank truck capable of transporting biodiesel at 198 thousand dollars. This is based on an 

110,000 dollar cost for the tractor and an 88,000 thousand dollar cost for the tank trailer. This 

estimate is 25% higher than the cost of a tank trailer designed to transport ethanol due to the need 

for an insulated/heated tank in colder climes. Thus, we estimate that the total cost of tank trucks 

needed to transport biodiesel due to the RFS2 standards by 2022 would be 7.8 million dollars. 

These costs were amortized over 10 years at a 7% annual cost of capital to derive the cents-pergallon distribution capital cost estimate in Section 4.2.2 of this DRIA. We used a 10 year 

amortization schedule for tank trucks as opposed to the 15 year schedule used for other capital 

equipment to reflect their likely shorter service life. 

4.2.2.2 Biodiesel Freight Costs 

The distribution of biodiesel from production plants to petroleum terminals where it 

would be blended with diesel fuel is discussed in Section 1.6.3 of the DRIA. Tank truck was the 

assumed method of shipment for distances of less than 300 miles. Where distances are beyond 

300 miles, shipment by manifest rail was assumed to be the preferred option other than in cases 

on the East coast where there were apparent barge routes from production to demand centers. In 

no case was it assumed that biodiesel would need to be shipped by multiple modes prior to 

delivery at the petroleum terminal. 

Our estimation of biodiesel freight costs is based on our evaluation of where biodiesel 

would be produced and where it would be used under the RFS2 standards. Section 1.5 of this 

DRIA contains a discussion of our projections regarding where biodiesel would be produced to 

satisfy the RFS2 requirements. Section 1.7 of this DRIA contains a discussion of where we 

project biodiesel would be used under the proposed RFS2 program. Demand for biodiesel in 

each state was established based on current and anticipated future state biodiesel mandates and 

593 
 

 

the anticipated demand for 2% biodiesel in most heating oil used in the Northeast by 

2022.YYYYYYYYY Production volumes from each plant were assigned to meet these demands 

based on minimizing overall distribution distances (and cost). The production volume that was 

not consumed in meeting the anticipated demand from state mandates and to meet heating oil 

demand was assumed to be used within trucking distance of the production plant to the extent 

possible while maintaining biodiesel blend concentrations below 5%. This may tend to result in 

a conservatively high estimate of biodiesel freight costs since biodiesel blend levels could exceed 

5% in some areas. The remaining volume needed to match our estimated production volume was 

assumed to be shipped via manifest rail car or barge to the nearest areas where diesel fuel use 

was not already saturated with biodiesel to the 5% level. A 1,000 mile shipping distance was 

selected to ensure that all biodiesel not used to satisfy a state mandate, otherwise used in state, or 

used for bio-heat could find a market. It is likely that some fraction would not need to travel 

quite at far. Therefore, this assumption is also likely to result in a conservatively high estimate 

of biodiesel freight costs. 

Our estimates of the freight costs for shipping biodiesel by tank truck are based on the 

ethanol tank truck freight costs that we developed for the RFS1 final rule.ZZZZZZZZZ These 

ethanol transport costs were increased by 10% to account for the increased cost associated with 

preventing fuel gelling during cold conditions. The cost of shipping biodiesel by truck when the 

trip (or multiple trips) could be completed in a day was estimated to range from 7 to 8 cents per 

gallon. Some long truck transports were assumed to be necessary (up to 300 miles), where a 

round trip could not be completed in a single day. In such cases, the need for an overnight 

layover was assumed to add 120 dollars to shipping costs, resulting in an estimated 9.5 cents per 

gallon freight cost. 

Our estimate of the cost of shipping biodiesel by manifest rail cars is based on publicly 

available biodiesel freight tariff information from BNSF railway from February 2008.927 We 

used the BNSF fuel surcharge schedule to adjust our freight cost estimates to match our 53 per 

barrel of crude scenario. Specific tariff information was not available for source/destinations 

needed for our analysis. A minimum cost of 9 cents per gallon was assumed to accommodate 

loading, unloading, and rail car lease costs. Based on the BNSF tariff information, we estimated 

that every 100 miles of additional shipment by manifest rail car beyond 600 miles adds 1.4 cents 

per gallon to shipping cost. Thus, for the assumed 1,000 mile shipping distance for biodiesel 

used to meet miscellaneous demand (i.e. not used to meet state mandates or for bioheat) the cost 

to ship by manifest rail car was estimated at 15 cents per gallon. Barge shipping costs were 

assumed to be comparable to the cost of shipping by manifest rail. This will tend to overstate 

barge shipping costs, since we understand that barge freight costs tend to be significantly less 

than rail freight costs. However, given that only 1% of biodiesel is projected to me moved by 

barge, this will have only a minimal effect on our overall estimation of biodiesel freight costs. 

We intend to seek out additional information regarding the cost of shipping biodiesel by barge 

over the routes we have identified so that we can update our biodiesel freight cost estimate for 

the final rule. Shipping distances were estimated based on a review of biodiesel production plant 

locations, demand centers, and the rail/barge transportation net. 

YYYYYYYYY When biodiesel is blending into heating oil, the product is commonly referred to as bioheat. ZZZZZZZZZ See Section 4.2.1.2 of this DRIA. 

594 
 

 

Similar to the situation regarding our estimation of ethanol freight costs, we were not able 

to satisfactorily adjust our freight cost estimates across all modes in order to estimate biodiesel 

freight costs under the 92 per barrel crude cost scenario used in other parts of our analysis. We 

intend to pursue this analysis further so that we can provide an estimate of the impact on 

biodiesel freight costs of changes in transportation fuel costs in the final rule. 

Due to the favorable match up in the location of biodiesel plants and biodiesel demand 

centers, 86% of biodiesel was projected to be shipped by truck, 13% was estimated to be shipped 

by manifest rail car, and 1% was estimated to be shipped by barge. We project that 

approximately 44% of the biodiesel production volume in 2022 would be used in the state where 

it was produced to meet state mandates, satisfy the demand for bioheat, or to meet other in-state 

miscellaneous demand. The average cost of shipping this volume by tank truck is estimated to 

average 8 cents per gallon. Approximately 3% of biodiesel production volume is estimated to be 

shipped out-of-state by manifest rail car to meet miscellaneous biodiesel demand at an average 

freight cost of 15 cents per gallon. 

Approximately 54% of biodiesel production is projected to be shipped out of state to 

satisfy state mandates or bioheat demand which could not be satisfied with in-state production. 

We assigned portions of the production volumes from states that had already satisfied this 

demand to meet this demand in other states based on minimizing overall shipping distances (and 

costs). A freight cost estimate was derived for each source and destination pair based on the 

fraction of the volumes that would be shipped by each mode and the freight cost for each mode 

used given the shipping distance. On average the cost of shipping biodiesel from out-of-state to 

satisfy state biodiesel mandates or the demand for bioheat is estimated at 10 cents per gallon. By 

weighting the biodiesel volumes used to satisfy the three demand categories by the respective 

freight cost to ship that volume we arrived at a national average biodiesel freight cost estimate of 

9.3 cents per gallon. Biodiesel freight costs are summarized in Table 4.2-8. 

Table 4.2-8. 

Estimated Biodiesel Freight Costs
 

Biodiesel Demand Category Fraction of 

Biodiesel Production 

Freight Cost 

(cpg) 

Shipped In-State to Satisfy In-State Demand 43% 8 

Shipped Out-of-State to Satisfy State Mandates 

and Demand for Bioheat 

54% 10 

Shipped Out-of-State to Satisfy 

Miscellaneous Demand 

3% 15 

Total (National Average) 100% 9.3 

4.2.3 Renewable Diesel Distribution Costs 

As discussed in Section 1.6.1.3, there are comparatively few additional costs associated 

with distributing renewable diesel fuel because the majority is projected to be produced at 

petroleum refineries and it can be shipped fungibly with petroleum-based diesel fuel. As 

discussed in Section 1.6.5 of this DRIA, we estimate that 8 additional 8,000 gallon capacity tank 

trucks would be needed by 2022 to transport the additional volume of renewable diesel fuel that 

595 
 

we project would be used to meet the RFS2 standards from stand-alone production facilities to 

petroleum terminals (relative to the 0 MGY 2022 reference case). Based on input from industry, 

we estimate that the cost of a new 8,000 gallon tank truck capable of transporting renewable 

diesel fuel at 180 thousand dollars. This is based on a 110 thousand dollar cost for the tractor 

and 70 thousand dollar cost for the tank trailer. Thus, we estimate that the total cost of tank 

trucks needed to transport renewable diesel fuel due to the RFS2 standards by 2022 would be 1.3 

million dollars. These costs were amortized over 10 years at a 7% annual cost of capital. This 

translates to 0.2 cents per gallon of the renewable diesel that would be produced at stand-alone 

facilities and hence need to be transported separately (125 million gallons by 2022). We used a 

10 year amortization schedule for tank trucks as opposed to the 15 year schedule used for other 

capital equipment to reflect their likely shorter service life. 

As discussed in Section 1.6.4 of this DRIA, we estimate that renewable diesel fuel which 

does need to be transported separately from petroleum-based diesel fuel (because it is produced 

at stand-alone facilities not located at a refinery) would be shipped by tank truck to a terminal 

facility where it would be blended directly with diesel fuel. The freight cost for this truck 

transport is estimated at 5 cents per gallon. Thus, the total cost of distributing renewable diesel 

fuel is estimated at 5.2 cents per gallon, and this only applies to the renewable diesel that would 

be produced at stand-alone facilities. 

As noted previously, we choose not to subtract the distribution costs for the petroleum-based 

fuels that would be displaced by the use of biofuels from our estimated biofuel distribution costs 

to help ensure a conservatively high estimate of biofuel distribution costs given the uncertainties 

in our analysis. We believe that the freight costs to ship petroleum-based fuels to the terminal 

are approximately 4 cents per gallon. If we were to subtract these costs from the estimated 

renewable diesel distribution costs, the result would be 1.2 cents per gallon. 

4.2.4 Potential Fuel Retailer Costs to Facilitate the Use of Mid-Level Ethanol Blends 

The potential changes that may be needed to the fuel distribution system to facilitate the 

introduction of mid-level ethanol blends are discussed in Section 1.6.11 of this DRIA. As 

discussed in Section 1.6.11, investigations are currently underway to evaluate the compatibility 

of existing retail fuel storage and dispensing equipment with Mid-level ethanol blends. If such 

equipment is found to compatible or to require only modest modification to accommodate midlevel ethanol blends, then the costs could be small. Even if some pieces of the above ground 

equipment are found to be incompatible with mid-level ethanol blends, it may be possible to 

replace such equipment through normal attrition. For example, the “hanging hardware” on a fuel 

dispenser has a normal service life of only 3 to 5 years. Other components have longer service 

lives. The pump dispenser has an average service life of 20 years, with up-scale marketers 

replacing their dispensers more frequently and lower tier marketers retaining their dispensers for 

as long as 40 years. Storage tank systems have a service life of approximately 40 years. Thus, 

depending on the type of equipment that might need to be replaced, waiting for its replacement 

through normal attrition could delay the widespread introduction of mid-level ethanol blends. 

If the extensive changes are needed, and particularly if concrete needs to be broken, the 

cost to introduce mid-level ethanol blends at retail could potential be large. To provide an upper 

596 
 

 

bound on the potential, we used cost estimates that we compiled for E85 capable equipment. It 

may be possible that even if current equipment needs to be replaced in order to accommodate 

mid-level ethanol blends, that such equipment might not need to be manufactured to the 

specifications necessary to be E85 capable. If this were the case, the costs of such equipment 

may be lower than comparable E85-capable equipment. 

We estimate that the cost of replacing the fuel-wetted components of a fuel dispenser 

with E85-capable equipment to be as much as $12,000 per dispenser. This includes the cost of 

the hanging hardware (at $750 for 2 nozzles, hoses, and break-away connections), the cost of the 

dispenser’s “hydraulic tree” (at $10,000), and installation costs ($1,250).AAAAAAAAAA Based on 

gasoline retailer survey data, we estimate that there is average of 3.9 gasoline dispensers at each 

gasoline retail facilities. 928 It was estimated that in 2007 there were 164, 292 gasoline retail 

facilities in the U.S.929 Thus, we estimate that the cost of retrofitting all 641,000 gasoline 

pumps at $7.7 billion. The cost would be considerably higher if the complete underground 

storage tank would need to be replaced. The cost of replacing an existing storage tank is 

estimated at $84,000. Thus, the cost of replacing a single tank at each retail facility would result 

in an additional cost of $13.8 billion for a total cost of $21.5 billion. Many retail facilities have 

multiple storage tanks in order to keep pace with fuel sales. The replacement of such storage 

tanks would further increase the potential cost. 

The introduction of a mid-level ethanol blend would not eliminate the need for the use of 

additional E85 (and additional E85 refueling facilities) to facilitate the consumption of the 

projected ethanol volumes needed to comply with the RFS2 standards.BBBBBBBBBB However, it 

could delay and to some extent reduce the need for additional E85 refueling facilities. To 

evaluate the potential effect on costs of the reduced need for additional refueling facilities that 

might result from the introduction of a mid-level ethanol blend, we evaluated a scenario where 

reasonable access to E85 would only be needed in 50% of the nation. Under our primary E85 

retail facility case, we assumed that reasonable access to E85 would be needed in 70% of the 

country, and that 40% of new E85 facilities have 2 E85 pumps and the remainder would have 1 

E85 pump.CCCCCCCCCC If we were to assume that to reasonable E85 availability in 50% of the 

nation while maintaining the same assumptions regarding the number of pumps per facility, the 

total cost of new E85 refueling facilities would be 2 billion dollars. This is approximately one 

billion dollars less than under our primary case where reasonable access is assumed to be needed 

in 70% of the country. 

We evaluated a sensitivity case from our primary E85 retail facility cost estimate under 

which it was assumed that 3 pumps would be needed at each E85 retail facility to maintain the 

needed E85 throughput. Under this sensitivity case, if we to assume that reasonable E85 

availability would only be needed in 50% of the country, the total cost of additional E85 

refueling facilities needed due to the RFS2 standards would be reduced by approximately 1.4 

billion dollars. 

AAAAAAAAAA The shell of fuel dispenser and the electronic components would remain unchanged. BBBBBBBBBB A discussion of the projected ethanol use levels under the RFS2 standards is discussed in Section 1.7.2 of 

this DRIA. 

CCCCCCCCCC See Section 4.2.1.1.6 of this DRIA for a discussion of E85 retail facility costs under the RFS2 program. 

597 
598 

4.3 Reduced Refining Industry Costs 

As renewable and alternative fuel use increases, the volume of petroleum-based products, 

such has gasoline and diesel fuel, would decrease. This reduction in finished refinery petroleum 

products is associated with a reduction in refinery industry costs. This cost reduction would 

essentially be the volume of fuel displaced multiplied by the cost for producing the fuel. There is 

also a reduction in capital costs which is important because by not investing in new refinery 

capital, more resources are freed up to build plants that produce renewable and alternative fuels. 

Although we conducted refinery modeling for estimating the cost of blending ethanol, we 

did not rely on the refinery model results for estimating the volume of displaced petroleum. 

Instead we conducted an energy balance around the increased use of renewable fuels, estimating 

the energy-equivalent volume of gasoline or diesel fuel displaced. This allowed us to more 

easily apply our best estimates for how much of the petroleum would displace imports of 

finished products versus crude oil for our energy security analysis which is discussed in Chapter 

15 of the DRIA. 

As part of this analysis we accounted for the change in petroleum demanded by upstream 

processes related to additional production of the renewable fuels as well as reduced production of 

petroleum fuels. For example, growing corn used for ethanol production requires the use of 

diesel fuel in tractors, which reduces the volume of petroleum displaced by the ethanol. 

Similarly, the refining of crude oil uses by-product hydrocarbons for heating within the refinery, 

therefore the overall effect of reduced gasoline and diesel fuel consumption is actually greater 

because of the additional upstream effect. We used the lifecycle petroleum demand estimates 

provided for in GREET model to account for the upstream consumption of petroleum for each of 

the renewable and alternative fuels, as well as for gasoline and diesel fuel. Although there may 

be some renewable fuel used for upstream energy, we assumed that this entire volume is 

petroleum because the volume of renewable and alternative fuels is fixed as described in Chapter 

1 above. 

For this proposed rule, we assumed that a portion of the gasoline displaced by ethanol is 

imported, while the other portion is produced from domestic refineries. The assumption we 

made is that one half of the ethanol market in the Northeast, which comprises about half of the 

nation’s gasoline demand, would displace imported gasoline or gasoline blend stocks. 

Therefore, to derive the portion of the new renewable fuels which would offset imports (and not 

impact domestic refinery production), we multiplied the total volume of petroleum gasoline 

displaced by 50 percent to represent that portion of the ethanol which would be used in the 

Northeast, and 50 percent again to only account for that which would offset imports. The rest of 

the ethanol, including half of the ethanol presumed to be used in the Northeast, is presumed to 

offset domestic gasoline production. In the case of biodiesel and renewable diesel, all of it is 

presumed to offset domestic diesel fuel production. For ethanol, biodiesel and renewable diesel, 

the amount of petroleum fuel displaced is estimated based on the relative energy contents of the 

renewable fuels to the fuels which they are displacing. The savings due to lower imported 

gasoline and diesel fuel is accounted for in the energy security analysis contained in Chapter 15. 
 

 

 

For estimating the reduced U.S. refinery costs, we multiplied the estimated volume of 

domestic gasoline and diesel fuel displaced by the wholesale price for each of these fuels, which 

are $1.57 per gallon for gasoline, and $1.61 per gallon for diesel fuel at $53/bbl crude oil, and 

$2.67 per gallon for gasoline, and $3.35 per gallon for diesel fuel at $92/bbl crude oil. For the 

volume of petroleum displaced upstream, we valued it using the wholesale diesel fuel price. 

Table 4.3-1 shows the net volumetric impact on the petroleum portion of gasoline and diesel fuel 

demand, as well as the reduced refining costs for 2022. 

Table 4.3-1. U.S. Refinery Cost Reduction for the RFS2 Fuel Program in 2022 

Total 

Volume 

Displaced 

(billion 

gallons) 

Refining Cost 

Reduction at 

$53/bbl crude oil 

price 

(billion dollars) 

Refining Cost 

Reduction at 

$92/bbl crude oil 

price 

(billion dollars) 

Upstream Petroleum -0.8 -$1.3 -$2.7 

End Use Gasoline 10.4 $16.3 $27.7 

Diesel Fuel 0.6 $0.9 $1.9 

Total - $15.9 $26.9 

4.4 Overall Costs to Gasoline and Diesel Fuel 

The previous sections of this chapter have presented estimates of the cost of producing 

and distributing ethanol, biodiesel and renewable diesel fuel. In this section, we summarize the 

results of refinery modeling conducted by Jacobs Consultancy under contract to EPA for using 

those biofuels.930 Jacobs’s used the Haverly Linear Programming (LP) model to conduct the 

analysis. This model is widely used by the refining industry, consultants, engineering firms and 

government agencies to analyze refinery economics, refinery operations, fuel quality changes, 

refinery capital investments, environmental changes and demand changes. The Haverly model 

uses Jacobs’s Refining Process Technology Database to represent refining operations. 

The modeling was conducted to analyze the effect of the increased renewable fuel use on 

the production costs and composition of the nation’s gasoline and diesel fuel. The refinery 

modeling output described in this section includes the changes in volumes and capital 

investments as well as the resulting capital and fixed operating costs, the variable costs, and the 

total of all these costs. Because of the significant increase in crude oil prices in mid-2008, we 

estimated the costs of this program at two different crude oil prices. The low price is $53/bbl 

which represents the reference crude oil price estimated by the Energy Information 

Administration (EIA) for its 2008 Annual Energy Outlook (AEO).931 The high price is $92/bbl 

which represents the high crude oil price estimated by EIA for its 2008 AEO. We describe the 

methodology for adjusting the cost of the RFS2 standard further below in the methodology 

section. 

4.4.1 Description of Refinery Modeling Cases Modeled and Methodology 

599 
 

 

The refinery modeling was set up to analyze the volumes required by the RFS as 

described in Chapter 1. The primary renewable fuel modeled was ethanol in gasoline, and we 

considered a small amount of biodiesel and renewable diesel as required under EISA. While the 

addition of ethanol was modeled with the refinery model to capture the blending costs of using a 

large amount of additional ethanol, the projected additional volme of biodiesel and renewable 

diesel was not captured by the refinery model. Instead, the blending of biodiesel and renewable 

diesel was captured outside the refinery model, although we modeled a slightly lower the energyequivalent volume of diesel fuel based on the addition of the biodiesel and renewable diesel 

volume. 

Jacobs conducted a Linear Programming modeling analysis of the refining industry for 

the various RFS scenarios using a model developed by Haverly’s LP technology. The modeling 

was set up to analyze the extent to which ethanol will be used in conventional gasoline and 

reformulated gasoline by region and the resulting effects on gasoline composition. The refining 

industry was modeled based on five aggregate complex refining regions, representing Petroleum 

Administration for Defense Districts (PADD) 1, 2, 3, 4 & 5 together minus California, and 

California separately. All of the PADDS were modeled simultaneously together in the LP model 

which allowed the refinery model to most efficiently rebalance the regional gasoline production 

volumes in response to the addition of the renewable fuels. 

The refinery modeling was conducted in three distinct steps which involved a base case, a 

reference case and a control case. 

4.4.1.1 Base Case 

The first step involved the establishment of a 2004 base case which calibrated the 

refinery model against 2004 volumes, gasoline quality, and refinery capital in place. We chose 

2004 because the following year, 2005, as well as the beginning of 2006, were affected by 

hurricanes and would not be representative of a typical year, and 2007 data was not yet available 

when we started the analysis. Refinery unit capacities from the Oil and Gas Journal and Energy 

Information Administration (EIA), as well as refinery feedstock and product volumes from EIA 

data were entered into the refinery model. The refinery model was then run and the resulting 

gasoline quality compared and calibrated to actual gasoline quality data information from EPA’s 

Reformulated Gasoline data base. 

4.4.1.2 Reference Case 

The reference case is a business-as-usual case that serves as a reference to the control 

cases. Thus, the year of analysis for the reference case must be the same as that used for control 

cases. Because the RFS2 fuel standard becomes fully implemented in 2022, we conducted our 

reference and control cases analysis in 2022. Two categories of adjustments were made to the 

base case refinery models to enable modeling the refining industry in 2022 for the reference case. 

First, the change in certain inputs assumptions such as product volumes and energy prices 

needed to be projected. U.S. refinery gasoline, diesel fuel and jet fuel demand were projected to 

grow to meet increased demand. These projected volumes were used for establishing finished 

product which then led to refinery production for each PADD to meet that increased demand. 

600 
This projected growth in U.S. refinery production is entered into the reference case version of the 

LP refinery model. 

The refinery modeling was conducted using the projection of crude oil and product prices 

in 2022. Crude and other input prices were based on Jacobs’ projection of refinery margins and 

crude prices in 2022 cases, which was also based on the historical price spreads of fuels between 

the PADDs, using information from EIA’s 2004 price information tables, Platts, and AEO 2006. 

The average price of crude oil was projected to be about $51 per barrel, although crude oil prices 

varied by PADD. For the reference case as well as for the control cases, we assumed the same 

crude oil and product prices. The crude oil prices and summertime and wintertime prices for 

gasoline, diesel fuel and jet fuel are summarized in Table 4.4-1. 

Table 4.4-1. Crude Oil and Finished Product Prices used in Refinery Modeling 

PADD 1 PADD 2 PADD 3 PADD 4/5 

CA excl. 

California 

Crude Oil 

($/bbl) 

Yearround 

Average 

53.6 53.0 50.6 51.8 50.2 

Reformulated 

Gasoline 

(c/gal) 

Summer 175.2 173.5 170.8 - 186.7 

Winter 161.4 158.7 155.3 - 173.7 

Conventional 

Gasoline 

(c/gal) 

Summer 167.6 165.1 161.4 173.6 -

Winter 154.0 151.8 148.5 160.4 -

Diesel Fuel 

(c/gal) 

Summer 156.6 157.6 154.6 166.6 164.6 

Winter 162.6 163.6 160.6 172.6 170.6 

Jet Fuel (c/gal) Summer 158.6 158.6 156.6 164.6 164.6 

Winter 156.6 156.6 154.6 162.6 162.6 

We also modeled the implementation of several new environmental programs that will 

have required changes in fuel quality by 2022, including the 30 ppm average gasoline sulfur 

standard, the 15 ppm cap standards on highway and nonroad diesel fuel, the Mobile Source Air 

Toxics (MSAT) 0.62 volume percent benzene standard. Although there may still be a small 

amount high sulfur diesel fuel, we assumed that all distillate fuel would be ultra low sulfur in 

compliance with the 15 ppm cap standard. We modeled the implementation of the 2005 Energy 

bill, which by rescinding the RFG oxygenate standard, resulted in the discontinued use of 

MTBE, and a large increase in the amount of ethanol blended into reformulated gasoline. We 

modeled 13.2 billion gallons of ethanol in the gasoline pool (starch ethanol, cellulosic ethanol 

and sugar ethanol) and 0.3 billion gallons of biodiesel and renewable diesel fuel in the diesel 

pool for 2022, which is the “business-as-usual” volume as projected by AEO 2007.932 However, 

we assessed the growth in energy demand using AEO 2008 which modeled the EISA Corporate 

Average Fuel Economy (CAFE) standards in the reference case because it will be phasing-in in 

parallel with the phase-in of the RFS2.933 For the reference case, the refinery model blended the 

ethanol as E10 as the refinery model did not find it economical to blend any ethanol as E85 

(Although the refinery modeling did not capture today’s small volume of E85 in the reference 

601 
 

 

case, not capturing this volume does not appreciably impact the results of the refinery 

modeling.). 

4.4.1.3 Control Case 

The third step, or the control case, involved the modeling of the 34 billion gallons of 

ethanol and 1 billion gallons of biodiesel and renewable diesel to comply with the RFS 

requirements in 2022 when the proposed renewable fuels program is fully phased-in. The cost 

and other implications of this fully phased-in control case are compared to the reference case to 

assess the cost of the program. We also modeled two other cases which served as sensitivities to 

our primary control case. The first is a 100 percent E10 case which modeled the saturation of the 

gasoline pool with 10 percent ethanol, but did not require additional volumes of ethanol that 

would force the use of E85. The second case required the same volumes of renewable fuels as 

our primary control case, except that ethanol was allowed to be blended at 20 percent. We ran 

these sensitivity cases to isolate aspects of the primary control case. We ran the E10 case to 

isolate the effects of E10 blending from that of E85 on gasoline fuel properties and costs. We 

ran the mid-ethanol blend sensitivity case to assess what might happen to gasoline fuel properties 

and costs if a waiver were to be granted for mid-ethanol blends as some have suggested. These 

cases are summarized below at the end of this section. 

The principal change in renewable fuel volumes modeled, relative to the reference case, 

was a large increase in ethanol blended into gasoline. Table 4.4-2 below summarizes the volume 

of biofuels estimated to be used in the year 2022 for the reference case and the control 

DDDDDDDDDD 

case.

Table 4.4-2. 

Summary of Reference and Control Case Volumes in 2022
 

(billion gallons) 

Reference Case Control Case Difference 

Corn Ethanol 12.3 15 2.7 

Cellulosic Ethanol 0.2 16 15.8 

Imported Ethanol 0.4 3.1 0.27 

Biodiesel 0.27 0.70 0.43 

Renewable Diesel 0 0.19 0.19 

Total 13.5 36 22.5 

The gasoline and diesel fuel product energy output for each control and sensitivity case 

modeled was maintained the same as that for the reference case. Maintaining constant energy 

output assumes that vehicle miles traveled would remain the same between the various cases 

despite any change in gasoline and diesel fuel prices caused by the use of renewable fuels. In 

reality the increased use of renewable fuels may result in changes to fuel prices to consumers, 

either directly as estimated in this section, or indirectly by affecting world oil prices as discussed 

in Chapter 15. However, our analysis was conducted in parallel without the ability to input the 

DDDDDDDDDD The renewable fuels cost modeling assessed the impact of biodiesel fuel costs not including 0.11 

billion gallons of corn oil made into biodiesel fuel, which is included in the volumes summary shown in Tables 1.2­

1. 

602 
 

 

 

 

results of the other analysis. Furthermore, it is difficult to predict the impacts on fuel prices to 

consumers, especially in light of the federal tax subsidies which we accounted for in our 

analysis, and the many and diverse state tax subsidies which we did not attempt to account for. 

Maintaining constant fuel product energy output captures the capital cost differences between the 

cases. Table 4.4-3 below summarizes the volumes of gasoline and diesel fuel used for the 

reference case, the primary control case and two sensitivity cases.EEEEEEEEEE 

Table 4.4-3. 

Volumes of Gasoline and Diesel Fuel Used in Refinery Modeling 

(Billion Gallons/yr) 

Reference 

Case 

Primary 

Control Case 

Sensitivity Cases 

 13.2 Bgals 

Ethanol as 

E10 

35 Bgals of 

E10 & E85 

E10 35 Bgals of 

E10, E20 

& E85 

Gasoline 

Volume 

(Gasoline and 

Ethanol) 

169.3 176.7 171.4 176.7 

Diesel Volume 

(Diesel Only) 

69.3 68.5 68.5 68.5 

 All the other environmental and ASTM fuel quality constraints modeled in the reference 

case described above are assumed to apply to the control case as well. The reference and control 

cases where modeled assuming that ethanol CG blends are entitled to the current 1.0 psi RVP 

waiver during the summer (i.e., for all 9.0 RVP and many low RVP control programs) so as to 

assess the impact on summertime butane removal. The crude oil and product prices for the 

control case were the same as the reference case. The capital investments made for the reference 

case are not assumed to be sunk when the refinery model is assessing the economics for capital 

investments for the various control cases. Thus, the refinery model is free to optimize the capital 

investments made for each control case incremental to the base case. The control cases are run 

with capital costs evaluated at a 15 percent rate of return on investment (ROI) after taxes, but are 

then adjusted post-modeling to a 7 percent ROI before taxes. 

4.4.1.4 Ethanol Blending and Prices 

A special procedure was set up in the refinery model to capture the costs of blending 

ethanol. Because ethanol is primarily produced in the Midwest, but distributed to the final 

terminals where it is blended with the gasoline (or gasoline blendstock for blending with 

ethanol), hypothetical terminals were set up in each PADD within the refinery model which 

would receive the shipped ethanol as well as the gasoline blendstock for blending with ethanol 

EEEEEEEEEE The refinery modeling was run assuming about 20 billion gallons more gasoline demand and 8 billion 

gallons more diesel fuel demand than what AEO 2008 projects for the year 2022. This probably had only a very 

minor impact on the relative costs of the control cases compared to the reference case because the relative volume 

differences between the cases (considering the additions of renewable fuels) were modeled as intended. The actual 

AEO 2008 gasoline and diesel fuel volumes were used as the basis to estimate the per-gallon costs. 

603 
(also referred to as conventional blendstock for oxygenate blending (CBOB) for conventional 

gasoline and reformulated blendstock for oxygenate blending (RBOB) for RFG and CARFG). 

The gasoline blendstock either comes from the same PADD where the terminal is located, or 

transferred from a different PADD. This refinery modeling technique helps to more correctly 

estimate the distribution costs for both the ethanol and the gasoline. The refinery model assessed 

ethanol’s use in each PADD based on its price relative to CG and RFG, which is based on its 

production cost and distribution costs, and its blending economics. For the base case we 

assumed that ethanol would be splash blended into gasoline. But by 2022 we expect that most, if 

not all, of the ethanol will be octane match-blended for blending up E10. 

The price of ethanol used in the reference case, the primary control case and the 

sensitivity cases was based on the 2004 yearly average price spread between regular 

conventional gasoline sold into the spot market in Houston and ethanol sold on the spot market 

on Chicago Board of Trade (CBOT). This was used to determine a Midwest ethanol production 

price. To derive ethanol prices for all other PADDs outside the Midwest, the Midwest ethanol 

production price was then adjusted for transportation costs to deliver ethanol from the Midwest 

to end use terminals (see Section 4.2 for additional details). This assumes that the Midwest 

ethanol market will continue to set the price for ethanol – a reasonable assumption considering 

the significant amount of corn and other biomass available in the Midwest. The sales prices 

assigned to ethanol are summarized in Table 4.4-4. 

Table 4.4-4. Ethanol Prices used in Refinery Modeling 

PADD 1 PADD 2 PADD 3 PADD 

4/5 CA 

excl. 

California 

Summer 159.9 153.3 163.2 168.3 168.5 

Winter 152.5 145.9 155.8 160.9 161.1 

After the refinery modeling was completed, the ethanol prices and the costs for each case 

were adjusted to reflect the ethanol production and distribution costs described above in Sections 

4.1 and 4.2. The ethanol production cost is the volume-weighted average for ethanol sourced 

from corn, cellulose and imports. The combined ethanol production cost and combined biodiesel 

and renewable diesel costs for 2022 for the reference crude oil price and the high crude oil price 

scenarios are shown in Table 4.4-5. The biodiesel and renewable diesel fuel production costs are 

principally comprised of the feedstock costs from the FASOM agricultural model, and this model 

estimated lower feedstock costs at the higher crude oil price. While this outcome initially seems 

unlikely, it could be possible based on changes in production levels of some agricultural 

products, so we opted to use the FASOM feedstock costs and the lower production costs at the 

higher crude oil price. 

604 
 

Table 4.4-5. 

Average Production Cost for Ethanol, Biodiesel and Renewable Diesel Fuel 

Crude Oil Price $53/bbl $92/bbl 

Production 

Cost (c/gal) 

Production 

Cost (c/gal) 

Volumetric 

Fraction 

Corn Ethanol 147 154 0.13 

Cellulosic Ethanol 138 143 0.75 

Imported Ethanol 169 171 0.12 

Volume Weighted Cost 143 148 1.00 

Biodiesel 270 268 0.69 

Renewable Diesel Fuel 210 208 0.31 

Volume Weighted Cost 251 249 1.00 

The combined ethanol production and distribution costs and the biodiesel and renewable 

diesel production and distribution costs are summarized below in Table 4.4-6. We provided two 

sets of costs which represent the projected costs at the $53/bbl crude oil price and at the $92/bbl 

crude oil price. 

Table 4.4-6. Ethanol Costs used in the Cost Analysis Post-Refinery Modeling 

 Ethanol Costs Biodiesel Renewable 

Diesel 

Region PADD 1 PADD 2 PADD 3 PADD 4/5 

excl. CA 

CA U.S. U.S. 

$53/bbl Crude Oil Price 

Production 

Cost 

143 143 143 143 143 270 210 

Distribution 

Cost 

19.4 12.1 17.5 23.6 23.4 18.2 5.1 

Total Cost 162.4 155.1 160.5 166.6 166.4 288.2 215.1 

$92/bbl Crude Oil Price 

Production 

Cost 

148 148 148 148 148 268 208 

Distribution 

Cost 

21.3 13.3 19.3 26.0 25.7 20 5.6 

Total Cost 169.3 161.3 167.3 174 173.7 288.0 213.6 

The ethanol production and distribution costs summarized in Table 4.4-6 are different in 

value compared to the ethanol prices used in the refinery modeling summarized above in Table 

4.4-4. To capture the social costs of the RFS 2 program, we adjusted the initial costs of the 

refinery modeling cost analysis using the ethanol production and distribution costs. This cost 

adjustment was made by multiplying the difference in ethanol cost or price between Tables 4.4-6 

and 4.4-4 by the difference in ethanol volume modeled between the control case and the 

reference case. 

We also estimated the costs of the RFS 2 program taking into account the consumption 

605 
 

subsidies for corn ethanol, cellulosic ethanol, biodiesel and renewable diesel fuel. While these 

subsidies conceal large portions of the program costs, their economic effects deserve to be 

understood. 

4.4.1.5 E85 Blending and Prices 

We conducted the refinery modeling assuming that E85 will be blended differently in the 

future compared to how it is blended today. Today E85 is blended at 85 percent by volume in 

the summer and at 70 percent by volume in the winter. Ethanol must be blended at less than 85 

percent in the winter because of ethanol’s low blending Reid Vapor Pressure (RVP). Unlike 

when ethanol is blended at 10 percent and causes a large vapor pressure increase, when ethanol 

is blended at 85 percent it blends much closer to its very low neat blending RVP of 2.2. When 

ethanol is blended with gasoline at the terminal, the available gasoline blendstock must be used. 

This blendstock is either a conventional blendstock for oxygenate blending (CBOB) or 

reformulated blendstock for oxygenate blending (RBOB) so that when this gasoline-like material 

blended with ethanol at 10 percent, the final blend complies with the local gasoline regulations. 

For example, reformulated gasoline (RFG) must comply with the hydrocarbon standard of the 

RFG program and therefore RFG tends to have an RVP of 6.8, and the RBOB that is blended 

with ethanol has an RVP of about 5.8. When this 5.8 RVP RBOB is blended with ethanol to 

make E85, its final RVP is estimated to be 5.05. However, the RVP minimum specified in the 

E85 ASTM standard shows the summertime lower limit of E85 is 5.5, thus, blending RBOB with 

85 percent ethanol would not comply with the ASTM lower RVP standard. Table 4.4-7 

summarizes ethanol’s blending RVP, gasoline’s RVP and the final blend RVP for summertime 

RFG and CG gasoline, and compares the blends RVP values to that of the E85 ASTM RVP 

standards.934 

Table 4.4-7. Comparison of E85 RVP levels to the ASTM RVP Standard 

Summer E85 Winter E70 

Gasoline 

RVPa 

CG 10.0 RFG & low 

RVP 6.8 

ASTM Std CG/RFG 

14 

ASTM Std 

Gasoline 

Blendstock 

RVP 

9.0 5.8 13 

Ethanol 

Blending 

RVP 

4.9 4.9 - 6.5 

Blend 

RVP 

5.67 5.05 5.5 8.5 9.5 

a Summertime CG is allowed a 1 psi waiver for blending with ethanol, however, RFG and some 

low RVP areas and wintertime CG/RFG do not receive 1 psi waivers. 

Table 4.4-7 shows that summertime RFG and wintertime gasoline cannot meet the 

ASTM RVP minimum standards based on blending ethanol with the locally available gasoline 

blendstock for blending up E10. For this reason, we ran the refinery model assuming that all 

E85 will also be blended with some butanes or pentanes (whichever is available from the nearest 

refineries) to bring E85 up to the maximum ASTM RVP standard, in addition to the CBOB or 

606 
RBOB being supplied to the local area. The maximum ASTM E85 RVP standard is 8.5 in the 

summertime and 12.0 in the wintertime. 

E85 is expected to be priced lower in the marketplace than E10 and even less relative to 

gasoline (E0) because of E85’s lower energy density. E85 contains about 77,900 BTUs per 

gallon compared to E10 which contains about 111,300 BTUs per gallon. Thus, when consumers 

consider refueling their vehicle using E85, they will bypass using it unless if it is priced at parity 

with gasoline on an energy basis. Parity pricing means that E85 would have to be priced 25 

percent lower than E10. Assuming that E85 is priced 25 percent lower than E10 at retail to 

account for the energy content differences, the pricing disparity between ethanol and gasoline is 

even greater at the terminal. Table 4.4-8 summarizes the pricing of E85 at retail and at the 

terminal where ethanol is usually blended into gasoline blendstock to create the E85. Retail 

markup averages about 10 cents per gallon.935 Federal and state taxes average 46 cents per 

gallon (although this varies significantly by state), and transportation from the terminal to retail 

averages 3 cents per gallon.936 Thus, if E10 gasoline is priced 163 cents per gallon at the 

terminal, it would be priced at 223 cents per gallon at retail. Based on E85’s 25 percent lower 

energy density, E85 would have to be priced at 167 cents per gallon at retail to reflect its lower 

energy density. Using the same terminal to retail costs/taxes, E85 would be priced at 107 cents 

per gallon at the terminal. All this is shown in Table 4.4-8. The bottom row of the table shows 

what ethanol (E100) would have to be price at for terminals to breakeven using ethanol in E85 

(this assumes that E85’s gasoline blendstock is priced the same as E10 at the terminal). Based 

on ethanol’s energy content alone, ethanol would have to be discounted significantly compared 

to gasoline for refiners to find it cost-effective to use. 

Table 4.4-8. E85 Pricing at Retail and at Terminals (cents per gallon) 

 Price at 

Retail 

Retail 

Markup 

Average 

Federal and 

State Taxes 

Transportation 

terminal to 

retail 

Terminal 

Price 

Gasoline E10 223 10 46 3 164 

E85 167 10 46 3 108 

Ethanol 

Breakeven 

Price 

- - - - 97 

In addition to this effect of energy equivalency, Section 1.7 above outlines the difficulty 

of using all this E85 because of the relatively low number of fuel flexible vehicles (FFVs) that 

will be available to consume the fuel. The relatively low number of FFVs means that the 

refueling rate of these vehicles will have to be very high. In the year 2022, we estimated in 

Section 1.7 that FFVs will have to refuel 74 percent of the time to use the volume of ethanol 

required by the RFS2 standard. This E85 refueling level is even more severe considering that 

that it is unlikely that every service station would make the capital investments to make E85 

available for sale. In Section 4.2, we estimate that one out of very four service stations will carry 

E85. Thus, E85 may have to be priced even lower than its fuel economy-adjusted price to entice 

FFV owners to refuel at a station carrying E85. To estimate the marginal lower price at which 

FFV owners would refuel at this high rate, we referenced an analysis based on a willingness to 

pay survey conducted by David Greene of the Oak Ridge National Laboratory.937 The summary 

607 
of this analysis is depicted in the Figure 4.4-1. 

Figure 4.4-1

Alternative Fuel Market Share as a Function of Fuel Availabilityailability and

Price Advantage (David L. Greene, 1997, Figure 6) 

X $0.21/gal Price Advantage (1997$) 

Refueling frequency given 

“reasonable access” 

Percent of stations offering E85 in areas of the

country with “reasonable access”, i.e., 25% 

 Based on our estimates that E85 would have to be purchased 74 percent of the time and 

that one out of every four service stations would carry E85, then Figure 4.4-1 estimates that E85 

would have to be priced 21 cents per gallon lower than gasoline to match this availability and 

refueling scenario. This cost estimate is based in 1997 dollars. Adjusting this cost estimate to 

608 
 

 

 

2006 dollars increases this estimate to 26 cents per gallon.FFFFFFFFFF 

There is one more factor which we believe could affect the price of E85. FFV owners 

who refuel on E85 will drive fewer miles before having to refuel compared to operating their 

vehicle on gasoline. The FFV drivers will therefore spend more time refueling their vehicle. As 

described above, FFV owners will drive 25 percent fewer miles per gallon and thus, will have to 

spend 25 percent more time refueling. We estimate that each refueling event requires 6 minutes 

of time, and that a person’s time is worth an average of 30 dollars per hour.938,939,940,941 Finally 

we assumed that a typical refueling volume for a refueling event is 15 gallons. Using these 

assumptions, the increased refueling frequency is costing the average FFV owner 5 cents per 

gallon more to use E85. To account for this additional cost, E85 would have to be priced 5 cents 

per gallon lower to make refueling FFVs a breakeven proposition. For our refinery modeling 

work, we reduced the refiner purchase price of E85 used in our refinery modeling analysis by 

this additional 5 cents per gallon. 

Table 4.4-9 summarizes the E85 refinery purchase prices at terminals by PADD used in 

our refinery modeling work. These prices represent the total of the energy content, the price 

adjustment for reduced fuel availability and the cost for increased refueling events. The E85 

prices should be compared to regular grade gasoline because the FFVs generally only require 

regular grade gasoline when operated on gasoline. 

Table 4.4-9. Wholesale E85 Prices used within the Refinery Model 

E85 used in Conventional 

Gasoline Areas (c/gal) 

E85 used in Reformulated 

Gasoline Areas (c/gal) 

PADD 1 Summer 

 Winter 

76 

67 

81 

72 

PADD 2 Summer 

 Winter 

75 

66 

80 

71 

PADD 3 Summer 

 Winter 

74 

65 

79 

70 

PADDs 4/5 Summer 

 Winter 

84 

75 

80 

81 

CA Summer 

 Winter 

-

-

86 

77 

While we used these E85 prices within the refinery model, they don’t necessarily 

represent the societal costs for using E85. The pricing to reflect reduced fuel availability, in 

particular, contains a significant amount of transfer payments from the refining industry to 

consumers and other entities, and these transfer payments do not represent the true cost for using 

FFFFFFFFFF If E85 is used to comply with the RFS2 standard as envisioned, and if E85 would have to be priced as low 

as we projected, refiners would probably have to find a way to recoup their financial losses for using E85. One way 

refiners could do that would be to price E10 gasoline somewhat higher to recoup the E85 financial loss. Since we 

are solely interested in estimating the social cost of the RFS2 program, we did not make this sort of adjustment to 

the price of E10. 

609 
 

 

 

E85.GGGGGGGGGG 

For estimating the program costs for using E85 (shown in Tables 4.4-12 and 4.4-13), we 

adjusted E85 price back up to 5 cents per gallon less than the gasoline price for each case (the 

additional time spent refueling is a true cost). We then used the relative energy density of the 

E85 to that of gasoline as reported by the refinery model (see energy content values in Table 4.4­

20) to account for the energy density costs for using E85. We preferred the energy content price 

cost made by the refinery model to our preliminary E85 energy content price adjustments 

because the refinery model can also account for changes in gasoline energy content made when 

accommodating the blending of ethanol. We are not assuming that the price adjustment that we 

made to account for lower E85 availability account for any additional social cost. If the FFV 

driver would have to drive out of his way from time-to-time to find the E85, then there would be 

some extra cost associated with the lower availability. But most of the time FFV drivers would 

likely learn where to find E85 along the routes that they normally frequent, thus, no additional 

effort and cost would be incurred for refueling on E85. Thus, we assume that the lower E85 

price to account for reduced E85 availability is purely a transfer payment from the refiner to the 

FFV owner. 

The assumption used here and throughout this proposed rulemaking is that ethanol’s fuel 

economy is directly proportional to its energy density and its concentration in the fuel. Since the 

volumetric energy content of ethanol is approximately 33 percent less than conventional 

gasoline, we assumed this loss in fuel economy proportional to its concentration in the fuel. 

Some studies have suggested, however, that ethanol’s decrease in fuel economy may be less than 

its relative decrease in volumetric energy content of the fuel. In other words, there is less of a 

fuel consumption decrease than what the lower energy density of ethanol would suggest. 

However, for a variety of reasons, we have reason to question the data from these studies. We 

therefore intend to investigate this issue more for the final rule as new data become available. 

4.4.1.6 Other Adjustments to the Costs 

As discussed above, we needed to adjust the estimated program costs from costs based on 

$51/barrel crude oil, the crude oil price at which the refinery model was run, to $53/bbl and 

$92/bbl, the crude oil costs that served as the basis for our cost analysis. To make these 

adjustments we estimated the wholesale gasoline and diesel fuel prices (which are the surrogate 

for the gasoline and diesel fuel production costs) at the adjusted crude oil price and compared 

these adjusted wholesale gasoline and diesel fuel adjusted prices to the baseline wholesale 

gasoline and diesel fuel prices. The baseline wholesale gasoline and diesel fuel prices, based on 

an average $51/bbl crude oil price, are summarized in Table 4.4-1. To adjust these wholesale 

prices, we needed to estimate how the price of crude oil will affect them. We conducted a 

regression between the annual average spot price of price of Western Texas Intermediate crude 

oil and the annual average retail gasoline and diesel fuel prices for the years 2002 through 

2006.942,943 This regression is reflected in Table 4.4-10 as Gasoline Retail Price = Crude Oil 

Price multiplied times 2.95 plus 65.7, or Gasoline Retail Price = Crude Oil Price x “X” + “Y.” 

The slope “X” and intercept “Y” for this equation are summarized in Table 4.4-10. The X and Y 

GGGGGGGGGG The possibility for this potentially large transfer payment associated with using ethanol in E85 would 

cause refiners to encourage the development of a cellulosic diesel fuel industry to avoid this E85 issue. 

610 
 

factors for diesel fuel are also summarized in Table 4.4-10 as well. However, we needed to 

estimate the wholesale prices instead of the retail prices, so we adjusted the equations to estimate 

the wholesale price using the Jacob’s wholesale prices as the calibrating values. The regression, 

including the adjustment values to derive the wholesale prices equations are summarized in 

Table 4.4-10. 

Table 4.4-10. 

Equations Used for Estimating Wholesale Average Gasoline and Diesel Fuel Prices* 

Equation for Retail Prices Equation for Wholesale Prices 

X Y X Adjusted Y 

Gasoline 2.95 65.7 2.95 +7.7 

Diesel Fuel 3.46 41.5 3.46 -17.0 

* The equation is used by multiplying the crude oil price ($/bbl) times the X and then adding Y to that 

product resulting in a gasoline or diesel fuel cost expressed in cents per gallon. 

The equations were used to estimate the average wholesale gasoline and diesel fuel 

prices. These average wholesale gasoline and diesel fuel prices are summarized in Table 4.4-11. 

Table 4.4-11 

Average Gasoline and Diesel Fuel Wholesale Prices by Crude Oil Price 

(c/gal) 

Crude Oil Price Gasoline Diesel Fuel 

51 158 149 

53 164 157 

92 279 313 

Table 4.4-11 shows the nationwide average costs, but our cost analysis was conducted on 

a PADD basis, thus, it was necessary to estimate revised gasoline and diesel fuel wholesale 

prices in each PADD. This was accomplished by generating a ratio of the average wholesale 

gasoline and diesel fuel prices at the higher crude oil price relative to the average wholesale and 

applying this ratio to the gasoline price in each PADD. It is important to note gasoline and diesel 

fuel pricing changes captured by our crude oil/gasoline and diesel fuel price relationship price 

model. Prior to 2005, diesel fuel was priced about the same as gasoline (+/- 5 cents per gallon on 

a yearly average). In 2005 and 2006, when crude oil was priced higher, diesel fuel was priced 13 

cents per gallon higher than gasoline. Thus, the equation picks up this relatively higher diesel 

fuel price at the higher crude oil prices in 2005 and 2006 and projects an even greater relative 

higher price for diesel fuel at our high crude oil price of $92/bbl. A higher relative diesel fuel 

price at higher crude oil prices in the future may be appropriate for a couple reasons. The first 

reason is that from January to mid-October 2008, when crude oil prices were very high, diesel 

fuel averaged 51 cents per gallon higher than gasoline. While we cannot say for certain that this 

association would always hold true at higher crude oil prices, we do have a possible explanation 

for a possible relationship here. Higher crude oil prices are likely to affect gasoline demand 

more than diesel fuel as more of the trips made by gasoline powered light-duty vehicles are 

discretionary. For example, people may readily change their vacations plans at higher crude oil 

prices, while diesel fuel used to power trucks that bring food to markets would be expected to 

611 
 

 

continue. Thus, as crude oil prices increase, gasoline consumption is likely more elastic 

resulting in greater reductions in gasoline demand compared to diesel fuel. We therefore believe 

that higher crude oil prices will tend towards relatively higher diesel fuel prices compared to 

gasoline. 

For other reasons, diesel fuel prices may trend higher in the future relative to gasoline 

prices. Because EISA required that corporate average fuel economy (CAFE) standards be 

increased for light duty motor vehicles, over time light duty vehicles, which are almost 

exclusively gasoline powered, will become more fuel efficient. This will cause gasoline demand 

to decrease, while diesel demand is projected to continue to increase. A second reason why 

refinery gasoline production will decrease is that most of the renewable fuel volume being 

produced to comply with the RFS is ethanol, and it will displace gasoline. This will contribute to 

the over supply of gasoline and the relative undersupply of diesel fuel, thus causing gasoline 

prices to be soft relative to diesel fuel prices. 

Another adjustment we made to the costs directly estimated by the LP refinery cost 

model was to add additional cost for distributing gasoline from the refinery to the terminal. The 

refinery cost model assigned a low distribution costs to gasoline for moving the gasoline from 

the refinery to the terminal. We estimate that this distribution cost should be about 4 cents per 

gallon, but the refinery model only assigned 2.5 cents per gallon for this. Thus, we credited 

ethanol 1.5 cents per gallon for each gasoline-equivalent gallon of ethanol blended into each 

PADD’s gasoline, since this roughly corresponded to the volume of gasoline displaced by the 

ethanol. 

4.4.2 Refinery Modeling Results 

In this subsection, we summarize the results of the three refinery modeling cases that we 

conducted, the primary control case, and the sensitivity cases, which include the E10 case and 

the mid-ethanol blend case. Additional detail concerning the refinery modeling results is 

contained in Jacob’s refinery modeling report contained in the docket. 

4.4.2.1 Control Case 

Tables 4.4-12 and 4.4-13 summarize the costs for the control case excluding federal 

ethanol, biodiesel and renewable diesel tax subsidies with crude oil priced at $53/bbl and 

$92/bbl, respectively. The costs are reported by different cost components as well as aggregated 

total and per-gallon costs.HHHHHHHHHH This estimate of costs reflects the changes in gasoline that 

are occurring with the expanded use of ethanol, biodiesel and renewable diesel. The operating 

costs include the labor, utility and other operating costs and are a direct output from the refinery 

model. These costs are adjusted to reflect ethanol’s production cost plus distribution costs 

instead of the ethanol prices used in the refinery cost model. The fixed costs are 3 percent of the 

reduced capital costs. The costs associated with lower energy density gasoline are accounted for 

HHHHHHHHHH EPA typically assesses social benefits and costs of a rulemaking. However, this analysis is more limited 

in its scope by sometimes examining the marginal production cost and the average production cost of ethanol and 

gasoline. 

612 
 

 

using the fractional change in energy density shown in Table 4.4-20, multiplied times the 

wholesale price of gasoline. By excluding the federal ethanol, biodiesel and renewable diesel 

fuel consumption subsidies, we avoid the transfer payments caused by these subsidies that would 

hide a portion of the program’s costs. The variable operating costs line item in Table 4.4-12 and 

4.4-13 capture several different aspects of this category of costs. In addition to ethanol’s 

blending costs captured by the refinery model, this category of costs captures ethanol’s higher 

production and distribution cost. At $53 per barrel crude oil costs, ethanol’s production and 

distribution costs are higher than the gasoline wholesale cost. Another item of the variable cost 

is the 5 cents per gallon refueling costs. Finally, this category of costs captures the 5 cents per 

E85 gallon cost which covers the cost of producing fuel flexible vehicles (FFVs) instead of nonFFVs. 

Table 4.4-12. 

Summary of Control Case Costs (without Tax Subsidies) 

(million dollars/year and c/gal, except as noted; 2006 dollars, 7% ROI before taxes, $53/bbl crude oil price) 

Cost to Gasoline Cost to Diesel Fuel 

Refinery Capital Costs ($Billion) -7.89 -

Amortized Refinery Capital Costs ($MM/yr) -842 -

Fixed Operating Cost ($MM/yr) -232 -

Variable Operating Cost ($MM/yr) 7,690 590 

Lower Energy Density ($MM/yr) 10,340 187 

Total Cost ($MM/yr) 16,960 777 

Amortized Refinery Capital Costs (c/gal) -0.48 -

Fixed Operating Cost (c/gal) -0.13 -

Variable Operating Cost (c/gal) 5.66 0.66 

Lower Energy Density (c/gal) 5.85 0.54 

Total Cost Excluding Subsidies (c/gal) 10.91 1.20 

Table 4.4-13. 

Summary of Control Case Costs (without Tax Subsidies) 

(million dollars/year and c/gal, except as noted; 2006 dollars, 7% ROI before taxes, $92/bbl crude oil price) 

Cost to Gasoline Cost to Diesel Fuel 

Amortized Refinery Capital Costs ($MM/yr) -842 -

Fixed Operating Cost ($MM/yr) -232 -

Variable Operating Cost ($MM/yr) -12,410 -419 

Lower Energy Density ($MM/yr) 17,598 373 

Total Cost ($MM/yr) 4,120 -46 

Refinery Capital Costs (c/gal) -0.48 -

Fixed Operating Cost (c/gal) -0.13 -

Variable Operating Cost (c/gal) -6.70 -1.15 

Lower Energy Density (c/gal) 9.95 1.08 

Total Cost Excluding Subsidies (c/gal) 2.65 -0.07 

Our analysis shows that when considering all the costs associated with these fuel changes 

resulting from the expanded use of ethanol, that these various possible gasoline use scenarios 

will cost the U.S. nearly $17 billion per year in the year 2022 when crude oil is priced at $53 per 

barrel. Expressed as per-gallon costs, these fuel changes would cost the U.S. 10.91 cents per 

gallon of gasoline. The addition of biodiesel and renewable diesel fuel is estimated to cost about 

613 
 

 

 

 

 

$780 million per year in the year 2022, or cost 1.20 cents per gallon. 

At $92 per barrel crude oil, the addition of the ethanol is estimated to cost 4.1 billion per 

year in 2022, and cost 2.65 cents per gallon. The addition of biodiesel and renewable diesel fuel 

is estimated to reduce the cost of diesel fuel by 46 million dollars in 2022, and reduce the pergallon cost of diesel fuel by 0.07 cents per gallon. 

Tables 4.4-12 and 4.4-13 express the total and per-gallon gasoline costs for the RFS case 

with the federal ethanol, biodiesel and renewable diesel subsidies included with crude oil priced 

at $53/bbl and $92/bbl, respectively. The federal tax subsidy is 45 cents per gallon for each 

gallon of new corn-based ethanol blended into gasoline and 101 cents per gallon for each gallon 

of cellulosic ethanol. Imported ethanol is also assumed to receive the 45 cents per gallon starch 

ethanol subsidy, although we assume that a greater volume of imported ethanol would be used 

than that which can flow through the Caribbean Basin, tariff free. Thus the 51 cents per gallon 

tariff would apply to that incremental volume of imported ethanol above the allowable Caribbean 

Basin initiative volume. We estimate that imported ethanol would earn 23 cents per gallon net 

subsidy. The biodiesel subsidy is 100 cents per gallon, and the renewable diesel fuel subsidy is 

50 cents per gallon.IIIIIIIIII The cost adjustment is estimated by multiplying the subsidy times the 

volume of new ethanol, biodiesel and renewable diesel estimated to be used. 

Table 4.4-14. 

Estimated Control Case Costs (Reflecting Tax Subsidies) 

(million dollars/year and cents/gallon; 2004 dollars, 7% ROI before taxes, $53/bbl crude oil price) 

 Cost to Gasoline Cost to Diesel Fuel 

Total Cost ($MM/yr) 16,957 777 

Federal Subsidy ($MM/yr) -17,699 -525 

Revised Total Cost ($MM/yr) -742 252 

Per-Gallon Cost Excluding Subsidies (c/gal) 10.91 1.20 

Federal Subsidy (c/gal) -11.39 -0.81 

Total Cost Including Subsidies (c/gal) -0.48 0.39 

Table 4.4-15. 

Estimated Control Case Costs (Reflecting Tax Subsidies) 

(million dollars/year and cents/gallon; 2004 dollars, 7% ROI before taxes, $92/bbl crude oil price) 

Cost to Gasoline Cost to Diesel Fuel 

Total Cost ($MM/yr) 4,116 -46 

Federal Subsidy ($MM/yr) -17,699 -535 

Revised Total Cost ($MM/yr) -13,583 -571 

Per-Gallon Cost Excluding Subsidies (c/gal) 2.65 -0.07 

Federal Subsidy (c/gal) -11.39 -0.81 

Total Cost Including Subsidies (c/gal) -8.74 -0.88 

The cost including subsidies would represent gasoline and diesel fuel’s apparent cost as 

reflected to the fuel industry as a whole because the federal tax subsidies tends to transfer a 

IIIIIIIIII The recent economic stimulus law passed by Congress extended the biodiesel and renewable diesel fuel 

subsidies, and it also increased the renewable diesel fuel subsidy to 100 cents per gallon. However, the increase in 

renewable diesel fuel subsidy occurred too late to account for this change in our cost analysis. 

614 
 

portion of the actual costs. Our analysis estimates that when the oil price is $53/bbl, the fuel 

industry will see a 0.48 cent per gallon decrease in the apparent cost of producing gasoline, and a 

0.39 increase in the apparent cost of producing diesel fuel. At the higher oil price of $93/bbl, the 

apparent cost of producing gasoline is estimated to decrease by 8.7 cents per gallon, and the 

apparent cost of producing diesel fuel is expected to decrease by 0.88 cents per gallon. These 

costs would also represent the apparent cost to consumers “at the pump” if the full tax credit 

were passed along to the consumers. However, it is possible that only a portion of the tax 

subsidy will be passed along to the consumer (historically, this has been the case). Thus, the 

price impact at the pump may be somewhere between the values in Tables 4.4-10 and 4.4-11, 

and Tables 4.4-12 and 4.4-13. However, consumers would also pay the full tax subsidy through 

higher taxes in addition to the values in Tables 4.4-12 and 4.4-13. 

Table 4.4-14 summarizes the volumetric inputs to refineries in each PADD for this 

control case. Because of the increased use of biofuels, petroleum inputs would be expected to 

decrease, and this is confirmed. 

Table 4.4-16. 

Summary of the Total and Incremental Volumetric Refinery Inputs by PADD 

(thousand barrels/day) PADD 1 PADD 2 PADD 3 PADD 4/5 CA 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

PADD Crude 1,525 0 3,317 -245 8,642 -458 1,726 -21 2,098 -39 

GTL Naphtha 0 0 0 0 0 0 0 0 0 0 

GTL Diesel 0 0 0 0 0 0 0 0 0 0 

VGO HS 0 0 0 0 483 -139 0 0 4 -24 

VGO LS 0 0 1 0 0 0 0 0 0 0 

HS AR (A960) 0 0 0 0 0 0 0 0 0 0 

LS AR (Alg) 200 -1 0 0 267 139 0 0 0 0 

Normal Butane 31 5 61 6 112 0 38 1 40 0 

Isobutane 14 4 22 0 44 -23 10 -4 14 -10 

MTBE 0 0 0 0 0 0 0 0 0 0 

Ethanol - E10 360 14 237 46 180 85 82 27 163 -8 

Ethanol - E20 0 0 0 0 0 0 0 0 0 0 

Ethanol - E85 475 475 174 174 370 370 67 67 118 118 

Reformer Feed 0 0 0 0 0 0 0 0 0 0 

Methanol 0 0 0 0 0 0 0 0 0 0 

Natural Gas (FOE) 67 -12 145 4 557 -13 119 -3 175 2 

Hydrogen (MSCF) 0 0 0 0 0 0 0 0 0 0 

Pentanes Plus 0 0 32 0 52 0 19 0 0 0 

Import CBOB 10% 277 277 0 0 0 0 0 0 0 0 

Import CBOB 20% 0 0 0 0 0 0 0 0 0 0 

Import RBOB 10% 123 -77 0 0 0 0 0 0 0 0 

Import RBOB 20% 0 0 0 0 0 0 0 0 0 0 

Import Alkylate 46 30 0 0 0 0 0 0 0 0 

Import Raffinate 4 -44 0 0 0 0 4 4 46 0 

Import Reformate 0 0 0 0 0 0 0 0 0 0 

Import FCC Naphtha 0 0 0 0 0 0 0 0 0 0 

Import Lt Naphtha 14 14 0 0 23 -7 0 0 1 0 

Import Hvy Naph 0 0 0 0 42 0 0 0 0 0 

Transfer Lt Naphtha 0 0 0 0 0 0 0 0 12 -12 

Transfer Reformate 0 0 0 -5 0 0 0 0 0 0 

Transfer Alkylate 60 0 6 3 0 0 0 0 60 0 

Transfer FCC Naphtha 0 0 0 0 0 0 0 0 0 0 

Transfer Raffinate 0 0 4 2 0 0 0 0 60 0 

Transfer RBOB 10% 662 -34 79 29 0 0 0 0 0 0 

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0 

Transfer CBOB 10% 1,300 2 421 -29 0 0 1 1 0 0 

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0 

Isooctane 2 2 0 0 0 0 0 0 35 7 

Isooctene 1 -10 0 -2 0 0 0 0 0 0 

Table 4.4-16 shows that inputs of crude oil decreases substantially in most of the PADDs. 

In two of the PADDs, vacumn gas oil (VGO) inputs to refineries decreases, which is reasonable 

615 
 

since VGO is a feedstock to fluidized catalytic cracker units, a large gasoline blendstock 

production unit within refineries. 

Table 4.4-17 below summarizes the refinery output volumes and changes in refinery 

output volumes relative to the reference case by PADD. 

Table 4.4-17. 

Summary of Total and Incremental Refinery Outputs by PADD 

(thousand barrels/day) PADD 1 PADD 2 PADD 3 PADD 4/5 CA 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Propane 33 -1 54 -10 145 0 26 -2 58 0 

Propylene 19 0 43 0 245 0 2 0 12 0 

Normal Butane 0 0 0 -4 30 -16 0 0 0 0 

Isobutane 0 0 0 0 0 0 4 4 14 6 

PC Naphtha 16 0 40 0 433 0 0 0 0 0 

PC Gasoil 0 0 496 -60 158 0 0 0 0 0 

CG Reg 0 -73 0 -552 0 -1,176 0 -246 0 0 

CG Prem 0 0 0 0 0 -2 0 -33 0 0 

CG E10 Reg 1,916 436 1,667 495 1,069 928 671 220 115 3 

CG E10 Prem 268 10 343 14 262 11 143 43 22 1 

RFG E10 Reg 1,099 -322 273 -55 358 -105 0 0 1,218 -94 

RFG E10 Prem 285 14 65 3 92 4 0 0 258 8 

CG E20 Reg 0 0 0 0 0 0 0 0 0 0 

RFG E20 Reg 0 0 0 0 0 0 0 0 0 0 

E85 to CG 156 156 133 133 306 306 78 78 0 0 

E85 to RFG 398 398 70 70 125 125 0 0 137 137 

Transfer RBOB 10% 0 0 0 0 741 -5 0 0 0 0 

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0 

Transfer CBOB 10% 0 0 0 0 1,722 -27 0 0 0 0 

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0 

Jet/Kero A (450ppm) 27 0 115 0 1,363 0 380 0 300 0 

X-Fer Diesel Rundown t 0 0 0 0 0 0 0 0 0 0 

HSD Gr 76 (0.2%) 0 0 0 0 0 0 0 0 0 0 

LSD Gr 74 (.05%) 0 0 0 0 0 0 0 0 0 0 

ULSD (15 ppm) 565 13 648 -29 2,189 -34 515 4 0 0 

CARB Diesel 0 0 0 0 0 0 0 0 354 -4 

X-Fer C5's to Storage 0 0 0 0 0 0 0 0 0 0 

1% Residual Fuel 0 0 0 0 0 0 0 0 0 0 

Residual Fuel 86 16 57 0 251 -21 151 5 68 -5 

Slurry 31 -1 80 -9 158 0 0 0 30 0 

Asphalt & Wax 143 0 210 0 158 0 5 0 44 0 

Gasoil 0 0 9 0 0 0 0 0 10 0 

Lubes 19 0 17 0 158 0 0 0 20 0 

Benzene 11 0 11 0 51 0 0 0 0 0 

Toluene 0 0 0 0 35 0 0 0 0 0 

Xylenes 0 0 0 0 8 0 0 0 0 0 

Cumene 0 0 0 0 0 0 0 0 0 0 

Cyclohexane 0 0 0 0 0 0 0 0 0 0 

Transfer Raffinate 0 0 0 0 64 2 0 0 0 0 

Transfer Alkylate 0 0 0 0 126 3 0 0 0 0 

Transfer Reformate 0 0 0 0 0 -5 0 0 0 0 

Transfer FCC naphtha 0 0 0 0 0 0 0 0 0 0 

Transfer Lt Naphtha 0 0 0 0 0 0 0 0 12 -12 

Transfer Blendstock 0 0 0 0 0 0 0 0 0 0 

Sulfur (STons) 1 0 4 0 16 -1 2 0 4 0 

Coke (STon) 1 -1 12 -2 65 -4 7 0 19 -1 

Table 4.4-18 summarizes the change in refinery unit capacities by PADD comparing the 

control case to the reference case. 

616 
Table 4.4-18. 

Change in Refinery Unit Capacities by PADD relative to the Reference Case 

(thousand barrels/day) 

Refinery Unit PADD 1 PADD 2 PADD 3 PADD 4/5 CA U.S. 

Crude Tower 0 -421 -398 0 0 -818 

Vacuum Tower 0 -188 -160 5 0 -343 

Sats Gas Plant -29 0 -35 1 -4 -66 

Unsats Gas Plant 0 -1 -53 0 -12 -66 

FCC DeC5 Tower 0 0 0 0 0 0 

FCC 0 0 -175 0 -63 -238 

FCC Splitter 0 -6 -97 0 -20 -123 

Hydrocracker 0 0 0 -3 0 -3 

H-Oil Unit 0 0 0 0 0 0 

Delayed Coker 0 0 -91 0 0 -91 

Visbreaker 48 0 0 0 0 48 

Thermal Naphtha Splitter 0 -4 -11 0 -1 -16 

CRU Reformer 0 0 0 0 0 0 

SRU Reformer 0 0 0 0 3 3 

BTX Reformer 0 1 0 0 0 1 

C4 Isomerization 0 0 0 0 -4 -4 

C5/C6 Isomerization -1 0 0 0 0 -1 

HF Alkylation 0 0 0 0 0 0 

H2SO4 Alkylation -22 0 -51 -15 -26 -113 

Dimersol 0 0 0 0 0 0 

Cat Poly 9 0 0 0 0 9 

Isooctane 0 0 0 0 0 0 

DHT - Total 7 0 -93 3 0 -84 

DHT 2nd RCT - Total 11 53 -69 -4 15 7 

DHT Arom Saturation 0 0 0 0 0 0 

NHT - Total Fd -16 0 0 -2 0 -17 

CGH - Generic 2 -48 25 8 0 -13 

CGH - Olefin Sat'n 0 0 0 0 0 0 

FCCU Fd HDT 0 0 0 -34 60 26 

LSR Splitter 0 16 0 0 0 16 

LSR Bz Saturator 0 0 0 0 0 0 

Reformate Saturator -9 0 -1 0 0 -9 

Reformate Splitter -26 0 -2 0 0 -28 

SDA 0 0 0 0 0 0 

MTBE 0 0 0 0 0 0 

TAME 0 0 0 0 0 0 

Hydrogen Plant - Total MSCF 7 34 36 -19 20 77 

Lube Unit 0 0 0 0 0 0 

Sulfur Plant 0 0 -1,402 -56 -96 -1,553 

Merox Jet 0 0 0 0 0 0 

Merox Diesel 0 0 0 0 0 0 

BTX Reformer - Tower feed 0 0 0 0 0 0 

BTX Reformer - Extract feed 1 1 0 0 0 1 

Most of the capacity throughput changes are negative, reflecting the decreased processing 

of crude oil and vacuum gas oil and decreased downstream refining units as projected by the 

refinery model. Of the negative throughput changes, the large reduced volume of the fluidized 

catalytic cracker unit is important. As discussed above, the refinery model likely chose to 

decrease the fluidized catalytic cracker throughput to crack less heavy hydrocarbons to light 

hydrocarbons, producing less gasoline material to offset the increased volume of ethanol. 

Another important decrease in refinery unit throughput is the alkylation unit. Because the 

617 
alkylation unit is responsible for increasing octane, its decrease reflects the rebalancing by the 

refinery model to adjust for the large increase in the volume of high octane ethanol. 

These changes in refinery unit throughputs are associated with changes in capital 

investments. Table 4.4-19 summarizes the projected change in capital investments between the 

control case and the reference case. This Table shows that incremental to the reference case, 

refiners are expected to reduce their capital investments by $7.9 billion compared to business as 

usual. Most of the reduction occurs in PADDs 2 and 3 where large volumes of ethanol, and 

other gasoline blendstocks are expected to enter the gasoline pool. Of course, this capital cost 

decrease is countered by the capital costs incurred to build new ethanol plants and to put into 

place the distribution system that the new ethanol requires (see Table 4.4-21 below). 

618 
 

Table 4.4-19. 

Change in Refinery Unit Investments by PADD (million dollars/year)
 Refinery Unit PADD 1 PADD 2 PADD 3 PADD 4/5 CA U.S. 

Crude Tower 0 -995 -665 0 202 -1,660 

Vacuum Tower 0 -527 -315 85 30 -756 

Sats Gas Plant -112 0 -103 3 17 -249 

Unsats Gas Plant 0 0 -260 0 0 -362 

FCC DeC5 Tower 0 0 0 0 0 0 

FCC 0 0 -1,280 0 0 -2,066 

FCC Splitter 0 -6 -47 0 0 -69 

Hydrocracker 0 0 0 -65 0 -65 

H-Oil Unit 0 0 0 0 0 0 

Delayed Coker 0 0 -1,261 0 0 -1,261 

Visbreaker 170 0 0 0 0 170 

Thermal Naphtha Splitter 0 -5 -4 0 3 -11 

CRU Reformer 0 0 0 0 0 0 

SRU Reformer 0 0 0 0 32 72 

BTX Reformer 0 11 2 0 0 13 

C4 Isomerization 0 0 0 0 14 -23 

C5/C6 Isomerization -64 0 0 0 0 -64 

HF Alkylation 0 0 0 0 0 0 

H2SO4 Alkylation -372 0 -557 -227 10 -1,617 

Dimersol 0 0 0 0 0 0 

Cat Poly 72 0 0 0 0 72 

Isooctane 0 0 0 0 0 0 

DHT - Total 42 0 -689 17 32 -631 

DHT 2nd RCT - Total 50 344 -313 -17 60 133 

DHT Arom Saturation 0 0 0 0 0 0 

NHT - Total Fd -70 0 0 -6 0 -76 

CGH - Generic 8 -200 101 26 0 -64 

CGH - Olefin Sat'n 0 0 0 0 0 0 

FCCU Fd HDT -2 0 0 -349 60 443 

LSR Splitter 0 7 0 0 8 7 

LSR Bz Saturator 0 0 0 0 0 0 

Reformate Saturator -39 0 -2 0 50 -41 

Reformate Splitter -39 0 -1 0 150 -40 

SDA 0 0 0 0 0 0 

MTBE 0 0 0 0 0 0 

TAME 0 0 0 0 0 0 

Hydrogen Plant - Total MSCF 19 118 95 -49 27 255 

Lube Unit 0 0 0 0 56 0 

Sulfur Plant 0 0 -3 0 437 -4 

Merox Jet 0 0 0 0 0 0 

Merox Diesel 0 0 0 0 0 0 

BTX Reformer - Tower feed 0 1 0 0 0 1 

BTX Reformer - Extract feed 3 3 0 0 0 6 

Total -334 -1,250 -5,304 -582 0 -7,887 

Table 4.4-19 essentially expresses the change in refinery capacity input shown in Table 

4.4-18, but expresses the changes in terms of dollars instead of thousands of barrels per day. The 

total reduced capital investment is 7.89 billion dollars. 

Table 4.4-20 summarizes the gasoline volume and qualities by different gasoline types 

for the control case, and also, for comparison, lists the same for the reference case. 

619 
Table 4.4-20. 

Gasoline Volume, Quality and Energy Density by Gasoline Type 

at the PADD Terminal 

RFG 

PADD 1 PADD 2 PADD 3 PADD 4/5 CA US 

Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control 

Total ('000 BPD) 1,692 1,384 391 338 551 450 - - 1,562 1,476 4,197 3,649 

Ethanol ('000 BPD) 171 140 39 34 56 45 - - 158 149 424 369 

RVP (psi) 10.7 10.6 10.4 11.3 9.7 10.6 - - 9.5 9.4 10.1 10.2 

Sulfur (ppm) 23 24 23 23 20 22 - - 9 10 17 18 

Octane (R+M/2) 88.1 88.3 88.0 88.2 88.0 88.2 - - 87.6 87.7 87.9 88.0 

Aromatics (vol%) 19.9 19.9 20.0 19.6 19.5 19.5 - - 21.3 21.7 20.4 20.6 

Benzene (vol%) 0.55 0.58 0.58 0.56 0.51 0.48 - - 0.51 0.52 0.53 0.54 

Olefins (vol%) 11.7 11.6 10.3 10.4 8.7 11.1 - - 5.7 5.7 8.9 9.0 

Oxygen (wt%) 3.7 3.7 3.7 3.7 3.7 3.7 - - 3.7 3.7 3.7 3.7 

E200 (vol%) 55.1 55.4 59.7 58.8 54.3 54.0 - - 57.7 57.4 56.4 56.4 

E300 (vol%) 93.9 95.1 84.3 95.2 87.4 95.2 - - 86.2 86.2 89.3 91.5 

Energy (MMBtu/Bbl) 4.954 4.948 4.920 4.905 4.983 4.961 - - 4.991 5.001 4.969 4.967 

CG 

Total ('000 BPD) 2,263 2,184 2,052 2,009 1,568 1,331 829 813 135 137 6,847 6,475 

Ethanol ('000 BPD) 176 221 152 203 40 134 56 82 14 14 436 654 

RVP (psi) 11.6 11.6 11.7 11.5 10.7 10.4 11.3 11.2 10.5 10.6 11.4 11.3 

Sulfur (ppm) 24 24 23 24 24 22 27 28 25 26 24 24 

Octane (R+M/2) 87.7 87.9 88.0 88.0 88.0 88.2 86.9 87.0 89.1 89.1 87.8 87.9 

Aromatics (vol%) 24.2 22.4 24.4 22.5 27.2 22.3 19.4 17.3 28.4 28.5 24.4 21.9 

Benzene (vol%) 0.61 0.53 0.64 0.52 0.59 0.50 1.16 1.04 0.60 0.56 0.68 0.58 

Olefins (vol%) 13.9 14.7 11.1 11.0 14.9 11.9 6.9 7.4 17.1 15.1 12.5 12.0 

Oxygen (wt%) 2.9 3.7 2.7 3.7 0.9 3.7 2.5 3.7 3.6 3.7 2.3 3.7 

E200 (vol%) 55.4 55.6 55.7 57.8 46.5 55.6 59.6 63.2 55.8 55.4 54.0 57.3 

E300 (vol%) 93.4 95.4 84.3 95.4 87.4 95.4 83.5 95.8 86.2 86.2 87.9 95.3 

Energy (MMBtu/Bbl) 4.980 4.947 4.965 4.931 5.069 4.951 5.011 4.962 4.969 4.983 4.999 4.946 

E85 

Total ('000 BPD) - 554 - 202 - 431 - 78 - 137 - 1,402 

Ethanol ('000 BPD) - 475 - 174 - 370 - 67 - 118 - 1,204 

RVP (psi) - 10.1 - 10.8 - 11.1 - 12.0 - 11.7 - 10.8 

Sulfur (ppm) - 10 - 9 - 9 - 9 - 9 - 10 

Octane (R+M/2) - 107.7 - 107.8 - 107.9 - 107.9 - 107.9 - 107.8 

Aromatics (vol%) - 1.1 - 0.6 - 0.5 - 0.0 - 0.3 - 0.7 

Benzene (vol%) - 0.03 - 0.02 - 0.01 - 0.00 - 0.01 - 0.02 

Olefins (vol%) - 2.2 - 2.1 - 2.2 - 1.1 - 1.2 - 2.0 

Oxygen (wt%) - 30.5 - 30.6 - 30.7 - 30.8 - 30.7 - 30.6 

E200 (vol%) - 127.0 - 128.4 - 128.7 - 129.6 - 129.1 - 128.1 

E300 (vol%) - 95.6 - 96.1 - 96.2 - 96.6 - 96.5 - 96.0 

Energy (MMBtu/Bbl) - 3.652 - 3.630 - 3.623 - 3.596 - 3.607 - 3.632 

All Mogas 

Total ('000 BPD) 3,955 4,122 2,443 2,550 2,120 2,212 829 891 1,697 1,751 11,044 11,526 

Ethanol ('000 BPD) 347 836 191 411 95 550 56 149 171 281 860 2,226 

RVP (psi) 11.2 11.1 11.5 11.4 10.5 10.6 11.3 11.3 9.6 9.7 10.9 10.9 

Sulfur (ppm) 24 22 23 22 23 19 27 26 10 11 22 20 

Octane (R+M/2) 87.9 90.7 88.0 89.6 88.0 92.1 86.9 88.8 87.8 89.4 87.8 90.4 

Aromatics (vol%) 22.4 18.7 23.7 20.4 25.2 17.5 19.4 15.8 21.8 20.6 22.9 18.9 

Benzene (vol%) 0.58 0.48 0.63 0.48 0.57 0.40 1.16 0.95 0.52 0.48 0.62 0.50 

Olefins (vol%) 12.9 12.0 10.9 10.2 13.3 9.8 6.9 6.9 6.6 6.1 11.1 9.9 

Oxygen (wt%) 3.2 7.4 2.9 5.9 1.7 9.1 2.5 6.2 3.7 5.9 2.9 7.1 

E200 (vol%) 55.3 65.1 56.4 63.6 48.5 69.5 59.6 69.0 57.5 62.8 54.9 65.6 

E300 (vol%) 93.6 95.3 84.3 95.4 87.4 95.5 83.5 95.9 86.2 87.0 88.4 94.2 

Energy (MMBtu/Bbl) 4.969 4.773 4.958 4.824 5.046 4.695 5.011 4.843 4.989 4.890 4.988 4.792 

Several very important differences are evident in Table 4.4-20. First, the energy content 

of the control case gasoline is much lower than that of the reference case due to the addition of 

low energy content ethanol. Another obvious change is the 4 volume percent decrease in 

aromatics content across the gasoline pool. This change is caused by two factors. One factor is 

the increase in high octane ethanol in E10 which allows for decreased production of high octane 

reformate, which is high in aromatics. Another factor is the blending of E85. The ethanol in 

E85 will dilute the aromatics contained in its gasoline blendstock. Another important change is 

the increase in the gasoline pool octane. Since the reference case gasoline pool was compliant in 

octane, the increased octane of the control case represents octane giveaway. Because of 

620 
ethanol’s very high octane and high concentration in E-85, E85 contains a much higher octane 

level, and when averaged with the rest of the gasoline pool, results in a sizable increase the 

gasoline pool’s average octane level, or octane giveaway. Similarly, the blending of E85 causes 

the decrease in gasoline pool benzene level. 

The increased use of renewable and alternative fuels would require capital investments in 

corn and cellulosic ethanol plants, and renewable diesel fuel plants. In addition to producing the 

fuels, storage and distribution facilities along the whole distribution chain, including at retail, 

will have to be constructed for these new fuels. Conversely, as these renewable and alternative 

fuels are being produced, they supplant gasoline and diesel fuel demand which results in less 

new investments in refineries compared to business-as-usual. In Table 4.4-21, we list the total 

incremental capital investments that we project would be made for this proposed RFS2 

rulemaking incremental to the reference case. These aggregate capital costs are estimated by 

deriving a total capital cost per gallon of product produced for each plant type and multiplying 

that capital cost per gallon factor by the total additional volume of that fuel supplied between the 

reference case and the control case. 

Table 4.4-21. 

Projected Total RFS Program U.S. Capital Investments 

(billion dollars) 

Plant Type Capital Costs 

Corn Ethanol 4.0 

Cellulosic Ethanol 50.1 

Ethanol Distribution 12.4 

Bio/Renew Diesel 

Fuel Production and 

Distribution 

0.25 

Refining -7.9 

Total 58.9 

Table 4.4-21 shows that the total U.S. incremental capital investments attributed to this 

program by 2022 is $58.9 billion. One contributing reason why the capital investments made for 

renewable fuels technologies is so much more than the decrease in refining industry capital 

investments is that a large part of the decrease in petroleum gasoline supply was from reduced 

imports. In addition, renewable fuels technologies are more capital intensive per gallon of fuel 

produced than incremental increases in gasoline and diesel fuel production at refineries. 

To understand entire costs of the program and their impacts on the U.S. economy, and to 

compare those costs to the benefits, we estimated the year-by-year costs from 2009, the first year 

of the program, to 2030. We first estimated renewable fuels volumes for each renewable fuels 

type based on the RFS2 volume standards and based on our projections of which renewable fuels 

would be used to comply with the standard. These volumes represent the increment between the 

RFS2 control case and the reference case. Based on AEO 2008, we also estimated the overall 

gasoline and diesel fuel volumes. Table 4.4-22 below summarizes the projected year-by-year 

incremental renewable fuel, and total gasoline and diesel fuel volumes. 

621 
 

Table 4.4-22. 

Summary of Year-by-Year Volumes (Billion Gallons/year) 

Year 

Gasoline 

Volume 

Corn

Ethanol 

Volume 

 Cellulosic 

Ethanol 

Volume 

Imported 

Ethanol 

Volume 

Diesel 

Fuel 

Volume 

Biodiesel 

Volume 

Renewable 

Diesel Fuel 

Volume 

2009 148.7 0.34 0.00 0.00 54.3 0.08 0.00 

2010 149.8 1.04 0.00 0.00 55.8 0.23 0.01 

2011 150.4 1.60 0.06 0.00 57.3 0.37 0.03 

2012 151.4 2.12 0.25 0.00 58.2 0.62 0.04 

2013 152.4 2.82 0.75 0.00 58.7 0.61 0.06 

2014 153.2 3.39 1.50 0.16 59.3 0.69 0.07 

2015 154.0 3.90 2.75 0.45 60.0 0.66 0.09 

2016 154.7 3.84 4.00 0.80 60.7 0.54 0.10 

2017 155.1 3.70 5.25 1.25 61.3 0.52 0.12 

2018 155.1 3.51 6.75 1.71 61.9 0.51 0.13 

2019 155.2 3.31 8.25 2.15 62.6 0.49 0.15 

2020 154.8 3.17 10.25 2.10 63.4 0.47 0.16 

2021 155.1 2.93 13.25 2.04 64.2 0.45 0.17 

2022 155.4 2.71 15.75 2.50 65.0 0.43 0.19 

2023 154.8 2.71 15.75 2.50 65.9 0.43 0.19 

2024 154.3 2.71 15.75 2.50 66.8 0.43 0.19 

2025 153.4 2.71 15.75 2.50 67.7 0.43 0.19 

2026 153.2 2.71 15.75 2.50 68.8 0.43 0.19 

2027 153.2 2.71 15.75 2.50 69.8 0.43 0.19 

2028 153.3 2.71 15.75 2.50 70.9 0.43 0.19 

2029 153.3 2.71 15.75 2.50 71.9 0.43 0.19 

2030 153.7 2.71 15.75 2.50 73.0 0.43 0.19 

Also for our year-by-year cost analysis, we needed year-by-year estimates of the 

production and distribution cost for each renewable fuel type. The feedstock costs were 

available for the years 2012, 2017 and 2022 from FASOM for corn ethanol and soy oil, used for 

producing biodiesel, with crude oil priced at $53/bbl and $92/bbl. We entered those feedstock 

costs into the respective cost models and interpolated and extrapolated the production costs for 

the years provided to develop production costs for the in-between years. For cellulosic ethanol, 

we assumed the same feedstock costs for all years, but we adjusted the production costs based on 

our adjusted NREL production costs, interpolating between the years for which we have specific 

cost data. Since the costs change so much for cellulosic ethanol, the costs in any one year were 

based on the accumulated costs from the previous years. For example, the production costs in 

the year 2015 are a function of the production costs times the new volume of cellulosic ethanol 

in 2015, plus the production costs times the volume of new cellulosic ethanol in 2014, and so on. 

This avoids underestimating the costs in the later years. Imported ethanol costs by year are from 

Section 4.1 above. Tables 4.4-23 and 4.4-24 summarize the renewable fuels production and 

distribution costs by year along with the projected crude oil, gasoline and diesel fuel wholesale 

costs. Table 4.4-23 represents the projected costs based on crude oil priced at $53 per barrel, and 

Table 4.4-24 presents the projected costs based on crude oil priced at $92 per barrel. 

622 
 

 

Table 4.4-23. 

Renewable Fuel Production and Distribution Costs Used in Year-by-Year Analysis
 

($53/bbl Crude Oil Case) 

Year 

Crude Oil 

Price $/bbl 

Wholesale 

Gasoline 

Price 

Corn 

Ethanol 

Prod Cost 

Cellulosic 

Ethanol 

Prod Cost 

Imported 

Ethanol 

Prod Cost 

Wholesale 

Diesel Fuel 

Price 

Biodiesel 

Prod Cost 

Renewable 

Diesel Fuel 

Prod Cost 

2009 68.3 204 155 - 178 220 270 210 

2010 65.2 195 154 229 177 209 270 210 

2011 62.7 188 153 211 176 200 270 210 

2012 60.1 180 152 193 175 191 270 210 

2013 57.4 172 151 175 174 182 273 212 

2014 54.7 164 150 157 173 172 276 214 

2015 52.0 156 149 139 172 163 279 217 

2016 49.4 148 148 138 172 154 282 219 

2017 49.5 149 147 137 171 154 285 221 

2018 50.2 151 147 136 171 157 282 219 

2019 50.9 153 147 134 171 159 279 217 

2020 51.5 155 147 133 170 161 276 214 

2021 52.1 156 147 132 170 163 273 212 

2022 52.8 159 147 131 170 166 270 210 

2023 53.8 161 147 131 170 169 270 210 

2024 54.7 164 147 131 168 172 270 210 

2025 55.7 167 147 131 168 176 270 210 

2026 56.6 170 147 131 168 179 270 210 

2027 55.8 167 147 131 168 176 270 210 

2028 56.8 170 147 131 168 180 270 210 

2029 57.9 174 147 131 168 184 270 210 

2030 58.7 176 147 131 168 186 270 210 

623 
 

Table 4.4-24. 

Renewable Fuel Production and Distribution Costs Used in Year-by-Year Analysis
 

($92/bbl Crude Oil Case) 

Year 

Crude Oil 

Price $/bbl 

Wholesale 

Gasoline 

Price 

Corn 

Ethanol 

Prod Cost 

Cellulosic 

Ethanol 

Prod Cost 

Imported 

Ethanol 

Prod Cost 

Wholesale 

Diesel Fuel 

Price 

Biodiesel 

Prod Cost 

Renewable 

Diesel Fuel 

Prod Cost 

2009 67.8 203 161 - 180 218 269 208 

2010 69.2 207 160 - 179 223 269 208 

2011 71.0 212 160 216 178 229 269 208 

2012 73.1 218 160 203 177 236 269 208 

2013 75.0 224 160 188 176 243 272 210 

2014 76.8 229 160 175 175 249 274 212 

2015 78.6 234 159 161 174 255 277 214 

2016 80.4 240 159 155 174 261 279 216 

2017 82.8 247 159 152 173 270 282 218 

2018 84.2 251 158 149 173 274 279 216 

2019 86.3 257 157 148 173 282 277 214 

2020 88.3 263 156 146 172 289 275 212 

2021 90.7 270 155 144 172 297 272 210 

2022 91.8 273 154 143 172 301 270 209 

2023 89.9 268 154 143 172 294 270 209 

2024 91.2 272 154 143 170 299 270 209 

2025 90.9 271 154 143 170 298 270 209 

2026 91.8 273 154 143 170 301 270 209 

2027 93.1 277 154 143 170 306 270 209 

2028 94.4 281 154 143 170 310 270 209 

2029 95.4 284 154 143 170 313 270 209 

2030 96.4 287 154 143 170 317 270 209 

Based on the volumes and renewable fuels production and distribution costs, we 

estimated the program costs in years other than 2022 and summarized them in Tables 4.4-25 and 

4.4-26. We started with the year 2022 costs as our basis. We then adjusted those costs using the 

volume and price relationship between ethanol and gasoline to estimate the costs in other years. 

We also calculated the total dollar amount of the subsidies based on the volumes of renewable 

fuels and the subsidy that applies to each renewable fuel, and what the subsidized cost would be 

when the subsidies are applied. 

624 
Table 4.4-25. 

Year-by-Year Annual Average and Per-Gallon Costs for Gasoline 

$53/bbl Crude Oil Price $92/bbl Crude Oil Price 

Year 

Total 

Annual 

Cost 

$MM/yr 

Gasoline 

Cost 

c/gal 

Subsidy 

$MM/yr 

Subsidized 

Gasoline 

Cost 

c/gal 

Total 

Annual 

Cost 

$MM/yr 

Gasoline 

Cost 

c/gal 

Subsidy 

$MM/yr 

Subsidized 

Gasoline 

Cost 

c/gal 

2009 -52 -0.03 153 -0.14 172 0.12 153 0.01 

2010 37 0.03 468 -0.29 441 0.29 468 -0.02 

2011 513 0.34 783 -0.18 540 0.36 783 -0.16 

2012 1,363 0.90 1,208 0.10 536 0.35 1,208 -0.44 

2013 2,244 1.47 2,028 0.14 705 0.46 2,028 -0.87 

2014 3,738 2.44 3,116 0.41 1,451 0.95 3,116 -1.09 

2015 5,761 3.74 4,733 0.67 2,268 1.47 4,733 -1.60 

2016 7,508 4.85 6,073 0.93 2,700 1.74 6,073 -2.18 

2017 8,910 5.75 7,326 1.02 2,916 1.88 7,326 -2.84 

2018 10,384 6.70 8,794 1.03 3,268 2.11 8,794 -3.56 

2019 11,747 7.57 10,248 0.97 3,319 2.14 10,248 -4.46 

2020 13,031 8.42 12,245 0.51 3,154 2.04 12,245 -5.87 

2021 14,998 9.67 15,207 -0.14 2,867 1.85 15,207 -7.96 

2022 16,957 10.91 17,708 -0.48 2,962 1.91 17,708 -9.49 

2023 16,584 10.71 16,488 0.06 3,517 2.27 16,488 -8.38 

2024 16,259 10.54 16,488 -0.15 2,979 1.93 16,488 -8.76 

2025 15,867 10.34 16,488 -0.40 3,079 2.01 16,488 -8.74 

2026 15,501 10.12 16,488 -0.64 2,732 1.78 16,488 -8.98 

2027 15,806 10.31 16,488 -0.44 2,231 1.46 16,488 -9.30 

2028 15,427 10.07 16,488 -0.69 1,771 1.16 16,488 -9.60 

2029 15,005 9.79 16,488 -0.97 1,372 0.89 16,488 -9.86 

2030 14,725 9.58 16,488 -1.15 977 0.64 16,488 -10.09 

625 
 

 

Table 4.4-26. 

Year-by-Year Annual Average and Per-Gallon Costs for Diesel Fuel 

$53/bbl Crude Oil Price $92/bbl Crude Oil Price 

Year 

Total 

Annual 

Cost 

$MM/yr 

Diesel Fuel 

Cost 

c/gal 

Subsidy 

$MM/yr 

Subsidized 

Diesel Fuel 

Cost 

c/gal 

Total 

Annual 

Cost 

$MM/yr 

Diesel Fuel 

Cost 

c/gal 

Subsidy 

$MM/yr 

Subsidized 

Diesel Fuel 

Cost 

c/gal 

2009 83 0.15 83 0.00 84 0.15 83 0.00 

2010 260 0.47 235 0.04 226 0.41 235 -0.02 

2011 460 0.80 387 0.13 350 0.61 387 -0.07 

2012 814 1.40 640 0.30 533 0.92 640 -0.18 

2013 890 1.52 639 0.43 505 0.86 639 -0.23 

2014 1,103 1.86 729 0.63 549 0.93 729 -0.30 

2015 1,155 1.93 707 0.75 503 0.84 707 -0.34 

2016 1,051 1.73 596 0.75 396 0.65 596 -0.33 

2017 1,048 1.71 583 0.76 348 0.57 583 -0.38 

2018 1,001 1.62 571 0.69 296 0.48 571 -0.44 

2019 952 1.52 558 0.63 229 0.37 558 -0.53 

2020 906 1.43 546 0.57 164 0.26 546 -0.60 

2021 864 1.35 533 0.51 93 0.14 533 -0.69 

2022 817 1.26 521 0.46 49 0.08 521 -0.73 

2023 798 1.21 521 0.42 87 0.13 521 -0.66 

2024 781 1.17 521 0.39 61 0.09 521 -0.69 

2025 761 1.12 521 0.35 67 0.10 521 -0.67 

2026 742 1.08 521 0.32 49 0.07 521 -0.69 

2027 758 1.09 521 0.34 23 0.03 521 -0.71 

2028 739 1.04 521 0.31 0 0.00 521 -0.74 

2029 717 1.00 521 0.27 -21 -0.03 521 -0.75 

2030 703 0.96 521 0.25 -41 -0.06 521 -0.77 

4.4.2.2 Sensitivity Cases 

We also ran two sensitivity cases to the 2022 control case. The two sensitivity cases 

were: 1) ethanol use is increased beyond the reference case until the gasoline pool is saturated 

with ethanol at 10 percent, and 2) ethanol, biodiesel and renewable diesel fuel are used at the 

same volumes as the primary year 2022 control case, however, the ethanol is primarily blended 

with gasoline at 20 percent which dramatically reduces the volume of E85 required. We ran 

sensitivity cases to isolate aspects of the primary control case. We ran the E10 case to isolate the 

effects of E10 blending from that of E85 on gasoline fuel properties and costs. We ran the midethanol blend sensitivity case to assess what might happen to gasoline fuel properties and costs if 

a waiver were to be granted for mid-ethanol blends as some have suggested. 

626 
 

 

 

 

4.4.2.2.1 E10 Sensitivity Case 

Tables 4.4-27 and 4.4-28 summarize the costs for the E10 sensitivity case ignoring 

federal ethanol tax subsidies and at two different crude oil prices. The costs are reported by 

different cost component as well as aggregated total and the per-gallon costs.JJJJJJJJJJ This 

estimate of costs reflects the changes in gasoline that are occurring with the expanded use of 

ethanol. The operating costs include the labor, utility and other operating costs and are a direct 

output from the refinery model. These costs are adjusted to reflect ethanol’s production cost plus 

distribution costs instead of the ethanol prices used in the refinery cost model. The fixed costs 

were assumed to be 3 percent of the capital costs. The costs associated with lower energy 

density gasoline are accounted for using the fractional change in energy density shown in Table 

4.4-28 multiplied times the wholesale price of gasoline. By ignoring the federal ethanol tax 

subsidies in the table, we avoid the transfer payments caused by these subsidies that would hide a 

portion of the program’s costs. 

Table 4.4-27. 

Summary of E10 Case Costs (without Ethanol Tax Subsidies) 

(million dollars/year and c/gal, except as noted; 2004 dollars, 

7% ROI before taxes, $53/bbl crude oil price)

 Cost to Gasoline 

Refinery Capital Costs ($Billion) -1.23 

Amortized Refinery Capital Costs ($MM/yr) -131 

Fixed Operating Cost ($MM/yr) -36 

Variable Operating Cost ($MM/yr) 940 

Lower Energy Density ($MM/yr) 1,930 

Total Cost ($MM/yr) 2,704 

Refinery Capital Costs (c/gal) -0.08 

Fixed Operating Cost (c/gal) -0.02 

Variable Operating Cost (c/gal) 0.76 

Lower Energy Density (c/gal) 1.13 

Total Cost Excluding Subsidies (c/gal) 1.79 

JJJJJJJJJJ EPA typically assesses social benefits and costs of a rulemaking. However, this analysis is more limited in 

its scope by sometimes relying on the marginal production price which includes some market distortions , while 

other times relying on the average production cost for ethanol. 

627 
 

 

Table 4.4-28. 

Summary of E10 Case Costs (without Ethanol Tax Subsidies) 

(million dollars/year and c/gal, except as noted; 2004 dollars, 

7% ROI before taxes, $92/bbl crude oil price) 

Cost to Gasoline 

Amortized Refinery Capital Costs ($MM/yr) -131 

Fixed Operating Cost ($MM/yr) -36 

Variable Operating Cost ($MM/yr) -1,348 

Lower Energy Density ($MM/yr) 2,690 

Total Cost ($MM/yr) 1,180 

Refinery Capital Costs (c/gal) -0.08 

Fixed Operating Cost (c/gal) -0.02 

Variable Operating Cost (c/gal) -0.69 

Lower Energy Density (c/gal) 1.57 

Total Cost Excluding Subsidies (c/gal) 0.78 

Our analysis shows that when considering all the costs associated with these fuel changes 

resulting from the expanded use of ethanol, that increased ethanol use up to 100 percent E10 will 

cost the U.S. $2.7 billion per year in the year 2022 when crude oil is priced at $53 per barrel. 

Expressed as per-gallon costs, these fuel changes would cost the U.S. 1.79 cents per gallon of 

gasoline. At $92 per barrel crude oil, the addition of the ethanol up to 100 percent E10 is 

estimated to cost $1,180 million per year in 2022, and cost 0.78 cents per gallon. These cost 

impacts are for far lower than for the control case described above due to the far lower volumes 

of ethanol, but also the lack of blending of E85. 

Tables 4.4-29 and 4.4-30 expresses the total and per-gallon gasoline costs for the RFS 

case with the federal ethanol, biodiesel and renewable diesel subsidies included with crude oil 

priced at $53/bbl and $92/bbl, respectively. The federal tax subsidy is 45 cents per gallon for 

each gallon of new corn-based ethanol blended into gasoline and 101 cents per gallon for each 

gallon of cellulosic ethanol. The biodiesel subsidy is 100 cents per gallon, and the renewable 

diesel fuel subsidy is 50 cents per gallon. The cost adjustment is estimated by multiplying the 

subsidy times the volume of new ethanol, biodiesel and renewable diesel estimated to be used. 

Table 4.4-29. 

Estimated E10 Case Cost (Reflecting Ethanol Tax Subsidies) 

(million dollars/year and cents/gallon; 2004 dollars, 

7% ROI before taxes, $53/bbl crude oil price)

 Cost to Gasoline 

Total Cost ($MM/yr) 2,704 

Federal Subsidy ($MM/yr) -3,491 

Revised Total Cost ($MM/yr) -787 

Per-Gallon Cost Excluding Subsidies (c/gal) 1.79 

Federal Subsidy (c/gal) -2.32 

Total Cost Including Subsidies (c/gal) -0.53 

628 
 

 

Table 4.4-30. 

Estimated E10 Case Cost (Reflecting Ethanol Tax Subsidies) 

(million dollars/year and cents/gallon; 2004 dollars, 

7% ROI before taxes, $92/bbl crude oil price) 

Cost to Gasoline 

Total Cost ($MM/yr) 1,179 

Federal Subsidy ($MM/yr) -3,491 

Revised Total Cost ($MM/yr) -2,312 

Per-Gallon Cost Excluding Subsidies (c/gal) 0.78 

Federal Subsidy (c/gal) -2.32 

Total Cost Including Subsidies (c/gal) -1.54 

The cost including subsidies may better represent gasoline and diesel fuel’s apparent cost 

as reflected to the fuel industry as a whole and to consumers “at the pump” because the federal 

subsidies tends to transfer a portion of the actual costs. Our analysis estimates that when the oil 

price is $53/bbl, the fuel industry and consumers will see a 0.53 cent per gallon decrease in the 

apparent cost of producing gasoline. At the higher oil price of $92/bbl, the apparent cost of 

producing gasoline is estimated to decrease by 1.54 cents per gallon. 

Table 4.4-31 summarizes the volumetric inputs to refineries in each PADD for this E10 

control case. 

629 
 

Table 4.4-31. 

Summary of the Total and Incremental Volumetric Refinery Inputs by PADD 

(thousand barrels/day) PADD 1 PADD 2 PADD 3 PADD 4/5 CA 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

PADD Crude 1,525 0 3,444 -118 9,037 -63 1,750 3 2,138 1 

GTL Naphtha 0 0 0 0 0 0 0 0 0 0 

GTL Diesel 0 0 0 0 0 0 0 0 0 0 

VGO HS 0 0 0 0 613 -8 0 0 28 -1 

VGO LS 0 0 1 0 0 0 0 0 0 0 

HS AR (A960) 0 0 0 0 0 0 0 0 0 0 

LS AR (Alg) 205 4 0 0 137 8 0 0 0 0 

Normal Butane 25 -1 45 -10 112 0 36 -1 40 0 

Isobutane 9 0 23 2 62 -4 13 -1 23 0 

MTBE 0 0 0 0 0 0 0 0 0 0 

Ethanol - E10 404 58 250 59 217 121 87 31 172 0 

Ethanol - E20 0 0 0 0 0 0 0 0 0 0 

Ethanol - E85 0 0 0 0 0 0 0 0 0 0 

Reformer Feed 0 0 0 0 0 0 0 0 0 0 

Methanol 0 0 0 0 0 0 0 0 0 0 

Natural Gas (FOE) 80 1 142 2 576 6 122 1 172 0 

Hydrogen (MSCF) 0 0 0 0 0 0 0 0 0 0 

Pentanes Plus 0 0 32 0 52 0 19 0 0 0 

Import CBOB 10% 421 421 0 0 0 0 0 0 0 0 

Import CBOB 20% 0 0 0 0 0 0 0 0 0 0 

Import RBOB 10% 187 -13 0 0 0 0 0 0 0 0 

Import RBOB 20% 0 0 0 0 0 0 0 0 0 0 

Import Alkylate 31 15 0 0 0 0 0 0 0 0 

Import Raffinate 33 -15 0 0 0 0 0 0 46 0 

Import Reformate 0 0 0 0 0 0 0 0 0 0 

Import FCC Naphtha 0 0 0 0 0 0 0 0 0 0 

Import Lt Naphtha 0 0 0 0 21 -9 0 0 1 0 

Import Hvy Naph 0 0 0 0 42 0 0 0 0 0 

Transfer Lt Naphtha 0 0 0 0 0 0 0 0 22 -2 

Transfer Reformate 0 0 0 -5 0 0 0 0 0 0 

Transfer Alkylate 60 0 10 7 0 0 0 0 60 0 

Transfer FCC Naphtha 0 0 0 0 0 0 0 0 0 0 

Transfer Raffinate 0 0 0 -2 0 0 0 0 60 0 

Transfer RBOB 10% 734 38 79 29 0 0 0 0 0 0 

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0 

Transfer CBOB 10% 1,300 2 421 -29 0 0 14 14 0 0 

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0 

Isooctane 0 0 0 0 0 0 0 0 29 1 

Isooctene 10 -1 2 0 0 0 0 0 0 0 

Table 4.4-32 below summarizes the refinery output volumes and changes in refinery 

output volumes relative to the reference case by PADD. 

630 
Table 4.4-32. 

Summary of Total and Incremental Refinery Outputs by PADD 

(thousand barrels/day) PADD 1 PADD 2 PADD 3 PADD 4/5 CA 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Propane 35 1 59 -5 139 -6 27 -1 59 1 

Propylene 19 0 43 0 245 0 2 0 12 0 

Normal Butane 0 0 3 -1 47 2 0 0 0 0 

Isobutane 0 0 0 0 0 0 0 0 10 1 

PC Naphtha 16 0 40 0 433 0 0 0 0 0 

PC Gasoil 0 0 527 -29 158 0 0 0 0 0 

CG Reg 0 -73 0 -552 0 -1,176 0 -246 0 0 

CG Prem 0 0 0 0 0 -2 0 -33 0 0 

CG E10 Reg 1,935 455 1,745 573 1,334 1,192 723 273 114 2 

CG E10 Prem 339 80 332 4 254 3 138 38 22 0 

RFG E10 Reg 1,455 34 332 4 469 6 0 0 1,312 0 

RFG E10 Prem 273 2 63 1 89 1 0 0 250 0 

CG E20 Reg 0 0 0 0 0 0 0 0 0 0 

RFG E20 Reg 0 0 0 0 0 0 0 0 0 0 

E85 to CG 0 0 0 0 0 0 0 0 0 0 

E85 to RFG 0 0 0 0 0 0 0 0 0 0 

Transfer RBOB 10% 0 0 0 0 813 67 0 0 0 0 

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0 

Transfer CBOB 10% 0 0 0 0 1,735 -13 0 0 0 0 

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0 

Jet/Kero A (450ppm) 27 0 115 0 1,363 0 380 0 300 0 

X-Fer Diesel Rundown 0 0 0 0 0 0 0 0 0 0 

HSD Gr 76 (0.2%) 0 0 0 0 0 0 0 0 0 0 

LSD Gr 74 (.05%) 0 0 0 0 0 0 0 0 0 0 

ULSD (15 ppm) 556 5 627 -50 2,210 -14 524 12 0 0 

CARB Diesel 0 0 0 0 0 0 0 0 354 -4 

X-Fer C5's to Storage 0 0 0 0 0 0 0 0 0 0 

1% Residual Fuel 0 0 0 0 0 0 0 0 0 0 

Residual Fuel 70 0 57 0 269 -3 149 4 74 2 

Slurry 31 -1 87 -3 158 0 1 1 30 0 

Asphalt & Wax 143 0 210 0 158 0 5 0 44 0 

Gasoil 0 0 9 0 0 0 0 0 10 0 

Lubes 19 0 17 0 158 0 0 0 20 0 

Benzene 11 0 11 0 51 0 0 0 0 0 

Toluene 0 0 0 0 35 0 0 0 0 0 

Xylenes 0 0 0 0 8 0 0 0 0 0 

Cumene 0 0 0 0 0 0 0 0 0 0 

Cyclohexane 0 0 0 0 0 0 0 0 0 0 

Transfer Raffinate 0 0 0 0 60 -2 0 0 0 0 

Transfer Alkylate 0 0 0 0 130 7 0 0 0 0 

Transfer Reformate 0 0 0 0 0 -5 0 0 0 0 

Transfer FCC naphtha 0 0 0 0 0 0 0 0 0 0 

Transfer Lt Naphtha 0 0 0 0 0 0 0 0 22 -2 

Transfer Blendstock 0 0 0 0 0 0 0 0 0 0 

Sulfur (STons) 1 0 4 0 17 0 3 0 4 0 

Coke (STon) 2 0 13 -1 68 -1 7 0 20 0 

Table 4.4-34 summarizes the change in refinery unit throughputs by PADD comparing 

the E10 case to the reference case. 

631 
 

Table 4.4-34. 

Change in Refinery Unit Capacities by PADD relative to the Reference Case 

(thousand barrels/day) 

Refinery Unit PADD 1 PADD 2 PADD 3 PADD 4/5 CA U.S. 

Crude Tower 0 -202 -59 0 0 -261 

Vacuum Tower 0 -90 -29 4 0 -115 

Sats Gas Plant 0 0 -10 2 0 -8 

Unsats Gas Plant 0 -1 -6 0 0 -6 

FCC DeC5 Tower 0 0 0 0 0 0 

FCC 0 0 -18 0 -4 -22 

FCC Splitter 1 -6 -10 0 -1 -16 

Hydrocracker 0 0 0 3 0 3 

H-Oil Unit 0 0 0 0 0 0 

Delayed Coker 0 0 -11 0 0 -11 

Visbreaker 0 0 0 0 0 0 

Thermal Naphtha Splitter 0 -4 -1 0 0 -5 

CRU Reformer 0 0 0 0 0 0 

SRU Reformer 0 0 0 0 3 3 

BTX Reformer 0 0 0 0 0 0 

C4 Isomerization 0 0 0 0 0 0 

C5/C6 Isomerization 4 0 0 0 0 4 

HF Alkylation 0 0 0 0 0 0 

H2SO4 Alkylation 0 0 -7 2 -5 -9 

Dimersol 0 0 0 0 0 0 

Cat Poly 0 0 0 0 0 0 

Isooctane 0 0 0 0 0 0 

DHT - Total 7 0 -12 11 0 6 

DHT 2nd RCT - Total 6 -25 -11 9 0 -21 

DHT Arom Saturation 0 0 0 0 0 0 

NHT - Total Fd 1 0 0 -1 0 0 

CGH - Generic -4 16 12 -15 0 8 

CGH - Olefin Sat'n 0 0 0 0 0 0 

FCCU Fd HDT 7 0 0 -29 0 -22 

LSR Splitter 0 17 0 0 0 17 

LSR Bz Saturator 0 0 0 0 0 0 

Reformate Saturator -2 0 0 0 0 -2 

Reformate Splitter -6 0 -1 0 0 -7 

SDA 0 0 0 0 0 0 

MTBE 0 0 0 0 0 0 

TAME 0 0 0 0 0 0 

Hydrogen Plant - Total MSCF 14 -16 107 17 -3 119 

Lube Unit 0 0 0 0 0 0 

Sulfur Plant 0 0 -98 -41 -5 -143 

Merox Jet 0 0 0 0 0 0 

Merox Diesel 0 0 0 0 0 0 

BTX Reformer - Tower feed 0 0 0 0 0 0 

BTX Reformer - Extract feed 0 0 0 0 0 0 

632 
Table 4.4-35. 

Change in Refinery Unit Investments by PADD (million dollars/yr) 

Refinery Unit PADD 1 PADD 2 PADD 3 PADD 4/5 CA U.S. 

Crude Tower 0 -486 -62 0 0 -547 

Vacuum Tower 0 -219 -34 83 0 -170 

Sats Gas Plant 0 0 -38 5 0 -34 

Unsats Gas Plant 2 0 -52 0 0 -49 

FCC DeC5 Tower 0 0 0 0 0 0 

FCC 0 0 -225 0 -26 -251 

FCC Splitter 0 -6 -3 0 0 -10 

Hydrocracker 0 0 0 49 0 49 

H-Oil Unit 0 0 0 0 0 0 

Delayed Coker 0 0 -121 0 0 -121 

Visbreaker 0 0 0 0 0 0 

Thermal Naphtha Splitter 0 -4 0 0 0 -5 

CRU Reformer 0 0 0 0 0 0 

SRU Reformer 0 0 0 0 71 71 

BTX Reformer 0 0 0 0 0 0 

C4 Isomerization 0 0 0 0 0 0 

C5/C6 Isomerization 26 0 0 0 0 26 

HF Alkylation 0 0 0 0 0 0 

H2SO4 Alkylation 5 0 -57 20 -104 -136 

Dimersol 0 0 0 0 0 0 

Cat Poly 0 0 0 0 0 0 

Isooctane 0 0 0 0 0 0 

DHT - Total 45 0 -125 64 0 -15 

DHT 2nd RCT - Total 28 -167 -34 40 0 -133 

DHT Arom Saturation 0 0 0 0 0 0 

NHT - Total Fd 4 0 0 -4 0 0 

CGH - Generic -22 101 28 -58 0 49 

CGH - Olefin Sat'n 0 0 0 0 0 0 

FCCU Fd HDT 51 0 0 -314 0 -264 

LSR Splitter 0 7 0 0 0 7 

LSR Bz Saturator 0 0 0 0 0 0 

Reformate Saturator -9 0 -1 0 0 -10 

Reformate Splitter -15 0 -1 0 0 -15 

SDA 0 0 0 0 0 0 

MTBE 0 0 0 0 0 0 

TAME 0 0 0 0 0 0 

Hydrogen Plant - Total MSCF 38 -37 284 87 -40 332 

Lube Unit 0 0 0 0 0 0 

Sulfur Plant 0 0 0 0 0 0 

Merox Jet 0 0 0 0 0 0 

Merox Diesel 0 0 0 0 0 0 

BTX Reformer - Tower feed 0 0 0 0 0 0 

BTX Reformer - Extract feed 0 0 0 0 0 0 

Total 153 -811 -440 -29 0 -1,226 

These changes in refinery unit throughputs are associated with changes in capital 

investments. Table 4.4-35 summarizes the projected change in capital investments between the 

reference case and the EIA control case. This Table shows that incremental to the reference 

case, refiners are expected to reduce their capital investments by $1.2 billion compared to 

business as usual. Most of the reduction occurs in PADDs 2 and 3. This capital cost decrease is 

countered by the capital costs incurred to build new ethanol plants and put into place the 

distribution system that the new ethanol requires. 

633 
 

Table 4.4-36. 

Gasoline Volume, Quality and Energy Density by Gasoline Type at the PADD Terminal
 PADD 1 PADD 2 PADD 3 PADD 4/5 CA US 

RFG Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control 

Total ('000 BPD) 1,692 1,728 391 396 551 558 - - 1,562 1,562 4,197 4,244 

Ethanol ('000 BPD) 171 175 39 40 56 56 - - 158 158 424 429 

RVP (psi) 10.7 10.8 10.4 10.6 9.7 9.8 - - 9.5 9.5 10.1 10.2 

Sulfur (ppm) 23 24 23 24 20 22 - - 9 9 17 18 

Octane (R+M/2) 88.1 88.1 88.0 88.0 88.0 88.0 - - 87.6 87.6 87.9 87.9 

Aromatics (vol%) 19.9 19.9 20.0 20.0 19.5 19.5 - - 21.3 21.3 20.4 20.4 

Benzene (vol%) 0.55 0.56 0.58 0.58 0.51 0.51 - - 0.51 0.51 0.53 0.54 

Olefins (vol%) 11.7 12.2 10.3 10.6 8.7 9.3 - - 5.7 5.7 8.9 9.3 

Oxygen (wt%) 3.7 3.7 3.7 3.7 3.7 3.7 - - 3.7 3.7 3.7 3.7 

E200 (vol%) 55.1 55.3 59.7 57.8 54.3 53.9 - - 57.7 57.6 56.4 56.2 

E300 (vol%) 93.9 93.9 84.3 82.9 87.4 85.8 - - 86.2 86.2 89.3 89.0 

Energy (MMBtu/Bbl) 4.954 4.950 4.920 4.939 4.983 4.976 - - 4.991 4.992 4.969 4.968 

CG 

Total ('000 BPD) 2,263 2,274 2,052 2,078 1,568 1,588 829 1,588 135 136 6,847 6,937 

Ethanol ('000 BPD) 176 230 152 210 40 160 56 160 14 14 436 701 

RVP (psi) 11.6 11.8 11.7 11.5 10.7 10.7 11.3 10.7 10.5 10.6 11.4 11.4 

Sulfur (ppm) 24 24 23 24 24 22 27 22 25 24 24 24 

Octane (R+M/2) 87.7 88.1 88.0 88.0 88.0 88.0 86.9 88.0 89.1 89.2 87.8 87.9 

Aromatics (vol%) 24.2 22.3 24.4 22.5 27.2 22.2 19.4 22.2 28.4 29.0 24.4 21.7 

Benzene (vol%) 0.61 0.51 0.64 0.53 0.59 0.50 1.16 0.50 0.60 0.60 0.68 0.58 

Olefins (vol%) 13.9 14.5 11.1 10.7 14.9 12.1 6.9 12.1 17.1 16.6 12.5 11.9 

Oxygen (wt%) 2.9 3.7 2.7 3.7 0.9 3.7 2.5 3.7 3.6 3.6 2.3 3.7 

E200 (vol%) 55.4 55.4 55.7 58.9 46.5 55.0 59.6 55.0 55.8 55.2 54.0 57.3 

E300 (vol%) 93.4 93.9 84.3 82.9 87.4 85.8 83.5 85.8 86.2 86.2 87.9 88.1 

Energy (MMBtu/Bbl) 4.980 4.931 4.965 4.923 5.069 4.971 5.011 4.971 4.969 4.973 4.999 4.942 

All Mogas 

Total ('000 BPD) 3,955 4,003 2,443 2,473 2,120 2,146 829 861 1,697 1,698 11,044 11,181 

Ethanol ('000 BPD) 347 404 191 250 95 217 56 87 171 172 860 1,129 

RVP (psi) 11.2 11.3 11.5 11.4 10.5 10.4 11.3 11.4 9.6 9.6 10.9 10.9 

Sulfur (ppm) 24 24 23 24 23 22 27 28 10 10 22 22 

Octane (R+M/2) 87.9 88.1 88.0 88.0 88.0 88.0 86.9 86.9 87.8 87.8 87.8 87.9 

Aromatics (vol%) 22.4 21.3 23.7 22.1 25.2 21.5 19.4 16.3 21.8 21.9 22.9 21.2 

Benzene (vol%) 0.58 0.53 0.63 0.54 0.57 0.50 1.16 1.04 0.52 0.52 0.62 0.57 

Olefins (vol%) 12.9 13.5 10.9 10.6 13.3 11.4 6.9 6.7 6.6 6.6 11.1 10.9 

Oxygen (wt%) 3.2 3.7 2.9 3.7 1.7 3.7 2.5 3.8 3.7 3.7 2.9 3.7 

E200 (vol%) 55.3 55.3 56.4 58.7 48.5 54.7 59.6 63.3 57.5 57.4 54.9 56.9 

E300 (vol%) 93.6 93.9 84.3 82.9 87.4 85.8 83.5 90.2 86.2 86.2 88.4 88.5 

Energy (MMBtu/Bbl) 4.969 4.939 4.958 4.926 5.046 4.972 5.011 4.957 4.989 4.990 4.988 4.952 

4.4.2.2.2 Mid-Ethanol Blend Sensitivity Case 

For this case, the year 2022 control case volumes were run assuming that ethanol was 

mostly blended as E20. About 10 percent of the gasoline pool was required to remain E10 to 

provide gasoline that would be compatible with nonroad gasoline powered engines and legacy 

cars. Most of the remainder of the gasoline was blended with ethanol at 20 percent by volume 

until the gasoline pool was saturated, allowing for a small amount of E85 to achieve the 

necessary volume of ethanol to comply with the RFS2 standard. 

Tables 4.4-37 and 4.4-38 summarize the costs for the RFS case excluding federal ethanol, 

biodiesel and renewable fuels consumption subsidies with crude oil priced at $53/bbl and 

$92/bbl, respectively. The costs are reported by different cost component as well as aggregated 

total and the per-gallon costs.KKKKKKKKKK The operating costs include the labor, utility and other 

634 
 

 

operating costs and are a direct output from the refinery model. These costs are adjusted to 

reflect ethanol’s production cost plus distribution costs instead of the ethanol prices used in the 

refinery cost model. The fixed costs are 3 percent of the capital costs. The costs associated with 

lower energy density gasoline are accounted for using the fractional change in energy density 

shown in Table 4.4-37, multiplied times the wholesale price of gasoline. 

Table 4.4-37. 

Summary of Mid-Ethanol Blend Case Costs (without Tax Subsidies) 

(million dollars/year and c/gal, except as noted; 2004 dollars, 7% ROI before taxes, $53/bbl crude oil price) 

 Cost to Gasoline Cost to Diesel Fuel 

Refinery Capital Costs ($Billion) -7.30 -

Amortized Refinery Capital Costs ($MM/yr) -780 -

Fixed Operating Cost ($MM/yr) -215 -

Variable Operating Cost ($MM/yr) 5,404 590 

Lower Energy Density Gasoline ($MM/yr) 9,630 187 

Total Cost ($MM/yr) 14,043 777 

Refinery Capital Costs (c/gal) -0.44 -

Fixed Operating Cost (c/gal) -0.12 -

Vaiable Operating Cost (c/gal) 4.15 0.66 

Lower Energy Density Gasoline (c/gal) 5.45 0.54 

Total Cost Excluding Subsidies (c/gal) 9.04 1.20 

Table 4.4-38. 

Summary of Mid-Ethanol Blend Case Costs (without Tax Subsidies) 

(million dollars/year and c/gal, except as noted; 2004 dollars, 7% ROI before taxes, $92/bbl crude oil price) 

Cost to Gasoline Cost to Diesel Fuel 

Amortized Refinery Capital Costs ($MM/yr) -780 -

Fixed Operating Cost ($MM/yr) -215 -

Variable Operating Cost ($MM/yr) -16,662 -419 

Lower Energy Density Gasoline ($MM/yr) 16,390 373 

Total Cost ($MM/yr) -1,267 -46 

Refinery Capital Costs (c/gal) -0.44 -

Fixed Operating Cost (c/gal) -0.12 -

Variable Operating Cost (c/gal) -9.53 -1.15 

Lower Energy Density Gasoline (c/gal) 9.28 1.08 

Total Cost Excluding Subsidies (c/gal) -0.82 -0.07 

Our analysis shows that when considering all the costs associated with these fuel changes 

resulting from the expanded use of ethanol that these various possible gasoline use scenarios will 

cost the U.S. $14.0 billion per year in the year 2022 when crude oil is priced at $53 per barrel. 

Expressed as per-gallon costs, these fuel changes would cost the U.S. 9.04 cents per gallon of 

gasoline. The addition of biodiesel and renewable diesel fuel is estimated to cost about $780 

million per year in the year 2022, or cost 1.20 cents per gallon. 

At $92 per barrel crude oil, the addition of the ethanol is estimated to decrease the cost of 

KKKKKKKKKK EPA 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. 

635 
 

 

 

 

producing gasoline in 2022 by 1.3 billion per year, or 0.82 cents per gallon. The addition of 

biodiesel and renewable diesel fuel is estimated to reduce the cost of diesel fuel by 46 million 

dollars in 2022, and reduce the per-gallon cost of diesel fuel by 0.07 cents per gallon. 

Tables 4.4-39 and 4.4-40 expresses the total and per-gallon gasoline costs for the RFS 

case with the federal ethanol, biodiesel and renewable diesel subsidies included with crude oil 

priced at $53/bbl and $92/bbl, respectively. The federal tax subsidy is 45 cents per gallon for 

each gallon of new corn-based ethanol blended into gasoline and 101 cents per gallon for each 

gallon of cellulosic ethanol. The biodiesel subsidy is 100 cents per gallon, and the renewable 

diesel fuel subsidy is 50 cents per gallon. The cost adjustment is estimated by multiplying the 

subsidy times the volume of new ethanol, biodiesel and renewable diesel estimated to be used. 

Table 4.4-39. 

Estimated Mid-Ethanol Blend Case Costs (Reflecting Tax Subsidies) 

(million dollars/year and cents/gallon; 2004 dollars, 7% ROI before taxes, $52/bbl crude oil price) 

Gasoline Costs Diesel Fuel Costs 

Total Cost ($MM/yr) 11,561 777 

Federal Subsidy ($MM/yr) -17,699 -525 

Revised Total Cost ($MM/yr) -6,139 252 

Per-Gallon Cost Excluding Subsidies (c/gal) 7.44 1.20 

Federal Subsidy (c/gal) -11.39 -0.81 

Total Cost Including Subsidies (c/gal) -3.95 0.39 

Table 4.4-40. 

Estimated Mid-Ethanol Blend Case Costs (Reflecting Tax Subsidies) 

(million dollars/year and cents/gallon; 2004 dollars, 7% ROI before taxes, $93/bbl crude oil price) 

Gasoline Costs Diesel Fuel Costs 

Total Cost ($MM/yr) -3,749 -46 

Federal Subsidy ($MM/yr) -17,699 -535 

Revised Total Cost ($MM/yr) -21,449 -571 

Per-Gallon Cost Excluding Subsidies (c/gal) -2.41 -0.07 

Federal Subsidy (c/gal) -11.39 -0.81 

Total Cost Including Subsidies (c/gal) -13.80 -0.88 

The cost including subsidies may better represent gasoline and diesel fuel’s apparent cost 

as reflected to the fuel industry as a whole and to consumers “at the pump” because the federal 

subsidies tends to transfer a portion of the actual costs. Our analysis estimates that when the oil 

price is $53/bbl, the fuel industry and consumers will see a 3.95 cent per gallon decrease in the 

apparent cost of producing gasoline, and a 0.39 increase in the apparent cost of producing diesel 

fuel. At the higher oil price of $93/bbl, the apparent cost of producing gasoline is estimated to 

decrease by 13.8 cents per gallon, and the apparent cost of producing diesel fuel is expected to 

decrease by 0.88 cents per gallon. 

Table 4.4-41 summarizes the volumetric inputs to refineries in each PADD for this 

control case. Because of the increased use of biofuels, petroleum inputs would be expected to 

decrease, and this is confirmed. 

636 
 

 

 

Table 4.4-41. 

Summary of the Total and Incremental Volumetric Refinery Inputs by PADD 

(thousand barrels/day) PADD 1 PADD 2 PADD 3 PADD 4/5 CA 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

PADD Crude 1,525 0 3,316 -247 8,633 -467 1,703 -44 2,121 0 

GTL Naphtha 0 0 0 0 0 0 0 0 0 0 

GTL Diesel 0 0 0 0 0 0 0 0 0 0 

VGO HS 0 0 0 0 551 -70 0 0 7 0 

VGO LS 0 0 1 0 0 0 0 0 0 0 

HS AR (A960) 0 0 0 0 0 0 0 0 0 0 

LS AR (Alg) 199 -2 0 0 199 70 0 0 0 0 

Normal Butane 28 2 38 -16 112 0 42 5 40 0 

Isobutane 14 4 22 1 62 -5 14 0 0 0 

MTBE 0 0 0 0 0 0 0 0 0 0 

Ethanol - E10 62 -285 39 -152 34 -62 13 -42 27 0 

Ethanol - E20 699 699 438 438 358 358 153 153 310 0 

Ethanol - E85 0 0 0 0 94 94 0 0 0 0 

Reformer Feed 0 0 0 0 0 0 0 0 0 0 

Methanol 0 0 0 0 0 0 0 0 0 0 

Natural Gas (FOE) 78 -1 143 3 570 1 122 0 176 0 

Hydrogen (MSCF) 0 0 0 0 0 0 0 0 0 0 

Pentanes Plus 0 0 0 -32 52 0 8 -10 0 0 

Import CBOB 10% 277 277 0 0 0 0 0 0 0 0 

Import CBOB 20% 0 0 0 0 0 0 0 0 0 0 

Import RBOB 10% 123 -77 0 0 0 0 0 0 0 0 

Import RBOB 20% 0 0 0 0 0 0 0 0 0 0 

Import Alkylate 25 9 0 0 0 0 0 0 0 0 

Import Raffinate 39 -9 0 0 0 0 0 0 46 0 

Import Reformate 0 0 0 0 0 0 0 0 0 0 

Import FCC Naphtha 0 0 0 0 0 0 0 0 0 0 

Import Lt Naphtha 0 0 0 0 16 -14 0 0 1 0 

Import Hvy Naph 0 0 0 0 42 0 0 0 0 0 

Transfer Lt Naphtha 0 0 4 4 0 0 0 0 0 0 

Transfer Reformate 0 0 0 -5 0 0 0 0 0 0 

Transfer Alkylate 60 0 6 3 0 0 0 0 23 0 

Transfer FCC Naphtha 0 0 0 0 0 0 0 0 0 0 

Transfer Raffinate 0 0 0 -2 0 0 0 0 60 0 

Transfer RBOB 10% 650 -47 79 29 0 0 0 0 0 0 

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0 

Transfer CBOB 10% 1,300 2 421 -29 0 0 17 17 0 0 

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0 

Isooctane 7 7 0 0 0 0 0 0 42 0 

Isooctene 21 10 0 -2 8 8 0 0 5 0 

637 
 

Table 4.4-42. 

Summary of Total and Incremental Refinery Outputs by PADD 

(thousand barrels/day) PADD 1 PADD 2 PADD 3 PADD 4/5 CA 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Control 

Case 

Difference 

from Ref Case 

Propane 33 -1 53 -11 130 -15 22 -6 55 -3 

Propylene 19 0 43 0 245 0 2 0 12 0 

Normal Butane 0 0 6 2 45 -1 0 0 0 0 

Isobutane 0 0 0 0 0 0 0 0 19 10 

PC Naphtha 16 0 40 0 433 0 0 0 0 0 

PC Gasoil 0 0 495 -60 158 0 0 0 0 0 

CG Reg 0 -73 0 -552 0 -1,176 0 -246 0 0 

CG Prem 0 0 0 0 0 -2 0 -33 0 0 

CG E10 Reg 0 -1,480 0 -1,172 0 -141 0 -450 0 -113 

CG E10 Prem 334 75 317 -11 240 -11 134 34 18 -4 

RFG E10 Reg 0 -1,421 0 -328 0 -463 0 0 0 -1,312 

RFG E10 Prem 276 5 65 3 92 4 0 0 253 3 

CG E20 Reg 2,009 2,009 1,825 1,825 1,397 1,397 757 757 125 125 

RFG E20 Reg 1,449 1,449 343 343 373 373 0 0 1,409 1,409 

E85 to CG 0 0 0 0 0 0 0 0 0 0 

E85 to RFG 0 0 0 0 110 110 0 0 0 0 

Transfer RBOB 10% 0 0 0 0 729 -17 0 0 0 0 

Transfer RBOB 20% 0 0 0 0 0 0 0 0 0 0 

Transfer CBOB 10% 0 0 0 0 1,738 -11 0 0 0 0 

Transfer CBOB 20% 0 0 0 0 0 0 0 0 0 0 

Jet/Kero A (450ppm) 27 0 115 0 1,363 0 380 0 300 0 

X-Fer Diesel Rundown t 0 0 0 0 0 0 0 0 0 0 

HSD Gr 76 (0.2%) 0 0 0 0 0 0 0 0 0 0 

LSD Gr 74 (.05%) 0 0 0 0 0 0 0 0 0 0 

ULSD (15 ppm) 559 8 650 -27 2,182 -41 526 14 0 0 

CARB Diesel 0 0 0 0 0 0 0 0 354 -4 

X-Fer C5's to Storage 0 0 0 0 0 0 0 0 41 41 

1% Residual Fuel 0 0 0 0 0 0 0 0 0 0 

Residual Fuel 83 12 57 0 244 -28 146 1 54 -18 

Slurry 29 -3 80 -9 153 -5 0 0 30 0 

Asphalt & Wax 143 0 210 0 158 0 5 0 44 0 

Gasoil 0 0 9 0 0 0 0 0 10 0 

Lubes 19 0 17 0 158 0 0 0 20 0 

Benzene 11 0 11 0 51 0 0 0 0 0 

Toluene 0 0 0 0 35 0 0 0 0 0 

Xylenes 0 0 0 0 8 0 0 0 0 0 

Cumene 0 0 0 0 0 0 0 0 0 0 

Cyclohexane 0 0 0 0 0 0 0 0 0 0 

Transfer Raffinate 0 0 0 0 60 -2 0 0 0 0 

Transfer Alkylate 0 0 0 0 89 -34 0 0 0 0 

Transfer Reformate 0 0 0 0 0 -5 0 0 0 0 

Transfer FCC naphtha 0 0 0 0 0 0 0 0 0 0 

Transfer Lt Naphtha 0 0 0 0 4 4 0 0 0 -24 

Transfer Blendstock 0 0 0 0 0 0 0 0 0 0 

Sulfur (STons) 1 0 4 0 16 -1 2 0 4 0 

Coke (STon) 1 0 12 -2 64 -5 7 0 21 1 

Table 4.4-43 summarizes the change in refinery unit throughputs by PADD comparing 

the mid-ethanol blend case to the reference case. 

638 
Table 4.4-43. 

Change in Refinery Unit Capacities by PADD relative to the Reference Case 

(thousand barrels/day) 

Refinery Unit PADD 1 PADD 2 PADD 3 PADD 4/5 CA U.S. 

Crude Tower 0 -421 -467 -41 -1 -930 

Vacuum Tower 0 -188 -200 -11 0 -399 

Sats Gas Plant 9 0 -24 -22 -14 -51 

Unsats Gas Plant 0 -1 -46 0 -12 -59 

FCC DeC5 Tower 0 0 0 0 0 0 

FCC 0 0 -151 0 -63 -214 

FCC Splitter 0 -6 -82 0 -20 -108 

Hydrocracker 0 0 0 -5 0 -5 

H-Oil Unit 0 0 0 0 0 0 

Delayed Coker 0 0 -91 0 0 -91 

Visbreaker 0 0 0 0 0 0 

Thermal Naphtha Splitter 0 -4 -11 0 1 -14 

CRU Reformer 0 0 0 0 0 0 

SRU Reformer 0 0 0 0 -30 -30 

BTX Reformer 0 1 0 0 0 1 

C4 Isomerization 0 0 0 0 -3 -3 

C5/C6 Isomerization -16 0 0 0 0 -16 

HF Alkylation 0 0 0 0 0 0 

H2SO4 Alkylation 27 0 -46 -8 -29 -56 

Dimersol 0 0 0 0 0 0 

Cat Poly 0 0 0 0 0 0 

Isooctane 0 0 0 0 0 0 

DHT - Total 10 0 -17 -1 0 -8 

DHT 2nd RCT - Total 15 56 -17 -8 24 71 

DHT Arom Saturation 0 0 0 0 0 0 

NHT - Total Fd 14 0 0 11 0 25 

CGH - Generic 11 -49 -51 10 0 -79 

CGH - Olefin Sat'n 0 0 0 0 0 0 

FCCU Fd HDT -1 0 0 -34 0 -35 

LSR Splitter 0 17 0 0 0 17 

LSR Bz Saturator 0 0 0 0 0 0 

Reformate Saturator -16 -9 5 0 -50 -70 

Reformate Splitter -48 -27 15 0 -150 -210 

SDA 0 0 0 0 0 0 

MTBE 0 0 0 0 0 0 

TAME 0 0 0 0 0 0 

Hydrogen Plant - Total MSCF -2 81 253 17 83 432 

Lube Unit 0 0 0 0 0 0 

Sulfur Plant 0 0 -935 -98 -11 -1,044 

Merox Jet 0 0 0 0 0 0 

Merox Diesel 0 0 0 0 0 0 

BTX Reformer - Tower feed 0 0 0 0 0 0 

BTX Reformer - Extract feed 0 1 0 0 0 1 

These changes in refinery unit throughputs are associated with changes in capital 

investments. Table 4.4-44 summarizes the projected change in capital investments between the 

mid-ethanol blend case and the reference case. 

639 
Table 4.4-44. 

Change in Refinery Unit Investments by PADD (million dollars/yr) 

Refinery Unit PADD 1 PADD 2 PADD 3 PADD 4/5 CA U.S. 

Crude Tower 0 -995 -739 -154 -1 -1,889 

Vacuum Tower 0 -527 -423 -18 -1 -968 

Sats Gas Plant 53 0 -63 -102 -68 -181 

Unsats Gas Plant 1 0 -240 0 -101 -341 

FCC DeC5 Tower 0 0 0 0 0 0 

FCC 0 0 -1,032 0 -786 -1,818 

FCC Splitter 0 -6 -38 0 -16 -60 

Hydrocracker 0 0 0 -95 0 -95 

H-Oil Unit 0 0 0 0 0 0 

Delayed Coker 0 0 -1,261 0 0 -1,261 

Visbreaker 0 0 0 0 0 0 

Thermal Naphtha Splitter 0 -5 -4 0 1 -9 

CRU Reformer 0 0 0 0 0 0 

SRU Reformer 0 0 0 0 -180 -180 

BTX Reformer 2 11 0 0 0 13 

C4 Isomerization 0 0 0 0 -15 -15 

C5/C6 Isomerization -198 0 0 0 0 -198 

HF Alkylation 0 0 0 0 0 0 

H2SO4 Alkylation 443 0 -518 -99 -508 -682 

Dimersol 0 0 0 0 0 0 

Cat Poly 0 0 0 0 0 0 

Isooctane 0 0 0 0 0 0 

DHT - Total 63 0 -146 -6 0 -89 

DHT 2nd RCT - Total 66 354 -104 -34 186 468 

DHT Arom Saturation 0 0 0 0 0 0 

NHT - Total Fd 97 0 0 35 0 132 

CGH - Generic 46 -203 -202 34 0 -325 

CGH - Olefin Sat'n 0 0 0 0 0 0 

FCCU Fd HDT -9 0 0 -349 0 -358 

LSR Splitter 0 7 0 0 0 7 

LSR Bz Saturator 0 0 0 0 0 0 

Reformate Saturator -96 -56 14 0 -318 -455 

Reformate Splitter -56 -33 8 0 -166 -247 

SDA 0 0 0 0 0 0 

MTBE 0 0 0 0 0 0 

TAME 0 0 0 0 0 0 

Hydrogen Plant - Total MSCF -5 266 607 84 289 1,241 

Lube Unit 0 0 0 0 0 0 

Sulfur Plant 0 0 -2 -1 0 -3 

Merox Jet 0 0 0 0 0 0 

Merox Diesel 0 0 0 0 0 0 

BTX Reformer - Tower feed 0 1 0 0 0 1 

BTX Reformer - Extract feed 0 3 0 0 0 4 

Total 407 -1,183 -4,144 -703 0 -7,308 

Table 4.4-44 shows that incremental to the reference case, refiners are expected to reduce 

their capital investments by $7.3 billion compared to business as usual. Most of the reduction 

occurs in PADDs 2 and 3 where large volumes of ethanol, and other gasoline blendstocks are 

expected to enter the gasoline pool. Of course, this capital cost decrease is countered by capital 

costs incurred to build new ethanol plants and put into place the distribution system that the new 

ethanol requires. 

640 
Table 4.4-45 summarizes the gasoline qualities for the mid-ethanol blend case and the 

reference case. 

Table 4.4-45. 

Gasoline Volume, Quality and Energy Density by Gasoline Type at the PADD Terminal 

PADD 1 PADD 2 PADD 3 PADD 4/5 CA US 

RFG Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control Ref Case Control 

Total ('000 BPD) 1,692 1,725 391 408 551 465 - - 1,562 1,661 4,197 4,260 

Ethanol ('000 BPD) 171 321 39 76 56 85 - - 158 310 424 791 

RVP (psi) 10.7 10.3 10.4 10.2 9.7 9.1 - - 9.5 9.3 10.1 9.8 

Sulfur (ppm) 23 19 23 18 20 22 - - 9 9 17 15 

Octane (R+M/2) 88.1 90.2 88.0 90.2 88.0 90.3 - - 87.6 88.3 87.9 89.5 

Aromatics (vol%) 19.9 15.6 20.0 15.8 19.5 15.0 - - 21.3 19.1 20.4 16.9 

Benzene (vol%) 0.55 0.46 0.58 0.42 0.51 0.44 - - 0.51 0.47 0.53 0.46 

Olefins (vol%) 11.7 10.8 10.3 7.6 8.7 8.2 - - 5.7 5.7 8.9 8.2 

Oxygen (wt%) 3.7 6.8 3.7 6.8 3.7 6.7 - - 3.7 6.8 3.7 6.8 

E200 (vol%) 55.1 64.2 59.7 65.0 54.3 60.1 - - 57.7 62.1 56.4 63.0 

E300 (vol%) 93.9 89.5 84.3 88.2 87.4 85.6 - - 86.2 86.2 89.3 87.6 

Energy (MMBtu/Bbl) 4.954 4.806 4.920 4.784 4.983 4.848 - - 4.991 4.905 4.969 4.847 

CG 

Total ('000 BPD) 2,263 2,344 2,052 2,142 1,568 1,637 829 891 135 143 6,847 7,156 

Ethanol ('000 BPD) 176 440 152 401 40 306 56 166 14 27 436 1,340 

RVP (psi) 11.6 11.5 11.7 11.3 10.7 10.4 11.3 11.1 10.5 10.2 11.4 11.1 

Sulfur (ppm) 24 22 23 23 24 21 27 28 25 26 24 23 

Octane (R+M/2) 87.7 90.2 88.0 90.1 88.0 90.1 86.9 87.2 89.1 90.3 87.8 89.8 

Aromatics (vol%) 24.2 20.2 24.4 20.4 27.2 20.2 19.4 13.4 28.4 24.4 24.4 19.5 

Benzene (vol%) 0.61 0.45 0.64 0.46 0.59 0.45 1.16 1.02 0.60 0.55 0.68 0.53 

Olefins (vol%) 13.9 12.9 11.1 10.2 14.9 11.0 6.9 6.3 17.1 16.8 12.5 10.9 

Oxygen (wt%) 2.9 6.9 2.7 6.8 0.9 6.8 2.5 6.9 3.6 6.8 2.3 6.8 

E200 (vol%) 55.4 62.2 55.7 64.1 46.5 61.1 59.6 68.5 55.8 64.9 54.0 63.3 

E300 (vol%) 93.4 84.9 84.3 86.3 87.4 84.9 83.5 90.9 86.2 83.8 87.9 86.0 

Energy (MMBtu/Bbl) 4.980 4.813 4.965 4.809 5.069 4.845 5.011 4.811 4.969 4.841 4.999 4.819 

E85 

Total ('000 BPD) - 0 - 0 - 110 - 0 - 0 - 110 

Ethanol ('000 BPD) - 0 - 0 - 94 - 0 - 0 - 95 

RVP (psi) - 10.5 - 10.5 - 12.2 - 10.3 - 10.4 - 12.2 

Sulfur (ppm) - 10 - 10 - 9 - 10 - 9 - 9 

Octane (R+M/2) - 107.8 - 107.8 - 108.0 - 107.6 - 107.7 - 108.0 

Aromatics (vol%) - 0.7 - 0.7 - 0.0 - 0.7 - 0.7 - 0.0 

Benzene (vol%) - 0.02 - 0.02 - 0.00 - 0.05 - 0.02 - 0.00 

Olefins (vol%) - 2.1 - 2.1 - 2.3 - 0.2 - 1.1 - 2.3 

Oxygen (wt%) - 30.6 - 30.6 - 30.8 - 30.6 - 30.6 - 30.8 

E200 (vol%) - 128.1 - 128.0 - 129.9 - 127.7 - 127.8 - 129.9 

E300 (vol%) - 96.1 - 96.0 - 96.6 - 96.0 - 96.1 - 96.6 

Energy (MMBtu/Bbl) - 3.635 - 3.636 - 3.598 - 3.635 - 3.637 - 3.598 

All Mogas 

Total ('000 BPD) 3,955 4,069 2,443 2,550 2,120 2,212 829 891 1,697 1,804 11,044 11,526 

Ethanol ('000 BPD) 347 760 191 477 95 485 56 167 171 337 860 2,226 

RVP (psi) 11.2 11.0 11.5 11.2 10.5 10.2 11.3 11.1 9.6 9.4 10.9 10.6 

Sulfur (ppm) 24 21 23 22 23 21 27 28 10 11 22 20 

Octane (R+M/2) 87.9 90.2 88.0 90.1 88.0 91.0 86.9 87.2 87.8 88.5 87.8 89.8 

Aromatics (vol%) 22.4 18.3 23.7 19.6 25.2 18.1 19.4 13.4 21.8 19.5 22.9 18.3 

Benzene (vol%) 0.58 0.46 0.63 0.46 0.57 0.43 1.16 1.02 0.52 0.48 0.62 0.50 

Olefins (vol%) 12.9 12.0 10.9 9.8 13.3 10.0 6.9 6.3 6.6 6.6 11.1 9.9 

Oxygen (wt%) 3.2 6.9 2.9 6.8 1.7 8.0 2.5 6.9 3.7 6.8 2.9 7.1 

E200 (vol%) 55.3 63.0 56.4 64.2 48.5 64.3 59.6 68.5 57.5 62.4 54.9 63.8 

E300 (vol%) 93.6 86.8 84.3 86.6 87.4 85.6 83.5 90.9 86.2 86.0 88.4 86.7 

Energy (MMBtu/Bbl) 4.969 4.810 4.958 4.805 5.046 4.784 5.011 4.811 4.989 4.900 4.988 4.818 

641 
 

Chapter 5: Economic Impacts and Benefits 

5.1 Agricultural Impacts 

5.1.1 Models Utilized 

As described in the Preamble, we used a suite of tools to model the potential domestic 

and international impacts of this rulemaking on the agricultural sector. The Forest and 

Agricultural Sector Optimization Model (FASOM), developed by Professor Bruce McCarl of 

Texas A&M University and others, provides detailed information on domestic agricultural and 

greenhouse gas impacts of renewable fuels. The Food and Agricultural Policy Research Institute 

(FAPRI) at Iowa State University and the University of Missouri-Columbia maintains a number 

of econometric models that are capable of providing detailed information on impacts on 

international agricultural markets from the wider use of renewable fuels in the U.S. 

FASOM is a long-term economic model of the U.S. agriculture sector that maximizes 

total revenues for producers while meeting the demands of consumers. Using a number of 

inputs, FASOM determines which crops, livestock, and processed agricultural products would be 

produced in the U.S. In each model simulation, crops compete for price sensitive inputs such as 

land and labor at the regional level. The cost of these and other inputs are used to determine the 

price and level of production of primary commodities (e.g., field crops, livestock, and biofuel 

products). FASOM also estimates prices using costs associated with the processing of primary 

commodities into secondary products (e.g., converting livestock to meat and dairy, crushing 

soybeans to soybean meal and oil). FASOM does not capture short-term fluctuations (i.e., 

month-to-month, annual) in prices and production, however, as it is designed to identify longterm trends. 

The FASOM model also contains a forestry component. Running both the forestry and 

agriculture components of the model would show the interaction between these two sectors. 

However, the analysis for this proposal only shows the results from the agriculture component 

with no interaction from the forestry sector, as the forestry component of the model is in the 

process of being updated. We plan to utilize a complete version of the model for our analysis in 

the final rule, where agricultural land use impacts also affect forestry land use, and cellulosic 

ethanol produced from the forestry sector will affect cellulosic ethanol production in the 

agriculture sector. 

FASOM uses supply and demand curves for the 11 major U.S. domestic 

regions,LLLLLLLLLL which are calibrated to historic price and production data. FASOM also 

includes detailed supply and demand data for corn, wheat, soybeans, rice and sorghum across 37 

LLLLLLLLLL U.S. regions consist of the Pacific Northwest (West and East), Pacific Southwest, Rocky Mountains, 

Great Plains, Southwest, South Central, Corn Belt, Lake States, Southeast, and the Northeast. 

642 
 

 

 

foreign regions.MMMMMMMMMM FASOM contains transportation costs to all regions and then uses 

all of this information to determine U.S. exports to the point where prices are then equated in all 

markets. 

We chose to use FASOM to model the full potential impacts on the domestic agricultural 

sector given higher renewable fuel volumes, in part because FASOM also provides detailed 

greenhouse gas information resulting from these changes (see Chapter 2 of this RIA for more 

information). FASOM is not able to model land use and agricultural sector changes 

internationally, however. Therefore, we are working with the FAPRI models to better 

understand international agricultural impacts. Additional details on the FASOM model are 

included in the docket.NNNNNNNNNN 

The FAPRI models are econometric models covering many agricultural commodities. 

These models capture the biological, technical, and economic relationships among key variables 

within a particular commodity and across commodities. They are based on historical data 

analysis, current academic research, and a reliance on accepted economic, agronomic, and 

biological relationships in agricultural production and markets. The international modeling 

system includes international grains, oilseeds, ethanol, sugar, and livestock models. In general, 

for each commodity sector, the economic relationship that supply equals demand is maintained 

by determining a market-clearing price for the commodity. In countries where domestic prices 

are not solved endogenously, these prices are modeled as a function of the world price using a 

price transmission equation. Since econometric models for each sector can be linked, changes in 

one commodity sector will impact other sectors. Elasticity values for supply and demand 

responses are based on econometric analysis and on consensus estimates. Additional details on 

the FAPRI models are included in the docket. 

Agricultural and trade policies for each commodity in a country are included in the 

models to the extent that they affect the supply and demand decisions of the economic agents. 

These policies include taxes on exports and imports, tariffs, tariff rate quotas, export subsidies, 

intervention prices, and set-aside rates. The FAPRI models assume that existing agricultural and 

trade policy variables will remain unchanged in the outlook period. OOOOOOOOOO 

We recognize that there are inherent challenges in reconciling the results from two 

different models, however we believe that using two models provides a more robust analysis 

than either model would be able to provide alone. Part of the difference in the model results is 

due to the fact that the two models have different time horizons. Since FASOM is a long term 

econometric model, short term spikes are smoothed out over the five year reporting period. In 

comparison, the FAPRI model captures annual fluctuations that may include short-term supply 

MMMMMMMMMM FASOM Foreign Regions include: the European Economic Community, North Central Europe, 

Southwest Europe, Eastern Europe, Adriatic, Eastern Mediterranean, Former Soviet Union, North Africa, East
 

Africa, West Africa, South Africa, Red Sea, Iran, India, Taiwan, Japan, South Korea, North Korea, China, 

Bangladesh, Indonesia, Myanmar, Pakistan, Philippines, Thailand, Vietnam, West Asia, Southeast Asia, Australia, 

Caribbean, Eastern Mexico, Eastern South America, Western South America, Argentina, Brazil, Canada, Other. 

NNNNNNNNNN Beach, Robert; McCarl, Bruce, Agricultural Impacts of the Energy Independence and Security Act:
 

FASOM Results and Model Description, RTI International, October, 2008. OOOOOOOOOO Technical Report: An Analysis of EPA Biofuel Scenarios with the FAPRI International Models, CARD
 

Staff, November, 2008. 

643 
and demand responses. Some of the discrepancies may be attributed to different underlying 

assumptions pertaining to elasticities of supply and demand for different commodities. These 

differences, in turn, affect projections of imports and exports, acreage shifting, and total 

consumption and production of various commodities. Some of the differences in results are 

described in more detail in the following sections. We will continue to work with the two 

models to isolate some of the key differences in assumptions and calibrate the models to a more 

consistent Reference Case in time for the Final Rulemaking. 

5.1.2 Volumes 

For the agricultural sector analysis using the FASOM and FAPRI models of the RFS2 

biofuel volumes, we assumed 15 billion gallons (Bgal) of corn ethanol would be produced for 

use as transportation fuel by 2022, an increase of 2.7 Bgal from the Reference Case. In addition, 

we modeled 1.0 Bgal per year of biodiesel use as fuel, an increase of 0.6 Bgal from the 

Reference Case, as well as an increase of 10 Bgal of cellulosic ethanol in 2022 from the 

agriculture sector. To satisfy the cellulosic ethanol requirements, the FASOM model was able to 

choose how much cellulosic ethanol was produced through the different production pathways. 

This is purely based on the economics of each feedstock, taking account the various harvesting 

and processing costs for each feedstock, and the income the agriculture sector derives from each 

feedstock. In FASOM, this volume consists of 7.5 billion gallons of cellulosic ethanol coming 

from corn residue in 2022, 1.3 billion gallons from switchgrass and 1.4 billion gallons from 

sugarcane bagasse. The volumes for the individual cellulosic ethanol feedstocks were not set 

exogenously. 

Given the short time frame for conducting this analysis, some of the projected sources of 

biofuels analyzed in the RFS2 proposal are not currently modeled in FASOM and FAPRI. For 

example, biodiesel from corn oil fractionation is not currently accounted for in FASOM. In 

addition, since FASOM is a domestic agricultural sector model, it can’t be utilized to examine 

U.S. biofuel imports. Also, neither of the two models used for this analysis — FASOM or 

FAPRI — include biofuels derived from domestic municipal solid waste or from the U.S. 

forestry sector. Thus, for the RFS2 agricultural sector analysis, these biofuel sources were 

estimated outside of the agricultural sector models (see Chapter 1). We estimate that 

approximately 2 billion gallons of cellulosic ethanol will be produced from municipal solid 

waste, and 4 billion gallons of cellulosic ethanol will be produced from the forestry sector in 

2022. 

All the results presented in this section are relative to the AEO 2007 Reference Case 

renewable fuel volumes, which include 12.3 Bgal of grain-based ethanol, 0.4 Bgal of biodiesel, 

and 0.3 Bgal of cellulosic ethanol in 2022. The domestic figures are provided by FASOM and 

FAPRI, and all of the international numbers are provided by FAPRI. For a more detailed set of 

results of the agricultural sector impacts of the RFS2 volumes, see the analytical reports 

submitted by FASOM and FAPRI in the docket of this rule. 

644 
 

 

 

Table 5.1-1 

Biofuel Volumes Modeled in 2022 

(Billions of Gallons) 

Biofuel Reference Case Control Case Change 

Corn Ethanol 12.3 15.0 2.7 

Corn Residue Cellulosic Ethanol 0 7.5 7.5 

Sugarcane Bagasse Cellulosic Ethanol 0.3 1.4 1.1 

Switchgrass Cellulosic Ethanol 0 1.3 1.3 

Other Ethanol 0 0.2 0.2 

Biodiesel 0.4 1.0 0.6 

5.1.3 Biofuel Feedstock Assumptions 

In order to run a representative model of the U.S. and international agriculture sectors to 

analyze the impact of the RFS2 biofuel volumes requirement, a series of assumptions and input 

parameters were set in order to achieve two major goals in our analysis. First, that the input 

assumptions are based on the most current data and projections available in government, 

industry, and academia; and second, to ensure that the two agriculture models, FASOM and 

FAPRI, were analyzing similar real-world assumptions, and thus present a detailed and 

consistent worldwide analysis. Table 5.1-2 lists some of the key assumptions associated with the 

agriculture sector modeling, as well as the source for these assumptions. Additional details on 

the assumptions included in FASOMPPPPPPPPPP and FAPRIQQQQQQQQQQ are included in the 

docket. 

A series of information was gathered from and reviewed by other government agencies, 

such as USDA and DOE. These include corn and soybean yields,RRRRRRRRRR corn ethanol dry 

and wet mill plant processing energy use, corn ethanol yields, corn ethanol by-product use, and 

estimated corn stover yields. For other assumptions, we relied on external expertise, such as 

FAPRI; the Greenhouse gases, Regulated Emissions and Energy use in Transportation (GREET) 

model;SSSSSSSSSS the Assessment System for Population Exposure Nationwide (ASPEN) 

model;TTTTTTTTTT and the Agriculture Resource Management Survey (ARMS).UUUUUUUUUU 

PPPPPPPPPP Beach, Robert; McCarl, Bruce, Agricultural Impacts of the Energy Independence and Security Act: 

FASOM Results and Model Description, RTI International, October, 2008. 

QQQQQQQQQQ Technical Report: An Analysis of EPA Biofuel Scenarios with the FAPRI International Models, CARD 

staff, November, 2008. 

RRRRRRRRRR USDA Agricultural Projections to 2017 (OCE-2008-1), February, 2008. SSSSSSSSSS The GREET model is run by Argonne National Laboratory at the Department of Energy. GREET can 

simulate more than 100 fuel production pathways and more than 80 vehicle/fuel systems.

TTTTTTTTTT ASPEN is a computer simulation model used to estimate toxic air pollutant concentrations is called the 

Assessment System for Population Exposure Nationwide, or. This model is based on the EPA’s Industrial Source 

Complex Long Term model (ISCLT) which simulates the behavior of the pollutants after they are emitted into the 

atmosphere. ASPEN uses estimates of toxic air pollutant emissions and meteorological data from National Weather 

Service Stations to estimate air toxics concentrations nationwide. 

UUUUUUUUUU ARMS is sponsored by the Economic Research Service (ERS) and National Agricultural Statistics 

Service (NASS) at USDA, and provides observations of field-level farm practices, the economics of the farm 

business, and the characteristics of the American farm household. 

645 
 

 

Projected crop yields, both domestically and internationally, constitute one of the most 

influential factors of this agricultural analysis. The yields presented in Table 5.1-2 are based on 

the USDA projections through 2017 (the last year of their baseline projections report) and then 

extrapolated out to 2022. The yields in this table represented the national weighted average 

yields, which vary by region. These yields are based on historical averages for the region, which 

increase over time in both the AEO Reference case and the EISA Control Case. FASOM 

assumes the rate of increase is (1.6% per year). For this proposal, we modeled the same yields in 

both the Reference Case and the Control Case, assuming there was no significant impact on 

yields due to commodity price changes resulting from the RFS2 volumes (i.e., no price-induced 

yield changes). In addition, we did not model changes in yields that might occur based on 

increased planting on marginal land or management practices (e.g., residue removal, corn after 

corn rotations) as a result of the RFS2 volumes. 

For cellulosic biofuels from corn residues, the current assumptions in FASOM for residue 

removal rates are based on the Graham et. al. paperVVVVVVVVVV and the Perlack et al 

study.WWWWWWWWWW This approach uses a maximum percent removal of residues on acres 

based on tillage practices.XXXXXXXXXX Other recent papers have raised the issue that a more 

relevant metric is a minimum amount of mass that must remain on an acre of land to prevent 

runoff and maintain soil carbon levels.YYYYYYYYYY However, we were unable to obtain national 

or regional estimates in time for the proposal. We intend to review these assumptions between 

proposal and final, and, if possible, update these assumptions as appropriate. In addition, we 

plan to review in more detail the sustainable removal rates for other crops such as wheat and rice 

residues.ZZZZZZZZZZ,AAAAAAAAAAA 

FASOM assumes fertilizer application rates do not increase over time in proportion to the 

increase in yields, as shown in Table 5.1-2. This data is based on USDA data that shows 

fertilizer application rates per acre remaining relatively steady for the past 30 years, during 

which time corn yields have increased approximately 70%.BBBBBBBBBBB However, it may be 

reasonable to assume that there may be a corresponding increase in fertilizer rates as crop yields 

increase into the future, and EPA requests comment on the relationship. In addition, when 

residues are removed from the field, some of the nutrients that are contained in the residue must 

be replaced through additional fertilizer use. For the proposal, we assumed that 7 additional 

pounds of nitrogen and 3.6 lbs of phosphorous must be applied per ton of residue removed. We 

will continue to review these assumptions for the final rule. 

VVVVVVVVVV See also http://www.cpnrd.org/Harvesting%20Stover.pdf WWWWWWWWWW Available at http://feedstockreview.ornl.gov/pdf/billion_ton_vision.pdf. XXXXXXXXXX Many site specific factors associated with the sustainable removal of residue (e.g., crop type, soil type, 

soil fertility, slope, and climate) affect which geographic regions are suitable for crop residue removal. Detailed 

modeling of these factors was beyond the scope of this analysis. 

YYYYYYYYYY Wilhelm et. al Corn Stover to Sustain Soil Organic Carbon Further Constrains Biomass Supply, Ag 

Journal (2007)

ZZZZZZZZZZ Kerstetter JD, Lyons JK. Logging and agricultural residue supply curves for the Pacific Northwest. 

Washington State University Energy Publication; 2001 

AAAAAAAAAAA Banowetz et al. Assessment of straw biomass feedstock resources in the Pacific Northwest. Biomass 

and Bioenergy. In Press 

BBBBBBBBBBB Data from the National Agriculture Statistics Service (NASS) at USDA: http://www.nass.usda.gov/ 

646 
 

 

Lastly, there is a limit to how many acres crops can be planted on. The Conservation 

Reserve Program (CRP)CCCCCCCCCCC is run by the Natural Resources Conservation Service at 

USDA. This program is designed to maintain Federal, State, and tribal environmental laws by 

making payments to farmers equivalent to the income otherwise earned from developing the land 

enrolled in the program. In the 2008 Farm Bill, the number of acres enrolled in the CRP was 

given a minimum limit of 32 million acres. It is assumed that USDA will increase payments to 

match the rising costs of crops that could be grown on CRP acres through the 2022 time period 

for this analysis. 

CCCCCCCCCCC See: http://www.nrcs.usda.gov/programs/CRP/ 

647 
648 

Table 5.1-2. 

Agriculture Model Assumptions 

Assumption Notes 

Feedstock Production 

U.S. national average corn yields are approximately 

170 bu/acre in 2017 and 180 bu/acre in 2022 (a 1.6% 

annual increase over the baseline year) Consistent with USDA projections 

U.S. national average soybean yields are (http://www.ers.usda.gov/publications/oce081/) 

approximately 50 bu/acre in 2022 (a 0.4% annual 

increase) 

International corn yields increasing over time, for 

example: 

Argentina ~140 bu/acre in 2022 (a 0.8% annual 

increase) 

Brazil ~68 bu/acre in 2022 (a 1.1% annual increase) FAPRI Models International soybean yields increasing over time, for 

example: 

Argentina ~48 bu/acre in 2022 (a 0.7% annual 

increase) 

Brazil ~50 bu/acre in 2022 (a 1.1% annual increase) 

Corn residue removal rates of 50% are allowed for no 

till practices; 35% removal rate allowed for reduced till 

practices (no removal from conventional till) 

Derived from Graham et. al., Agronomy Journal, 

99:1–11 (2007). “Current and Potential U.S. Corn 

Stover Supplies.” and Perlack, R. D., L. L. 

Wright, A. F. Turhollow, R. L. Graham, B. J. 

Stokes, and D. C. Erbach. 2005. Biomass as 

Feedstock for a Bioenergy and Bioproducts 

Industry: the Technical Feasibility of a Billion-ton 

Annual Supply. Report prepared for the U.S. 

Department of Energy and the U.S. Department 

of Agricutlure. 

The Conservation Reserve Program (CRP) has a 

minimum limit of 32 million acres enrolled in the 

program at any given time 

2008 Farm Bill 

USDA baseline assumptions 

Fertilizer Use 

U.S. nitrogen application rate in corn is approximately 

136 lbs/acre in the corn belt in 2022 

U.S. phosphorous application rate in corn is 

approximately 28 lbs/acre in the corn belt in 2022 

Based on ARMS data, adjusted for differences in 

regions and irrigation practices 

For U.S. assume higher yields require no increase in 

fertilizer use 

Based on USDA baseline assumptions 

This holds for all farming rotations (e.g., corn / 

soybean and corn / corn) and land types (e.g., 

prime and marginal land); see below for stover 

removal impacts 

Nitrogen nutrient replacement application = 7 lbs/ton 

corn residue removed 

Phosphorous nutrient replacement application = 3.6 

lbs/ton corn residue removed 

These numbers come from the Argonne National 

Lab Report, Fuel Cycle Assessment of Selected 

Bioethanol Production Pathways in the United 

States. (November 7, 2006). (Used and cited by 

GREET) 

Processing 

1 bushel of corn produces 17 lbs of dried distillers 

grains (dry tons). 

1 pound of DDG substitutes 0.9 pounds of corn and 

0.1 pound of soybean meal feed 

www.ethanol.org 

USDA baseline assumptions 
5.1.4 Economic Impacts – Domestic – Control Case 

For this analysis, the FASOM model is utilized for all domestic agriculture impacts. 

Although the FAPRI models do not provide the same amount of detail on GHG emissions for the 

domestic agriculture impacts as the FASOM model, FAPRI does estimate some of the same 

outputs, such as national crop acres, prices, and exports. Additionally, a common set of inputs 

were provided to both models, such as corn yields, energy prices, and the number of acres 

enrolled in the Conservation Reserve Program (CRP). In this chapter, we present both the 

FASOM and FAPRI results to demonstrate the range of potential agricultural impacts. Though 

our primary domestic analysis relies upon the FASOM model, as it contains more detail and 

scope beyond the FAPRI model for the U.S., this allows for a useful comparison between the 

two models, reinforces the accuracy of our domestic analysis, and ensures consistency when 

analyzing the impacts of the RFS2 fuel volume requirements on the domestic and international 

agriculture markets. 

Commodity Prices 

To satisfy the demands for increased biofuels for the RFS2 proposal, the FASOM model 

predicts an increase in prices for the primary feedstocks of biofuels. The proposed increase in 

corn ethanol production results in an increase in U.S. corn prices of $0.15 per bushel (4.6%) 

above the Reference Case price of $3.19 per bushel in 2022. Similarly, by 2022, the increase in 

demand for biodiesel production leads to an increase of U.S. soybean prices, which would 

increase by $0.29 per bushel (2.9%) above the Reference Case price of $9.97 per bushel. One of 

the major feedstocks of cellulosic ethanol is sugarcane bagasse, and as the demand for cellulosic 

ethanol increases with the RFS2 proposal, the price of sugarcane in 2022 would increase 

$13.34/ton (41%) above the Reference Case price of $32.49 per ton. There are also indirect 

effects from the RFS2 proposal reflected in commodity prices. For instance, corn is a major 

component in animal feed in the U.S., and as corn prices rise in 2022, beef prices would increase 

$0.93 per hundred pounds (1.4%), relative to the Reference Case price of $67.72 per hundred 

pounds. Higher U.S. corn prices would have a direct impact on the value of U.S. agricultural 

land. As demand for corn and other farm products increases, the price of U.S. farm land would 

also increase. Our analysis shows that land prices would increase by approximately 21% by 

2022, relative to the Reference Case. 

The FAPRI models also provide some domestic agriculture impacts in the U.S. In 2022, 

FAPRI predicts that U.S. corn prices would increase $0.22 per bushel (8.2%) above the 

Reference Case to $2.91 per bushel. Soybean prices would increase $0.42 per bushel (5.7%) 

above the Reference Case to $7.86 per bushel in 2022. 

649 
 

Table 5.1-3. 

Change in U.S. Commodity Prices from the Reference Case 

(2006$) 

FASOM Model 

Commodity Change % Change 

Corn $0.15/bushel 4.6% 

Soybeans $0.29/bushel 2.9% 

Sugarcane $13.34/ton 41% 

Fed Beef $0.93/hundred pounds 1.4% 

FAPRI Model 

Commodity Change % Change 

Corn $0.22/bushel 8.2% 

Soybeans $0.42/bushel 5.7% 

In FASOM, the increase in demand for cellulosic ethanol also leads to the production of 

feedstocks in the Control Case that previously had no value in the Reference Case. This includes 

dedicated energy crops, such as switchgrass, as well as crop residues, such as corn stover. The 

price of switchgrass in 2022 is $30.18 per wet ton, and the farm gate feedstock price of corn 

residue is $32.74/wet ton in the Control Case. These prices do not include the storage, handling, 

or delivery costs. We intend to update the costs assumptions (described in more detail in Section 

4.1.1 of the DRIA) for the final rule. Since the FAPRI models do not explicitly model cellulosic 

ethanol production from agriculture residues or dedicated energy crops, comparable price 

impacts are not available. 

Commodity Use Changes 

Changes in the consumption patterns of U.S. corn can be seen by the increasing 

percentage of corn used for ethanol. FASOM estimates that the amount of domestically 

produced corn used for ethanol in 2022 would increase to 33%, relative to the 28% usage rate 

under the Reference Case. The rising price of corn and soybeans in the U.S. would have a direct 

impact on how corn is used. Higher domestic corn prices would lead to lower U.S. exports as 

the world markets shift to other sources of these products or expand the use of substitute grains. 

FASOM estimates that U.S. corn exports would drop 263 million bushels (-9.9%) to 2.4 billion 

bushels by 2022. In value terms, U.S. exports of corn would fall by $487 million (-5.7%) to $8 

billion in 2022. FAPRI estimates that U.S. corn exports would decrease 288 million bushels (­

7.6%) to 3.5 billion bushels in 2022. In value terms, U.S. corn exports not change, maintaining 

its value of $10.2 billion. 

U.S. exports of soybeans would also decrease under this proposal. FASOM estimates 

that U.S. exports of soybeans would decrease 96.6 million bushels (-9.3%) to 943 million 

bushels in 2022. In value terms, U.S. exports of soybeans would decrease by $691 million (­

6.7%) to $9.7 billion in 2022. FAPRI predicts that U.S. soybean exports would decrease 43 

million bushels (-5.1%) to 802 million bushels and in value terms, U.S. soybean exports would 

increase by $19.4 million (0.3%) to $6.3 billion in 2022. 

650 
Table 5.1-4. 

Reductions in U.S. Exports from the Reference Case in 2022 

FASOM Model 

Exports Change % Change 

Corn in Bushels 263 million -9.9% 

Soybeans in Bushels 96.6 million -9.3% 

Total Value of Exports Change % Change 

Corn (2006$) -$487 million -5.7% 

Soybeans (2006$) -$691 million -6.7% 

FAPRI Model 

Exports Change % Change 

Corn in Bushels 288 million -7.6% 

Soybeans in Bushels 96.6 million -5.1% 

Total Value of Exports Change % Change 

Corn (2006$) $0 0% 

Soybeans (2006$) $19.4 million 0.3% 

Higher U.S. demand for corn for ethanol production would cause a decrease in the use of 

corn for U.S. livestock feed. Substitutes are available for corn as a feedstock, and this market is 

price sensitive. Several ethanol processing byproducts could also be used to replace a portion of 

the corn used as feed, depending on the type of animal. Distillers dried grains with solubles 

(DDGS) are a byproduct of dry mill ethanol production, and gluten meal and gluten feed are 

byproducts of wet milling ethanol production. Based on the assumption that 1 bushel of corn 

produces 17 lbs of DDGS, and that 1 pound of DDGS substitutes for 0.9 lbs if corn and 0.1 lbs of 

soybean meal in animal feed (see Table 5.1-2), FASOM estimates that the use of these ethanol 

byproducts in feed would increase 19% to 30 million tons, compared to 25 million tons under the 

Reference Case in 2022. 

Table 5.1-5. 

Percent Change in Ethanol Byproducts Use in Feed 

Relative to the Reference Case
 

Category 2022 

Ethanol Byproducts 19% 

The EISA cellulosic ethanol requirements result in the production of residual agriculture 

products as well as dedicated energy crops. By 2022, FASOM estimates 90 million tons of corn 

residue are harvested for cellulosic ethanol production, as well as 18 million tons of switchgrass. 

Additionally, sugarcane bagasse for cellulosic ethanol production increases by 15.7 million tons 

to 19.7 million tons relative to the Reference Case. 

Land Use Change 

In order to satisfy the increased demand for corn ethanol, FASOM estimates an increase 

of 3.2 million acres, 3.9%, in harvested corn acres, above the 83.4 million acres harvested under 

651 
 

the Reference Case.DDDDDDDDDDD Most of the new corn acres come from a reduction in existing 

crop acres, such as rice, wheat, and hay. Rice acres, in 2022, decreases by 151 thousand acres (­

3.8%) to 3.8 million acres in the Control Case. Wheat acres decrease by 676 thousand acres (­

1.5%) to 43.6 million acres in 2022. Hay acres decrease by 625 thousand acres (-1.1%) to 54.2 

million acres in 2022. Similarly, FAPRI estimates that harvested U.S. corn acres increase by 3.6 

million acres, 4.2%, in 2022. See Table 5.1-6 for changes in crop acres in the FASOM model. 

As stated above, the FASOM model does not currently account for the impacts of the RFS2 

biofuel volume requirements’ impact on the forestry sector. We plan on using the forestry 

component in combination with the agriculture component to analyze the final rule. 

Table 5.1-6. 

Change in Crop Acres Relative to the Reference Case in 2022 

(millions of acres)
 

Crop Change % Change 

Corn 3.2 3.9% 

Hay -0.6 -1.1% 

Rice -0.2 -3.8% 

Soybeans -0.4 -0.5% 

Sugarcane 0.7 55% 

Switchgrass 2.8 N/A 

Wheat 0.7 -1.5% 

Though demand for biodiesel increases, the models predict a fall in U.S. soybean acres 

harvested, assuming soybean-based biodiesel meets the EISA GHG emission reduction 

thresholds. According to the FASOM model, harvested soybean acres would decrease by 

approximately 0.4 million acres (-0.5%) relative to the Reference Case acreage of 71.5 million 

acres in 2022. Despite the decrease in soybean acres, soybean oil production would increase by 

0.4 million tons (4.0%) by 2022 over the Reference Case. Additionally, FASOM predicts that 

soybean oil exports would decrease 1.3 million tons (-52%) in 2022 relative to the Reference 

Case. 

Likewise, FAPRI estimates that the increased demand for biodiesel from soybean oil 

results chiefly in a reduction in soybean oil exports, rather than an increase in acres harvested. 

Harvested soybean acres decrease by 0.9 million acres (-1.3%) to 69.1 million acres in 2022. 

FAPRI also estimates little change in soybean oil production, with a decrease of 32 million 

pounds (-0.1%) to 26.9 billion pounds in 2022. Exports in 2022 decrease by 2.9 billion pounds 

(-26.8%), to 7.9 billion pounds in 2022. 

 In the FASOM model, as the demand for cellulosic ethanol increases, most of the 

production is derived from corn residue harvesting. FASOM projects that the least cost options 

for meeting the cellulosic ethanol mandate will be primarily residue based feedstocks. However, 

this assumption is highly dependent on the assumed densities associated with switchgrass 

production, as well as the sustainable removal rates associated with residue crops. If more mass 

DDDDDDDDDDD FASOM estimates that total planted corn acres increase to 93.8 million acres from the Reference Case 

level of 90.1 million acres in 2017. Total planted acres increases to 92.2 million acres from the Reference Case 

level of 89 million acres in 2022. 

652 
653 

 

is required on the land to prevent erosion or soil carbon loss, there could be insufficient residue 

for cellulosic feedstocks. In addition, there are harvesting, transporting, and storing logistical 

issues that must be overcome before large-scale cellulosic biofuels can be produced, as described 

in Chapter 1. 

One of the primary crop residue feedstocks for cellulosic ethanol production is sugarcane 

bagasse. As demand for cellulosic ethanol increases, sugarcane acres increase by 0.7 millions 

acres (55%) to 1.9 million acres in 2022. In addition, some of the cellulosic ethanol comes from 

switchgrass, which is not produced under the Reference Case. In the scenario analyzed, 2.8 

million acres of switchgrass will be planted by 2022. As mentioned above, FAPRI does not 

explicitly model the production of cellulosic ethanol and the resulting impacts on the agriculture 

sector. For both the Reference Case and the Control Case, we assume 32 million acres would 

remain in the Conservation Reserve Program (CRP). Therefore, some of the new corn, soybean, 

and switchgrass acres may be indirectly coming from former land that is not re-enrolled in the 

program. Figure 5.1-1 shows the change in acres for all crops in the U.S. in 2022. Figure 5.1-2 

shows the production levels of cellulosic feedstocks by region in 2022. 
Figure 5.1-1. 

FASOM Model Estimated Change in 

U.S. Crop Acres Relative to the Reference Case in 2022 

(millions of acres) 

-1.5 

-1.0 

-0.5 

0.0 

0.5 

1.0 

1.5 

2.0 

2.5 

3.0 

3.5 

4.0 

Barley

Corn

Cotton

Wheat

Hay

Oats

Rice

Silage

Sorghum

Soybeans

Sugarbeet

Sugarcane

SwitchGrass

Other

Total 

Millions of Acres 

654 
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655 
656 

Figure 5.1-2. 

Control Case Cellulosic Feedstock Production in the U.S. in 2022 

(thousands of acres) 
This page intentionally left blank. 

657 
658 

 

 

 

 

 

As crop acres increase to meet the additional demand for corn and other crops for biofuel 

production, fertilizer use increases as a result. In 2022, FASOM estimates that nitrogen fertilizer 

use in the U.S. agricultural sector would increase by 897 million pounds, 3.4% over the 

Reference Case level of 26.2 billion pounds, and that phosphorous fertilizer use would increase 

by 496 million pounds, 8.6% higher than the Reference Case level of 5.8 billion pounds. The 

FAPRI model does not provide estimates for fertilizer use. 

Table 5.1-7. 

Change in U.S. Fertilizer Use 

Relative to the Reference Case 

(millions of pounds) 

Fertilizer Change %Change 

Nitrogen 897 3.4% 

Phosphorous 496 8.6% 

Impact on U.S. Farm Income 

The increase in renewable fuel production provides a significant increase in net farm 

income to the U.S. agricultural and livestock sector. FASOM predicts that net U.S. farm income 

would increase by $7.1 billion dollars (10.6%) in 2022 relative to the AEO 2007 Reference Case. 

Impact on U.S. Food Prices 

Due to higher commodity prices, FASOM estimates that U.S. food costsEEEEEEEEEEE 

would increase by $10 per person per year by 2022, relative to the Reference Case.FFFFFFFFFFF 

Total effective farm gate food costs would increase by $3.3 billion (0.2%) in 2022.GGGGGGGGGGG 

To put these changes in perspective, average U.S. per capita food expenditures in 2007 were 

$3,778 or approximately 10% of personal disposable income. The total amount spent on food in 

the U.S. in 2007 was $1.14 trillion dollars.HHHHHHHHHHH 

5.1.5 Economic Impacts – Domestic – Sensitivities 

EEEEEEEEEEE FASOM does not calculate changes in price to the consumer directly. The proxy for aggregate food 

price change is an indexed value of all food prices at the farm gate. It should be noted, however, that according to 

USDA, approximately 80 percent of consumer food expenditures are a result of handling after it leaves the farm 

(e.g., processing, packaging, storage, marketing, and distribution). These costs consist of a complex set of variables, 

and do not necessarily change in proportion to an increase in farm gate costs. In fact, these intermediate steps can 

absorb price increases to some extent, suggesting that only a portion of farm gate price changes are typically 

reflected at the retail level. See http://www.ers.usda.gov/publications/foodreview/septdec00/FRsept00e.pdf. FFFFFFFFFFF These estimates are based on U.S. Census population projections of 318 million people in 2017 and 330 

million people in 2022. See http://www.census.gov/population/www/projections/natsum.html. GGGGGGGGGGG Farm Gate food prices refer to the prices that farmers are paid for their commodities. HHHHHHHHHHH See www.ers.usda.gov/Briefing/CPIFoodAndExpenditures/Data/table15.htm. 
 

In the impact analysis volumes of the RFS2 volumes, a number of key assumptions were 

set in both in the Reference Case and the Control Case. Namely, energy prices in both cases are 

from the AEO 08 Reference Case,IIIIIIIIIII national average corn yields in 2022 reached 183 

bu/acre, and the number of acres enrolled in CRP is 32 million acres in 2022. In order to 

demonstrate their influence, the FASOM model was used to analyze variations on these key 

assumptions and observe the impacts on corn prices, harvested acres, and exports. With each 

sensitivity run, only one variable is changed, such as energy prices, corn yields, or acres in CRP, 

for both the Reference Case and the Control Case. The impact of the RFS2 volumes is observed 

under each set of new circumstances. In the original analysis, U.S. corn prices increase by 

$0.15/bu, 4.6%, to $3.34/bu; U.S. harvested corn acres increase by 3.2 million acres, 3.9%, to 

86.6 million acres; and U.S. corn exports decrease by 263 million bushels, -9.9%, to 2.4 billion 

bushels in 2022. 

The Reference Case and the Control Case contain energy prices from the AEO 08 

Reference Case, in which gasoline prices are approximately $2.36 per gallon in 2022. As a 

sensitivity, the FASOM model ran a “high price case”, where all other variables remaining equal, 

energy prices are from the AEO 08 High Price Case,JJJJJJJJJJJ in which gasoline prices are 

approximately $3.28 per gallon in 2022. Higher energy prices lead to increased costs for crop 

production, leading to relatively higher prices. Under these circumstances, U.S. corn prices 

increase by approximately $0.15/bu, 4.6%, to $3.42/bu in 2022. Additionally, harvested U.S. 

corn acres increase by 2.7 million acres, 3.3%, to 85.3 million acres; and U.S. corn exports 

decrease by 278 million bushels (-11%) to 2.3 billion bushels in 2022. 

Another key assumption examined here is the estimated technological rate of progress for 

corn yields. Different projected corn yield values in a given year have large implications for 

domestic agricultural land use and the export commodity market. If yields are relatively low, 

more land is required to supply the amount of corn demanded for biofuel production, which 

would also lead to relatively lower corn exports and higher corn prices. Conversely, if yields are 

relatively high, less land is required to meet the demand for corn ethanol, corn exports would be 

relatively higher, and corn prices would be relatively lower. In the original analysis, national 

average corn yields are approximately 183 bu/acre in 2022. In the “low yield case”, corn yields 

are equal to 163 bu/acre in 2022. Under this scenario, implementation of the RFS2 volumes 

would lead to U.S. corn prices increasing by $0.34/bu (9.8%) to $3.84/bu in 2022. Also, U.S. 

corn acres increase by 1.1 million acres (1.3%) to 90.1 million acres and U.S. corn exports 

decrease by 425 million bushels (-20%) to 1.7 billion bushels in 2022. In the “high yield case”, 

corn yields are equal to 208 bu/acre in 2022. Under these circumstances, implementation of the 

RFS2 volumes would lead to and increase of U.S. corn prices by $0.07/bu (2.6%) to $2.95/bu, an 

increase in U.S. corn acres of 1.4 million acres (1.7%) to 82 million acres, and a decrease of U.S. 

corn exports of 493 million bushels (-13.3%) to 3.2 billion bushels. 

The final key assumption varied here regards the number of acres enrolled in CRP. In the 

original analysis, the number of acres in CRP were limited with a minimum of 32 million acres 

in accordance with the 2008 Farm Bill. As a sensitivity analysis, a scenario was examined where 

there is no minimum restriction imposed in the CRP program, and farmers may produce crops on 

IIIIIIIIIII See: http://www.eia.doe.gov/oiaf/aeo/aeoref_tab.html JJJJJJJJJJJ See: http://www.eia.doe.gov/oiaf/aeo/aeohighprice.html 

659 
 

these acres if it proves to be economically beneficial. With no limits on CRP acreage and more 

land becomes available for crop production, corn prices will be relatively lower. Under these 

circumstances, implementation of the RFS2 volumes would result in an increase in U.S. corn 

prices of $0.12/bu (3.7%) to $3.25/bu, an increase in U.S. corn acres of 2.6 million acres (3%) to 

87.7 million acres, and a decrease of 299 million bushels of corn exports (-10.5%) to 2.5 billion 

bushels in 2022. 

Figure 5.1-3. 

Change in U.S. Corn Prices in 2022 

(2006$ per bushel) 

Change in U.S. Corn Price in 2022 

Relative to the Reference Case 

$0.00 

$0.05 

$0.10 

$0.15 

$0.20 

$0.25 

$0.30 

$0.35 

$0.40 

Control Case AEO 08 High Price 

Case 

Corn Yield - Low Case Corn Yield - High Case CRP - All Can Revert 

2006$ per bushel 

660 
 

Figure 5.1-4. 

Change in U.S. Harvested Corn Acres in 2022
 

(millions of acres) 

Change in U.S. Harvested Corn Acres in 2022 

Relative to the Reference Case 

0.0 

0.5 

1.0 

1.5 

2.0 

2.5 

3.0 

3.5 

Control Case AEO 08 High Price 

Case 

Corn Yield - Low Case Corn Yield - High Case CRP - All Can Revert 

Millions of Acres 

Figure 5.1-5. 

Change in U.S. Corn Exports in 2022 

(billions of bushels)
 

Change in U.S. Corn Exports in 2022 

Relative to the Reference Case 

-0.6 

-0.5 

-0.4 

-0.3 

-0.2 

-0.1 

0.0 

Control Case 

AEO 08 High Price 

Case Corn Yield - Low Case Corn Yield - High Case CRP - All Can Revert 

Billions of Bushels 

661 
5.1.6 Economic Impacts - International 

The FAPRI models are utilized to assess the international impacts on trade, land use, and 

food consumption as a result of the RFS2 biofuels requirement in the U.S. In the FAPRI models, 

links between the U.S. and international models are made through commodity prices and net 

trade equations. In general, for each commodity sector, the economic relationship that quantity 

supplied equals quantity demanded is achieved through a market-clearing price for the 

commodity. In other countries domestic prices are modeled as a function of the world price 

using a price transmission equation. Since econometric models for each sector can be linked, 

changes in one commodity sector will impact the other sectors. 

The model for each commodity consists of a number of countries/regions, including a 

rest-of-the-world aggregate to close the model. The models specify behavioral equations for 

production, use, stocks, and trade between countries/regions. The models solve for representative 

world prices by equating excess supply and demand across countries. Using price transmission 

equations, the domestic price for each country is linked with the representative world price 

through exchange rates. It is through changes in world prices that change in worldwide 

commodity production and trade is determined. 

Global Commodity Price Changes 

As the RFS2 proposal alters various commodity production and prices in the U.S., it 

follows that the world price for these same commodities, and therefore their production and 

trade, are affected as well. As the U.S. increases its use of corn for ethanol production, the 

FAPRI model estimates that it reduces corn net exports (as mentioned above), which results in 

the world price of corn increasing by $0.26/bu (7.5%) to $3.69/bu in 2022. Similarly, the 

decrease in U.S. net exports of soybeans has a corresponding effect on the world price of 

soybeans, which increases by $0.52/bu (5.6%) to $9.94/bu in 2022. As a primary feedstock for 

domestic biodiesel production, the U.S. decreases in net exports of soybean oil to satisfy the 

increased demand for biodiesel, causing world soybean oil prices to increase by $120.93/ton 

(12.2%) to $1,116.43/ton in 2022. 

World biofuel prices are also affected by the RFS2 proposal. As mentioned above in 

section 5.1.2, the U.S. satisfies a portion of the increased demand for biofuels by increasing its 

imports of ethanol. The FAPRI model predicts that this increased demand on the world supply 

of ethanol leads to an increase its world price by $0.38/gallon (60.8%) to $1.00/gallon in 2022. 

Though the U.S. does not change it’s level of import or export of biodiesel, which is zero, the 

change in the price of biodiesel feedstocks, such as soybean oil, affects the world price of 

biodiesel, which increases by $0.10/gallon (2.11%) to $4.89/gallon in 2022. 

662 
Table 5.1-8. 

Global Commodity Price Changes in 2022 

(2006$ per unit) 

Commodity Change 

(2006$ per Unit) 

% Change 

Corn $0.26/bushel 7.5% 

Soybeans $0.52/bushel 5.6% 

Soybean Oil $120.93/ton 12.2% 

Ethanol $0.38/gallon 60.8% 

Biodiesel $0.10/gallon 2.11% 

World Trade in Biofuels 

As the U.S. increases its demand for increased use of biofuels, this will also lead to 

impacts on the world trade market for biofuels. With the RFS2 proposal, the U.S. will increase 

its imports of ethanol. EPA estimates that in 2022, the U.S. will increase net imports of ethanol 

by 2.5 billion gallons (388%) to 3.1 billion gallons. In response, the only net exporter of ethanol 

in the world, Brazil, increases production of ethanol and increases its net exports by 2.2 billion 

gallons (65.9%) to 5.4 billion gallons. However, since the U.S. demand for ethanol imports 

exceeds the increase in Brazilian net exports, other countries see a reduction in their net imports 

of ethanol. China decreases its net imports by 96 million gallons (-60.3%) to 64 million gallons, 

Canada decreases its net imports by 31 million gallons (-7.1%) to 412 million gallons, and the 

European Union decreases its net imports of ethanol by 40 million gallons (-7.4%) to 507 million 

gallons in 2022. Additionally, India decreases its net imports of ethanol by 57 million gallons (­

12.7%) to 388 million gallons, Japan decreases net imports of ethanol by 10 million gallons (­

2.6%) to 365 million gallons, and South Korea decreases net imports of ethanol by 5 million 

gallons (-2.9%) to 175 million gallons. The rest of the world decreases net imports of ethanol by 

2 million gallons (-0.4%) to 477 million gallons in 2022. 

663 
Figure 5.1-6. 

Ethanol Net Exports by Country in 2022 

(billions of gallons)
 

Ethanol Net Exports in 2022 

-4 

-3 

-2 

-1 

0 

1 

2 

3 

4 

5 

6 

BrazilChina

Canada

European Union

India

Japan

South Korea

United States

Rest of World

Total Net

Exports 

Billions of Gallons 

Reference Case Control Case 

Though the U.S. does not import any biodiesel either in the AEO 2007 Reference Case 

nor the EISA Control Case, the decrease in soybean oil exports from the U.S. of 2.9 billion 

pounds (-27%) to 7.9 billion pounds, as estimated by the FAPRI model has implications in the 

biodiesel trade market. The decrease in U.S. soybean oil exports leads to an increase in the 

world price of soybean oil, causing other countries to increase their net exports of soybean oil. 

Argentina and Brazil increase their soybean oil net exports by 354 million pounds and 676 

million pounds, respectively, in 2022. Since the world price of soybean oil increases at a much 

larger rate (12.2%) than the world price of biodiesel (2.1%) due to the RFS2 proposal, it 

becomes relatively more profitable to increase net exports of soybean oil for major producers. 

This results in less soybean oil being used in the production of biodiesel and therefore a decrease 

in biodiesel net exports. In 2022, Argentina decreases their biodiesel net exports by 8 million 

gallons (-3.0%) to 269 million gallons, and Brazil decreases their biodiesel net exports by 19 

million gallons (-7.3%) to 240 million gallons. In response, the EU reduces their net imports of 

biodiesel by 26 million gallons (-5.2%) to 479 million gallons and Japan reduces its net imports 

of biodiesel by 1 million gallons (-1.3%). 

664 
Figure 5.1-7. 

Biodiesel Net Exports by Country in 2022 

(billions of gallons)
 

Biodiesel Net Exports in 2022 

-0.6 

-0.5 

-0.4 

-0.3 

-0.2 

-0.1 

0.0 

0.1 

0.2 

0.3 

0.4

 Argentina

 Brazil

 Indonesia

 Malaysia

 United States

 European

Union

 Japan

 ROW

Total Net

Exports 

Billions of Gallons 

Reference Case Control Case 

International Land Use Change 

Changes to the global commodity trade markets and world commodity prices result in 

changes in international land use. The FAPRI model provides international change in crop acres 

as a result of the RFS2 proposal. Brazil has the largest positive change in crop acres in 2022, 

followed by the U.S., Nigeria, India, Paraguay, and China. As the U.S. increases its net imports 

of ethanol by 2.5 billion gallons in 2022, the major supplier of this increase in ethanol is Brazil 

which produces ethanol from sugarcane. The FAPRI model estimates that Brazil crop acres 

increase by 3.1 million acres (2.0%) to 153.6 million acres relative to the Reference Case. The 

major crop contributing to this increase is sugarcane, which increases by 2.0 million acres (8.7%) 

in 2022 to 24.4 million acres. Total U.S. acres increase by 2.3 million acres (1.0%) in 2022 to 

232.6 million acres. The major crop contributing to this increase is corn, which increases by 3.7 

million acres (4.2%) to 90 million acres in order to satisfy the increased demand for corn ethanol. 

Though Brazil and the U.S. increase their crop acres to meet the increased demand for biofuel, 

other countries, such as Nigeria and India, respond by increasing their major food crops: 

sorghum and rice, respectively. Nigeria has an increase in crop acres of 1.5 million acres (5.9%) 

to 27.3 million acres in 2022. This increase is entirely due to an increase in sorghum acres, 

which represents a 7.6% increase in sorghum acres in 2022. India’s total crop acres increase by 

1.0 million acres (0.3%) to 326 million acres in 2022. Rice is the largest contributor to this 

increase, rising by 0.4 million acres (0.4%) in 2022, though soybeans, sorghum, and corn also 

665 
 

increase by 0.25, 0.31, and 0.21 million acres, respectively. Total crop acres in Paraguay 

increase by 0.8 million acres (6.9%) to 12 million acres. This increase is entirely due to the 

increase of soybean acres, which rise 6.9% in 2022. China’s total crop acres increase by 0.4 

million acres (0.2%) to 257.8 million acres in 2022. The crop with the largest increase is corn, 

which rises by 0.7 million acres (1.0%) 70.4 million acres in 2022. 

Figure 5.1-8. 

Change in World Crop Acres By Country in 2022 

(millions of acres)
 

14 

Change in World Crop Acres in 2022 

0 

2 

4 

6 

8 

10 

12 

Brazil US Entire World 

Millions of Acres 

Nigeria India Paraguay China Rest of 

World 

International Crop Yields 

When analyzing the change in international crop acres in response to the RFS2 proposal, 

it is important to note that different countries have different yields for each crop. The FAPRI 

model bases each country’s crop yield on historical trends and projects this technical rate of 

progress into the future. Similar to the FASOM model, the yield for each crop is the same in 

both the Reference Case and the Control Case in that neither model has price induced crop 

yields. Table 5.1-9 lists the production and yields for the top four producers of corn and 

soybeans in the Control Case in 2022. 

666 
 

 

Table 5.1-9. 

Corn and Soybean Control Case Production and Yields for the 

Top Four Producing Countries in 2022
 

Corn 

Country Production 

(billions of bushels) 

Yield 

(bushels/acre) 

U.S. 16.6 184 

China 7.0 99 

Brazil 2.5 68 

EU 2.3 111 

Soybeans 

Country Production 

(billions of bushels) 

Yield 

(bushels/acre) 

Brazil 3.8 50 

U.S. 3.4 49 

Argentina 2.4 48 

China 0.6 30 

World Food Consumption 

The RFS2 mandate results in higher international commodity prices, which would impact 

world food consumption.KKKKKKKKKKK As mentioned above, with the RFS2 proposal world corn 

prices would increase by 7.5% to $3.69 per bushel in 2022, relative to the Reference Case. The 

impact on world soybean prices is somewhat smaller, increasing 5.6% to $9.94 per bushel in 

2022. Since major agricultural commodity prices increase globally, it is anticipated that world 

consumption of food would decrease. The FAPRI model indicates that world consumption of 

corn for food falls by 1.1 million metric tons (-0.5%) in 2022 relative to the Reference Case. 

Similarly, the FAPRI model estimates that world consumption of wheat for food would decrease 

by 0.6 million metric tons (-0.1%) in 2022. World consumption of oil for food (e.g., vegetable 

oils) decreases by 1.8 million metric tons (-1.4%) by 2022. The model also estimates a small 

change in world meat consumption, decreasing by 0.3 million metric tons (-0.1%) in 2022. 

When considering all the food uses included in the model, world food consumption decreases by 

0.9 million metric tons (-0.04%) by 2022. While FAPRI provides estimates of changes in world 

food consumption, estimating effects on global nutrition is beyond the scope of this analysis. 

KKKKKKKKKKK The food commodities included in the FAPRI model include corn, wheat, sorghum, barley, soybeans, 

sugar, peanuts, oils, beef, pork, poultry, and dairy products. 

667 
 

 

 

Table 5.1-10. 

Change in World Food Consumption Relative to the Reference Case 

(millions of metric tons)
 

Category Change % Change 

Corn -1.1 -0.5% 

Wheat -0.6 -0.1% 

Vegetable Oils -1.8 -1.4% 

Meat -0.3 -0.1% 

Total Food -0.9 -0.4% 

5.2 Petroleum and Energy Security Impacts 

5.2.1 Impact on U.S. Petroleum Imports 

In 2007, U.S. petroleum imports represented 19.5 percent of total U.S. imports of all 

goods and services.LLLLLLLLLLL In 2005, the United States imported almost 60 percent of the 

petroleum it consumed. This compares roughly to 35 percent of petroleum from imports in 

1975.MMMMMMMMMMM Transportation accounts for 70 percent of the U.S. petroleum 

consumption. It is clear that petroleum imports have a significant impact on the U.S. economy. 

Diversifying transportation fuels in the U.S. is expected to lower U.S. petroleum imports. To 

estimate the impacts of this proposal on the U.S.’s dependence on imported oil, we calculate 

avoided U.S. expenditures on petroleum imports. 

EPA analyzed two approaches to estimate the reductions in U.S. petroleum imports. The 

first approach utilizes a model of the U.S. energy sector, the National Energy Modeling System 

(NEMS), to quantify the type and volume of reduced petroleum imports based on supply and 

demand for specific fuels in a given year. The National Energy Modeling System (NEMS) is a 

computer-based, energy-economy modeling system of U.S. energy markets through the 2030 

time period. NEMS projects U.S. production, imports, conversion, consumption, and prices of 

energy; subject to assumptions on world energy markets, resource availability and costs, 

behavioral and technological choice criteria, cost and performance characteristics of energy 

technologies, and demographics. NEMS is designed and implemented by the Energy 

Information Administration (EIA) of the U.S. Department of Energy (DOE). For this analysis, 

the NEMS model was run with the 2007 AEO levels of biofuels in the reference case compared 

with the biofuel volume RFS2 requirements. 

Considering the regional nature of U.S. imports of petroleum imports, a second approach 

was utilized as well to estimate the impacts of the RFS2 proposal on U.S. oil imports. This 

approach is labeled “Regional Gasoline Market” approach. This approach makes the assumption 

that one half of the ethanol market is in the Northeast portion of the U.S., which also comprises 

LLLLLLLLLLL Bureau of Economic Affairs: “U.S. International Transactions, Fourth Quarter of 2007”
 

by Elena L. Nguyen and Jessica Melton Hanson, April 2008. 

MMMMMMMMMMM Davis, Stacy C.; Diegel, Susan W., Transportation Energy Data Book: 25th Edition, Oak Ridge 

National Laboratory, U.S. Department of Energy, ORNL-6974, 2006. 

668 
about half of the nation’s gasoline demand. For this analysis, it is estimated that ethanol would 

displace imported gasoline or gasoline blend stocks in the Northeast, but not elsewhere in the 

country. Therefore, to derive the portion of the new renewable fuels which would offset U.S. 

petroleum imports (and not impact domestic refinery production), we multiplied the total volume 

of petroleum fuel displaced by 50 percent to represent that portion of the ethanol which would be 

used in the Northeast, and 50 percent again to only account for that which would offset imports. 

The rest of the ethanol, including half of the ethanol presumed to be used in the Northeast, is 

presumed to offset domestic gasoline production, which ultimately offsets crude oil inputs at 

refineries. Biodiesel and renewable diesel are presumed to offset domestic diesel fuel 

production. 

The results shown in Table 5.2-1-1 below reflect the net lifecycle reductions in U.S. oil 

imports projected by NEMS. The net lifecycle reductions include the upstream petroleum used 

to produce renewable fuels, gasoline and diesel, as well as the petroleum directly used by endusers. 

Table 5.2-1-1. 

Net Reductions in Oil Imports in 2022 

(Using the NEMS Model) 

(millions of barrels per day)
 

Category of Reduction 2022 

Imports of Finished Petroleum 

Products 0.823 

Imports of Crude Oil (0.007) 

Total Reduction 0.815 

Percent Reduction 6.15 

The NEMS model projects that for the year 2022 all of the reduction in petroleum 

imports comes out of finished petroleum products. NEMS projects that 91 percent of the 

reductions in 2022 come from reduced net imports of crude oil and finished petroleum products 

(as compared to a 9 percent reduction in domestic U.S. production). 

The results shown in Table 5.2.1-2 below reflect the net lifecycle reductions in U.S. oil 

imports projected by the use of the Regional Gasoline Market approach detailed above. 

Table 5.2.1-2. 

Net Reductions in Oil Imports in 2022 

(Using Regional Gasoline Market Approach) 

(millions of barrels per day)
 

Category of Reduction 2022 

Imports of Finished Petroleum Products 0.250 

Imports of Crude Oil 0.637 

Total Reduction 0.887 

Percent Reduction 6.17% 

669 
The Regional Gasoline Market approach projects that for 2022, 72% of the petroleum 

supply displacement (on a volume basis) comes out of reduced net crude oil imports, and 28% 

out of net imports of finished petroleum products (excluding biofuels). Using our two 

approaches for projecting total petroleum import reductions (the NEMS and the Regional 

Gasoline Market), we estimate that petroleum product imports will fall by between 0.815 to 

0.887 million barrels per day in 2022 as a result of the RFS2 proposal. 

Using the NEMS model, we also calculated the change in expenditures in both U.S. 

petroleum and ethanol imports with the RFS2 proposal and compared these with the U.S. trade 

position measured as U.S. net exports of all goods and services economy-wide. Changes in fuel 

expenditures were estimated by multiplying the changes in gasoline, diesel, and ethanol net 

imports by the respective AEO 2008 wholesale gasoline and distillate price forecasts, and 

ethanol price forecasts from the Food and Agricultural Policy Research Institute (FAPRI) for the 

specific analysis years. In Table 5.2.1-3, the net expenditures in reduced petroleum imports and 

increased ethanol imports are compared to the total value of U.S. net exports of goods and 

services for the whole economy for 2022. The U.S. net exports of goods and services estimates 

are taken from Energy Information Administration’s Annual Energy Outlook 2008. We project 

that avoided expenditures on imported petroleum products due to this proposal would be roughly 

$16 billion in 2022. Relative to the 2022 projection, the total avoided expenditures on liquid 

transportation fuels are projected to be $12.4 billion with the RFS2 proposal. 

Table 5.2.1-3. 

Changes in Expenditures on 

Transportation Fuel Net Imports 

(billions of 2006$) 

Category 2022 

AEO Total Net Exports 16 

Expenditures on Net Petroleum 

Imports (15.96) 

Expenditures on Net Ethanol and 

Biodiesel Imports 3.52 

Net Expenditures on 

Transportation Fuel Imports (12.44) 

5.2.2 Background on U.S. Energy Security 

U.S. energy security is broadly defined as protecting the U.S. economy against 

circumstances that threaten significant short- and long-term increases in energy costs. 

Most discussion of U.S. energy security revolves around the topic of the economic costs of U.S. 

dependence on oil imports. The problem is that the U.S. relies on sources of imported oil from 

potentially unfriendly and unstable sources. In addition, oil exporters have the ability to raise the 

price of oil by exerting monopoly power through the formation of a cartel, the Organization of 

Petroleum Exporting Countries (OPEC). Finally, these factors contribute to the vulnerability of 

the U.S. economy to episodic oil supply shocks and price spikes. In 2005, U.S. imports of crude 

oil were $232 billion (see Figure 5.2.2-1). 

670 
 

 

 

 

Figure 5.2.2-1. U.S. Expenditures on Crude Oil 

Source: Annual Energy Review 2006 and International Energy Review 2004. Year 2005 values are preliminary. 

One effect of the RFS proposal is that it promotes diversification of transportation fuels 

in the U.S. The result is that it reduces U.S. oil imports, which reduces both financial and 

strategic risks associated with a potential disruption in supply or a spike in the cost of a particular 

energy source. This reduction in risks is a measure of improved U.S. energy security. For the 

RFS2 proposal an “oil premium” approach is utilized to identify those energy-security related 

impacts which are not reflected in the market price of oil, and which are expected to change in 

response to an incremental change in the level of U.S. oil imports. 

5.2.3 Methodology Used to Estimate U.S. Energy Security Benefits 

In order to understand the energy security implications of reducing U.S. oil imports, EPA 

has worked with Oak Ridge National Laboratory (ORNL), which has developed approaches for 

evaluating the social costs and energy security implications of oil use. In a new study entitled 

"The Energy Security Benefits of Reduced Oil Use, 2006-2015," produced for the Renewable 

Fuel Standard (RFS) Rule of 2007, ORNL has updated and applied the method used in the 1997 

report "Oil Imports: An Assessment of Benefits and Costs", by Leiby, Jones, Curlee and 

Lee.NNNNNNNNNNN,OOOOOOOOOOO A draft of this updated report was included as part of the record 

NNNNNNNNNNN Leiby, Paul N., Donald W. Jones, T. Randall Curlee, and Russell Lee, Oil Imports: An Assessment of 

Benefits and Costs, ORNL-6851, Oak Ridge National Laboratory, November, 1997. OOOOOOOOOOO The 1997 ORNL paper was cited and its results used in DOT/NHTSA’s rules establishing CAFE 

standards for 2008 through 2011 model year light trucks. See DOT/NHTSA, Final Regulatory Impacts Analysis: 

Corporate Average Fuel Economy and CAFE Reform MY 2008-2011, March 2006. 

671 
 

in the final RFS rulemaking, and the public was invited to analyze this Report and provide other 

perspectives for best quantifying energy security benefits. Since promulgation of the RFS rule, 

EPA has worked with ORNL to finalize the report and quantify the energy security benefits 

associated with a reduction in imported oil. In addition, the Report has been the subject to an 

external peer review by six experts from outside the U.S. government.PPPPPPPPPPP Updating the 

ORNL methodology to incorporate the comments from the Peer Reviewers, ORNL estimates 

that the total energy security benefits associated with a reduction of imported oil is $12.38/barrel, 

with a range of $6.88 - $18.52/barrel of imported oil reduced. Highlights of the analysis are 

shown below. 

The approach developed by ORNL estimates the incremental benefits to society, in 

dollars per barrel, of reducing U.S. oil imports, called “oil premium." Since the 1997 publication 

of this report, changes in oil market conditions, both current and projected, suggest that the 

magnitude of the oil premium has changed. Significant driving factors that have been revised 

include: projected world oil prices, current and anticipated levels of OPEC production, U.S. 

import levels, the estimated responsiveness of regional oil supplies and demands to price, and the 

likelihood of oil supply disruptions (see Table 5.2.3-1). For this analysis, oil prices from the 

EIA's AEO 2007 were used. Using the "oil premium" approach, estimates of benefits of 

improved U.S. energy security from reduced U.S. oil imports due to increased availability and 

use of other transportation fuels are calculated. 

Table 5.2.3-1. Market and Parameter Changes Influencing Premium Estimate 

Source: Leiby, Paul N. "The Energy Security Benefits of Reduced Oil Use, 2006-2015", Oak Ridge 

National Laboratory ORNL/TM-2007/028, July 2007. 

PPPPPPPPPPPLeiby, Paul N. “Estimating the Energy Security Benefits of Reduced U.S. Oil Imports: Final Report”, 

ORNL/TM-2007/028, Oak Ridge National Laboratory, March 6, 2008. 

672 
In conducting this analysis, ORNL considered the full economic cost of importing 

petroleum into the U.S. The full economic cost of importing petroleum into the U.S. is defined 

for this analysis to include two components in addition to the purchase price of petroleum itself. 

These are: (1) the higher costs for oil imports resulting from the effect of U.S. import demand on 

the world oil price and OPEC market power (i.e., the "demand" or "monoposony" costs); and (2) 

the risk of reductions in U.S. economic output and disruption of the U.S. economy caused by 

sudden disruptions in the supply of imported oil to the U.S. (i.e., macroeconomic 

disruption/adjustment costs). 

5.2.3.1 Effect of Oil Use on Long-Run Oil Price, U.S. Import Costs, and Economic Output 

The first component of the full economic costs of importing petroleum into the U.S. 

follows from the effect of U.S. import demand on the world oil price over the long-run. Because 

the U.S. is a sufficiently large purchaser of foreign oil supplies, its purchases can affect the world 

oil price. This monopsony power means that increases in U.S. petroleum demand can cause the 

world price of crude oil to rise, and conversely, that reduced U.S. petroleum demand can reduce 

the world price of crude oil. Thus, one benefit of decreasing U.S. oil purchases, due to the 

increased availability and use of other transportation fuels, is the potential decrease in the crude 

oil price paid for all crude oil purchased. 

The demand or monopsony effect can be readily illustrated with an example. If the U.S. 

imports 10 million barrels per day at a world oil price of $50 per barrel, its total daily bill for oil 

imports is $500 million. If a decrease in U.S. imports to 9 million barrels per day causes the 

world oil price to drop to $49 per barrel, the daily U.S. oil import bill drops to $441 million (9 

million barrels times $49 per barrel). While the world oil price only declines $1, the resulting 

decrease in oil purchase payments of $59 million per day ($500 million minus $441 million) is 

equivalent to an incremental benefit of $59 per barrel of oil imports reduced, or $10 more than 

the newly-decreased world price of $49 per barrel. This additional $10 per barrel “import cost 

premium” represents the incremental external benefits to U.S. society as a whole for avoided 

import costs beyond the price paid oil purchases. This additional benefit arises only to the extent 

that reduction in U.S. oil imports affects the world oil price. ORNL estimates this component of 

the energy security benefit to be $7.65/barrel, with a range of $2.86 – $13.53/barel of imported 

oil reduced. 

5.2.3.2 Short-Run Disruption Premium from Expected Costs of Sudden Supply Disruptions 

The second component of the oil import premium, the “disruption premium", arises from 

the effect of oil imports on the expected cost of disruptions. A sudden increase in oil prices 

triggered by a disruption in world oil supplies has two main effects: (1) it increases the costs of 

imports in the short run, further expanding the transfer of U.S. wealth to foreign producers, and 

(2) it can lead to macroeconomic contraction, dislocation and GDP losses. ORNL estimates the 

composite estimate of these two factors that comprise the “disruption premium” to be 

$4.74/barrel, with a range of $2.17 – $7.64/barrel of imported oil reduced. 

5.2.3.2.1 Higher Costs of Oil Imports and Wealth Transfer during Shocks 

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During oil price shocks, the higher price of imported oil causes increased payments for 

imports and a transfer of wealth from U.S. society to oil exporters. This increased claim on U.S. 

economic output is a loss to the U.S. that is separate from and additional to any reduction in 

economic output due to the shock. The increased wealth transfer during shocks is counted as a 

loss to the degree that the expected price increase is not anticipated and internalized by oil 

consumers. 

5.2.3.2.2 Macroeconomic Costs: Potential Output Loss and Dislocation/Adjustment Costs 

Macroeconomic losses during price shocks reflect both aggregate output losses and 

allocative losses. The former are a reduction in the level of output that the U.S. economy can 

produce fully using its available resources; and the latter stem from temporary dislocation and 

underutilization of available resources due to the shock, such as labor unemployment and idle 

plant capacity. The aggregate output effect, a reduction in “potential” economic output, will last 

so long as the price is elevated. It depends on the extent and duration of any disruption in the 

world supply of oil, since these factors determine the magnitude of the resulting increase in 

prices for petroleum products, as well as whether and how rapidly these prices return to their predisruption levels. 

In addition to the aggregate contraction, there are “allocative” or “adjustment” costs 

associated with dislocated energy markets. Because supply disruptions and resulting price 

increases occur suddenly, empirical evidence shows they also impose additional costs on 

businesses and households which must adjust their use of petroleum and other productive factors 

more rapidly than if the same price increase had occurred gradually. Dislocational effects 

include the unemployment of workers and other resources during the time needed for their 

intersectoral or interregional reallocation, and pauses in capital investment due to uncertainty. 

These adjustments temporarily reduce the level of economic output that can be achieved even 

below the “potential” output level that would ultimately be reached once the economy’s 

adaptation to higher petroleum prices was complete. The additional costs imposed on businesses 

and households for making these adjustments reflect their limited ability to adjust prices, output 

levels, and their use of energy, labor and other inputs quickly and smoothly in response to rapid 

changes in prices for petroleum products. 

Since future disruptions in foreign oil supplies are an uncertain prospect, each of the 

disruption cost components must be weighted by the probability that the supply of petroleum to 

the U.S. will actually be disrupted. Thus, the “expected value” of these costs – the product of the 

probability that a supply disruption will occur and the sum of costs from reduced economic 

output and the economy’s abrupt adjustment to sharply higher petroleum prices – is the relevant 

measure of their magnitude. Further, when assessing the energy security value of a policy to 

reduce oil use, it is only the change in the expected costs of disruption that results from the 

policy that is relevant. The expected costs of disruption may change from lowering the normal 

(pre-disruption) level of domestic petroleum use and imports, from any induced alteration in the 

likelihood or size of disruption, or from altering the short-run flexibility (elasticity) of petroleum 

use. 

674 
In summary, the steps needed to calculate the disruption or security premium are first, 

determine the likelihood of an oil supply disruption in the future; second, assess the likely 

impacts of a potential oil supply disruption on the world oil price; third, assess the impact of the 

oil price shock on the U.S. economy (in terms of import costs and macroeconomic losses); and 

fourth, determine how these costs change with oil imports. The value of price spike costs 

avoided by reducing oil imports becomes the oil security portion of the premium. ORNL 

estimates the composite value that comprises the “disruption premium” to be $4.74/barrel, with a 

range of $2.17 – $7.64/barrel of imported oil reduced. 

We recognize that our current energy security analysis does not take into account riskshifting that might occur as the U.S. reduces its dependency on petroleum by increasing its use of 

biofuels. For example, our analysis did not take into account other energy security implications 

associated with biofuels, such as possible supply disruptions of corn-based ethanol. Between the 

proposal and the final rulemaking, EPA will attempt to broaden our energy security analysis to 

incorporate estimates of overall motor fuel supply and demand flexibility and reliability, and 

impacts of possible agricultural sector market disruptions (for example, a drought) for 

presentation in the final rule. The expanded analysis will also consider how the use of biofuels 

can alter short and long run elasticity (flexibility) in the motor fuel market, with implications for 

robustness of the fuel system in the face of diverse supply shocks. As part of this analysis, the 

Agency plans on analyzing those factors that can cause shifts in the prices of biofuels, and the 

impact these factors have on the energy security estimate. 

5.2.3.3 Costs of Existing U.S. Energy Security Policies 

The last often-identified component of the full economic costs of U.S. oil imports is the 

costs to the U.S. taxpayers of existing U.S. energy security policies. The two primary examples 

are maintaining a military presence to help secure a stable oil supply from potentially vulnerable 

regions of the world and maintaining the Strategic Petroleum Reserve (SPR). The SPR is the 

largest stockpile of government-owned emergency crude oil in the world. Established in the 

aftermath of the 1973-74 oil embargo, the SPR provides the U.S. a response option should a 

disruption in commercial oil supplies threaten the U.S. economy. It also allows the U.S. to meet 

part of its International Energy Agency obligation to maintain emergency oil stocks, and it 

provides a national defense fuel reserve. 

U.S. military costs are excluded from the analysis performed by ORNL because their 

attribution to particular missions or activities is difficult. Most military forces serve a broad 

range of security and foreign policy objectives. Attempts to attribute some share of U.S. military 

costs to oil imports are further challenged by the need to estimate how those costs might vary 

with incremental variations in U.S. oil imports. Similarly, while the costs for building and 

maintaining the SPR are more clearly related to U.S. oil use and imports, historically these costs 

have not varied in response to changes in U.S. oil import levels. Thus, while SPR is factored 

into the ORNL analysis, the cost of maintaining the SPR is excluded. 

5.2.3.4 Modifications to Analysis Based Upon Peer Reviewer Comments 

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The Agency commissioned ORNL to conduct a number of sensitivity analyses to address 

the comments of the Peer Reviewers. Based upon the Peer Reviewer comments, key parameters 

that influence the “oil import” premium were assessed. Since not all the comments were in 

agreement with each other, several ranges of different parameters were developed for the 

analyses. A summary of the results of the analyses are shown in Table 5.2.3-2. 

Three key parameters were varied in order to assess their impacts on the oil import 

premium: (1) the response of OPEC supply, (2) the combined response of non-U.S., non-OPEC 

demand and supply and (3) the GDP response to a change in the world oil as a result of reduced 

U.S. oil imports. The cases in Table 5.2.3-2 used updated supply/demand elasticities for nonU.S./non-OPEC region after considering more recent estimates than those used in 1997 study. 

As a result, the total market responsiveness is greater than previous ORNL estimates. Only 

small changes to the world oil price are anticipated from a substantial reduction in U.S. demand, 

on average, about $0.70/bbl for every million-barrels-per-day reduction in demand. 

In the ORNL framework, OPEC-behavior is treated parametrically, with a wide range of 

possible responses represented by a range of supply elasticities. Case One in the Table below 

refers to the AEO 2007 estimates of energy market trends and uses the elasticity parameters from 

the original 1997 ORNL study. In Case Two, the OPEC supply elasticities range for 0.25 to 6 

with a mean elasticity of 1.7. Case Three alters the distribution of the OPEC supply elasticities 

so that the mean elasticity is 2.2 instead of 1.7. With the more elastic OPEC oil supply in Case 

Three, the oil premium is lower. Alternatively, a candidate rule for OPEC strategic response 

behavior, adapted from a lead article on what behavior maximizes OPEC’s long run net revenue 

in a robust way,QQQQQQQQQQQ would have OPEC responding to preserve its worldwide oil market 

share. This is presented as Case Seven. Application of this rule instead of the range of OPEC 

supply responses used leads to an estimate of the oil import premium that is between Case Two 

and Case Three. 

The second key parameter that was varied based upon Peer Reviewer comments was nonOPEC, non-U.S. demand and supply responsiveness to a change in the U.S. oil import demand 

and, hence, the world oil price. In Case Four (see Table below), the mean non-U.S./non-OPEC 

demand and supply elasticities are taken to each be 0.3 in absolute value terms. When combined 

together, the net elasticity of import demand from this region — the non-U.S./non-OPEC region 

is — roughly 1.6. Case Five takes the Case Four assumptions of a more elastic OPEC supply 

behavior and combines those assumptions with the 1.6 net elasticity of import demand for the 

non-U.S./non-OPEC region. Case Six looks at the consequences of a yet higher net elasticity of 

import demand — 2.28 — for the non-U.S./non-OPEC region. The impact on the oil import 

premium is relatively modest. 

Cases Eight and Nine consider a reduced GDP elasticity, the parameter which 

summarizes the sensitivity of GDP to oil price shocks. Several Reviewers suggested a lower 

estimate for this parameter. In response to their comments, a couple of cases were examined 

QQQQQQQQQQQ Gately, Dermot 2004. "OPEC's Incentives for Faster Output Growth," The Energy Journal, 

25(2):75-96, "What Oil Export Levels Should We Expect From OPEC?" The Energy Journal, 28(2):151-173, 2007. 

676 
 

where the GDP elasticity was lowered to 0.032 in comparison to the original ORNL estimate of 

0.0495. As anticipated, this change lowered the oil import premium modestly. For example, 

compared with Case Four where OPEC supply is more elastic, lowering the GDP elasticity with 

respect to the world oil price reduced the oil import premium by roughly $0.40/barrel. This is 

because the GDP-dislocation component is only about one-quarter of the total premium, and 

there are offsetting changes in other components. The last case examined, Case Nine, looks at 

the consequences for the oil import premium with a reduced elasticity of GDP if OPEC attempts 

to maintain its share of the world oil market. 

Clearly there is an unavoidable degree of uncertainty about the magnitude of marginal 

economic costs from the U.S. importation of petroleum, and the size of the oil import premium. 

ORNL sought to reflect this with probabilistic risk analysis over key input factors, guided by the 

available literature and the best judgment of oil market experts. Cases shown in Table 5.2.3-2 

explore some reasonable variations in the ranges of input assumptions and the mean oil premium 

estimates vary in a fairly moderate range between roughly $11 and $15/barrel of imported oil. 

On balance, Case Eight suggested a reasonable and cautious assessment of the premium value to 

ORNL, and is ORNL’s recommended case. This is based on a review of important driving 

factors, the numerical evaluations and simulations over major uncertainties, and taking into 

consideration the many comments and suggestion from the Reviewers, the EPA and other 

Agencies. This recommended case, and the premium range resulting from 90% of the simulated 

outcomes, encompasses a wide array of perspectives and potential market outcomes in response 

to a reduction of U.S. imports. 

This recommended case relies on the most recent available projections of the U.S. and 

world oil market for the next ten years based upon the AEO 2007 Reference Case. OPECbehavior is treated parametrically, with a wide range of possible responses represented by a wide 

range of supply elasticities, from small to quite large. This recommended case recognizes that 

the OPEC response is the most uncertain single element of this analysis. It could vary between 

inelastic defense of output levels, or market share, or could be highly elastic in defense of price, 

probably at the expense of longer run cartel power and discounted net profits. The balance 

between possible elastic and inelastic OPEC response is essentially even over a fairly wide range 

of elasticities. ORNL concluded that this is the best way to estimate OPEC behavior until 

greater progress can be made in synthesizing what insights are available from the evolving 

strategic game-theoretic and empirical research on OPEC behavior, and advancing that research. 

An alternative would have been to use OPEC strategic response behavior to maximize long-run 

net revenue, which may well correspond to market-share preservation behavior (e.g., Case 

Seven), and a somewhat higher premium value. 

Finally, ORNL’s recommended case uses a GDP elasticity range, the parameter which 

summarizes the sensitivity of GDP to oil price shocks, which is reduced compared to earlier 

estimates, and compared to the full range of historically-based estimates. This helps address the 

concerns of those who either question the conclusions of past empirical estimates or expect that 

the impacts of oil shocks may well be declining. EPA requests comment on the ORNL oil 

security methodology outline above and the estimates of the recommended “oil premium” 

estimate developed using the ORNL methodology. 

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Table 5.2.3-2: Summary Results - Oil Import Premium Under Various Cases ($2006/BBL) 

Component Statistic 

1) AEO2007 Base Outlook, 1997 Study Elasticities 

2) AEO2007 Base Outlook, Wider Range of OPEC Supply Elasticities 

3) Case 2 with Revised Wider Range of OPEC Supply Elasticities 

4) Case 2 with Updated NonOPEC Supply/Demand Elasticities 

5) Case 4 plus Revised Wider Range of OPEC Supply Elasticities 

6) Case 4 Variant with Wider, Higher Range of NonU.S./Non-OPEC Supply/Demand Elasticities 

7) Case 6 with Applied Strategic OPEC Behavioral Rule: Maintain Market Share 

8) ReEla

Monopsony Component Mean $5.42 $9.99 $7.95 $7.57 $6.35 $6.27 $9.11 

Range ($3.51 - $7.98) ($3.02 - $20.66) ($3.04 - $18.79) ($2.86 - $13.39) ($2.82 - $12.72) ($2.62 - $11.03) ($6.51 - $12.09) ($2

Disruption Import Costs Mean $2.30 $2.27 $2.28 $1.87 $1.89 $1.88 $1.84 

Range ($0.5 - $4.54) ($0.56 - $4.45) ($0.64 - $4.49) ($0.38 - $3.65) ($0.37 - $3.74) ($0.41 - $3.6) ($0.43 - $3.56) ($

Disruption Dislocation Costs Mean $3.73 $3.60 $3.66 $3.33 $3.36 $3.38 $3.32 

Range ($1.03 - $6.51) ($1.01 - $6.4) ($1.03 - $6.56) ($0.9 - $6.07) ($0.92 - $5.94) ($0.9 - $5.97) ($0.85 - $6.1) ($

Economic Disruption/Adjustment Costs 

Mean $6.03 $5.87 $5.94 $5.20 $5.25 $5.26 $5.16 

Range ($2.86 - $9.75) ($2.86 - $9.49) ($2.82 - $9.59) ($2.46 - $8.46) ($2.53 - $8.39) ($2.51 - $8.69) ($2.47 - $8.51) ($

Total Mid-Point Mean $11.44 $15.86 $13.90 $12.77 $11.59 $11.55 $14.27 

Range ($7.83 - $15.54) ($7.89 - $26.7) ($7.69 - $24.82) ($7.07 - $19.08) ($6.78 - $18.13) ($6.61 - $16.78) ($10.74 - $18.12) ($6

Total Premium, in $/Gallon Mean $0.27 $0.38 $0.33 $0.30 $0.28 $0.28 $0.34 

Price Reduction ($/MMBD) Mean $0.51 $1.01 $0.78 $0.73 $0.60 $0.59 $0.88 

Cases 5) Revise Case 4, with OPEC behavior distributed over elasticities 0 to 6, so that 25% of response is inelastic (< 1.0), mode elasticity is 2.0 (mean elasticity is 2.2 rather than demand is -1.6 for the non-U.S./non-OPEC region. 6) Alternative to Case 4 with expanded (and higher) range of non-U.S. supply/demand elasticities. Elasticity of non-U.S. demand = -0.3 to -0.7, triangular distribution with monon-U.S. supply = 0.2 to 0.6, mode 0.3 and mean 0.367. Implying (mode) net elasticity of import demand from non-U.S./non-OPEC regions more than doubled to mode -1.97) Applied Strategic OPEC Behavioral Rule to Case 6: Maintain Market Share (Gately 2004 paper best strategy). This rule implies that OPEC Supply elasticity matches that result non-U.S. elasticity of import demand ranges from -1.38 to -3.52, with mode -1.92, mean -2.28. Total elasticity of net import supply to U.S. then ranges from 4.8 to 8.6 8) Variant on version Case 4, considered reduced GDP elasticity for future disruptions (range -0.01 to -0.054; midcase value -0.032; mean value is -0.032, reduced from meabehavior treated parametrically. 9) Revise Case 7 (which applied Strategic OPEC Behavioral Rule to Case 6: Maintain Market Share (Gately 2004 paper best strategy)) with reduced GDP elasticity for future 

0.054; midcase value -0.032; mean value is -0.032, reduced from mean value of -0.0495). 2) AEO2007 Base Outlook, with wider range of OPEC supply elasticities, 0.25 to 6.0 and a mean elasticity of 1.76. 3) Revise Case 2, with OPEC behavior distributed over elasticities 0 to 6, so that 25% of response is inelastic (< 1.0), mode elasticity is 2.0 (mean elasticity is 2.2 rather than 4) Updated Case 2 supply/demand elasticities for non-OPEC region with more recent estimates. Elasticity of non-U.S. demand -0.2 to -0.4, with mean and mode -0.3, non-Umean and mode 0.3, implying (mode) net elasticity of import demand from non-U.S./non-OPEC regions ~doubled to -1.6. 

1) Based on AEO2007. Updated oil market outlook from AEO1994 Base Case to AEO2007 Base Case. Among other things, this means average crude price rises from $20match 1997 values. Non-U.S. elasticity of import demand = -0.876, parametric treatment of OPEC response with elasticity 1.0-5.0 (triangular distribution with mode 2.0). 
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5.2.4 Estimates of per Barrel and Total U.S. Energy Security Benefits 

Table 5.2.4-1 below summarizes ORNL’s estimate of the energy security benefits 

associated with the RFS2 proposal. The components of the energy security benefit estimate are 

shown as well as the total U.S. energy security benefits associated with U.S. import reductions 

due to this proposed rule, in Table 5.2.4-2. 

Table 5.2.4-1. 

Energy Security Benefits 

($/barrel in 2006$)
 

Effect Updated ORNL Study 

Monopsony (best estimate) $7.65 

(range) $3.35 – $12.45 

Macroeconomic Disruption (best estimate) $4.74 

(range) $2.64 – $6.96 

Total (best estimate) $12.38 

(range) $7.65 - $17.23 

Total energy security benefits associated with the RFS2 proposal are calculated in Table 

5.2.4-1 for the year 2022. These benefits are derived from the estimated reductions in imports of 

finished petroleum products and crude oil using an energy security premium price of 

$12.38/barrel. 

Table 5.2.4-2. 

Total Energy Security Benefits 

(billions of 2006$) 

Year 2022 

Benefits $3.7 

5.3 Benefits of Reducing GHG Emissions 

5.3.1 Introduction 

The wider use of renewable fuels from the RFS2 proposal results in reductions in 

greenhouse gas (GHG) emissions. Carbon dioxide (CO2) and other GHGs mix well in the 

atmosphere, regardless of the location of the source, with each unit of emissions affecting global 

regional climates; and therefore, influencing regional biophysical and socioeconomic systems. 

The effects of changes in GHG emissions are felt for decades to centuries given the atmospheric 

lifetimes of GHGs. This section provides estimates for the marginal and total benefits that could 

be monetized for the projected GHG emissions reductions of this proposal. EPA requests 

comment on the approach utilized to estimate the GHG benefits associated with the proposal. 

5.3.2 Marginal GHG Benefits Estimates 
 

 

 

The projected net GHG emissions reductions associated with the proposal reflect an 

incremental change to projected total global emissions. Therefore, as shown in Section 2.4, the 

projected global climate signal will be small but discernable (i.e., it incrementally shifts the 

distribution of projected global mean surface temperatures to the left with the upper end shifting 

more than the lower end). Given that the climate response is projected to be marginal relative to 

the baseline climate, it is conceptually appropriate to use an approach that estimates the marginal 

value of changes in climate change impacts over time as an estimate for the monetized marginal 

benefit of the GHG emissions reductions projected for this proposal. The marginal value of 

carbon is equal to the net present value of climate change impacts over hundreds of years of one 

additional net global metric ton of GHGs emitted to the atmosphere at a particular point in time. 

This marginal value (i.e., cost) of carbon is sometimes referred to as the “social cost of carbon.” 

Based on the global implications of GHGs and the economic principles that follow, EPA 

has developed ranges of global marginal benefits estimates, as well as U.S. marginal estimates 

(Table 5.3-1).RRRRRRRRRRR It is important to note at the outset that the estimates are incomplete 

since current methods are only able to reflect a partial accounting of the climate change impacts 

identified by the Intergovernmental Panel on Climate Change (IPCC; discussed more below). 

Also, domestic estimates omit impacts on the United States resulting from climate change 

impacts in other countries (e.g., economic or national security impacts). The global estimates 

were developed from a survey analysis of the peer reviewed literature (i.e., meta analysis). U.S. 

estimates, and a consistent set of global estimates, were developed from a single model and are 

highly preliminary, under evaluation, and likely to be revised. The single model used was the 

Climate Framework for Uncertainty, Negotiation, and Distribution (FUND; discussed below). It 

was necessary to develop the latter set of estimates because the peer reviewed literature does not 

provide regional (i.e., at the U.S. or China level) marginal benefits estimates, and, since the 

regional estimates are not directly comparable to the global meta analysis estimates, it was 

important to have a consistent set of regional and global estimates. Ranges of estimates are 

provided to capture some of the uncertainties associated with modeling climate change impacts. 

The range of estimates is wide due to the uncertainties relating to socio-economic futures, 

climate responsiveness, impacts modeling, as well as the choice of discount rate.SSSSSSSSSSS For 

instance, for 2007 emission reductions and a 2% consumption discount rate the global meta 

analysis estimates range from $-3 to $159/t CO2, while the U.S. estimates range from $0 to $16/t 

CO2. For 2007 emission reductions and a 3% consumption discount rate, the global metaestimates range from $-4 to $106/t CO2, and the U.S. estimates range from $0 to $5/t 

TTTTTTTTTTT CO2. The global meta analysis mean values for 2007 emission reductions are $68 and 

$40/t CO2 for discount rates of 2% and 3% respectively (in 2006 $) while the domestic mean 

RRRRRRRRRRR For background on economic principles and the marginal benefit estimates, see Technical Support 

Document on Benefits of Reducing GHG Emissions, U.S. Environmental Protection Agency, June 12, 2008, 

www.regulations.gov (search phrase “Technical Support Document on Benefits of Reducing GHG Emissions”) SSSSSSSSSSS A discount rate reflects the rate at which people trade-off a dollar received today versus a dollar received 

a year from now. People generally value benefits received today more than those received tomorrow. As a result, 

when making decisions today, they tend to discount the benefits they receive in the future. The actual discount rate 

depends on the decision-maker and the kind of investment. In this context, the decision-maker is the Federal 

Government and changing GHG emissions is an investment with an extremely long-run annual (non-constant) 

return. Therefore, social discounting and intergenerational discount rates are appropriate. TTTTTTTTTTT See Table 5.3-1 for global (FUND) estimates consistent with the U.S. estimates. 

682 
 

 

 

 

 

 

values from a single model are $4 and $1/t CO2 for the same discount rates. The estimates for 

future year emission changes are likely to be higher as future marginal emissions increases are 

expected to produce larger incremental damages as physical and economic systems become more 

stressed as the magnitude of climate change increases.UUUUUUUUUUU 

Table 5.3-1. 

Marginal GHG Benefits Estimates for Consumption Discount Rates of 

2%, 3%, and 7% and Year of Emissions Change 

(all values are reported in 2006$/tCO2) 

2% 3% 7%**

Low Central High Low Central High Low Central High 

Meta global

2007 -3 68 159 -4 40 106 n/a n/a n/a 

2017 -2 91 213 -3 53 142 n/a n/a n/a 

2022 -2 105 247 -2 62 165 n/a n/a n/a 

2030 -1 134 314 -2 78 209 n/a n/a n/a 

2040 -1 179 421 -1 105 281 n/a n/a n/a 

FUND

global

2007 -6 88 695 -6 17 132 -3 -1 5 

2017 -4 118 934 -4 23 178 -2 -1 7 

2022 -4 136 1083 -4 26 206 -2 -1 9 

2030 -3 173 1372 -3 33 261 -1 0 11 

2040 -2 232 1843 -2 44 351 -1 0 15 

FUND

domestic

2007 0 4 16 0 1 5 0 0 0 

2017 0* 6 22 0* 1 7 0* 0* 0* 

2022 0* 7 26 0* 2 9 0* 0* 0* 

2030 0* 9 32 0* 2 11 0* 0* 0* 

2040 0* 12 44 0* 3 15 0* 0* 0* 

* These estimates, if explicitly estimated, may be greater than zero, especially in later years. They are currently reported as zero 

because the explicit estimates for an earlier year were zero and were grown at 3% per year. However, we do not anticipate that 

the explicit estimates for these later years would be significantly above zero given the magnitude of the current central estimates 

for discount rates of 2% and 3% and the effect of the high discount rate in the case of 7%. 

** Except for illustrative purposes, the marginal benefits estimates in the peer reviewed literature do not use consumption 

discount rates as high as 7%. 

The meta analysis ranges were developed from the Tol (2008) meta 

analysis.VVVVVVVVVVV The meta analysis range only includes global estimates generated by 

more recent peer reviewed studies (i.e., published after 1995). In addition, the ranges only 

consider regional aggregations using simple summation and intergenerational consumption 

discount rates of approximately 2% and 3%. Discount rates of 2% and 3% are consistent with 

EPA and OMB guidance on intergenerational discount rates (EPA, 2000; OMB, 

2003).WWWWWWWWWWW The estimated distributions of the meta global estimates are right 

skewed with long right tails, which is consistent with characterizations of low probability high 

impact damages, such as catastrophic events like collapse of the West Antarctic Ice 

UUUUUUUUUUU The IPCC suggests an increase of 2-4% per year (IPCC WGII, 2007. Climate Change 2007 - Impacts, 

Adaptation and Vulnerability. Contribution of Working Group II to the Fourth Assessment Report of the IPCC, 

http://www.ipcc.ch/). For Table 5.3-1., we assumed the estimates increased at 3% per year. For the final rule, we 

anticipate that we will explicitly estimate FUND marginal benefits values for each emissions reduction year. VVVVVVVVVVV Tol (2008) is an update of the Tol (2005) meta analysis. Tol (2005) was used in the IPCC Working 

Group II’s Fourth Assessment Report (IPCC WGII, 2007).

WWWWWWWWWWW OMB and EPA guidance on inter-generational discounting suggests using a low but positive 

discount rate if there are important intergenerational benefits/costs. Consumption discount rates of 1% to 3% are 

given by OMB and 0.5% to 3% by EPA (OMB Circular A-4, 2003; EPA Guidelines for Preparing Economic 

Analyses, 2000). 

683 
-36 0 36 72 108 144 180 

2006$/tCO2

~2%

~3%

Probability of 

$/tCO2

 

 

 

 

Sheet.XXXXXXXXXXX YYYYYYYYYYY ZZZZZZZZZZZ Figure 5.3-1 provides the estimated probability 

density functions by discount rate. Following Tol (2008), we fit extreme value Fisher-Tippett 

distributions because they better reflected the right skewness of the data.AAAAAAAAAAAA Note 

that the x-axis of Figure 5.3-1 reflects that marginal value for emissions reductions circa 1995. 

As noted above, these values were grown to produce the estimates in Table 5.3-1. The central 

meta estimates in Table 5.3-1 are means, and the low and high are the 5th and 95th percentiles. 

Means are presented because, as a central statistic, they better represent the skewed shape of 

these distributions compared to medians. 

Figure 5.3-1. 

Probability Density Functions for Meta Analysis Global Marginal Benefit Estimates for a 

Marginal Emissions Reduction circa 1995 and Consumption Discount Rates of 2% and 3%
 

(Developed from Tol, 2008, Meta Analysis) 

-36 0 36 72 108 144 180 

2006$/tCO2 

~2% 

~3%

Probability of

$/tCO2 The consistent domestic and global estimates were developed using the FUND integrated 

assessment model.BBBBBBBBBBBB The ranges were generated from sensitivity analysis where 

assumptions were varied with respect to climate sensitivity (1.5 to 6.0 degrees 

XXXXXXXXXXX Webster, M., C. Forest, J.M. Reilly, M.H. Babiker, D.W. Kicklighter, M. Mayer, R.G. Prinn, M. 

Sarofim, A.P. Sokolov, P.H. Stone & C. Wang, 2003. Uncertainty Analysis of Climate Change and Policy
 

Response, Climatic Change 61(3): 295-320. 

YYYYYYYYYYY Weitzman, M., 2007, “The Stern Review of the Economics of Climate Change,” Journal of Economic 

Literature. ZZZZZZZZZZZ Weitzman, M., 2007, “Structural Uncertainty and the Statistical Life in the Economics of Catastrophic 

Climate Change,” Working paper http://econweb.fas.harvard.edu/faculty/weitzman/papers/ValStatLifeClimate.pdf. AAAAAAAAAAAA For our meta analysis, the sample sizes were 13 and 10 for consumption discount rates of 2% and 3%
 

respectively. A sample size of 10 or greater is considered sufficient for estimating an extreme value distribution
 

(Carter, D. J. T. and P. G. Challenor, 1983. Application of extreme value analysis to Weibull data, Quart. J. R. Met. 

Soc. 109, 429-433). BBBBBBBBBBBB FUND is a spatially and temporally consistent framework across regions of the world (e.g., U.S., 

China), impacts sectors, and time. FUND explicitly models impacts sectors in 16 global regions. FUND is one of
 

the few models in the world that explicitly models global and regional marginal benefits estimates. Numerous
 

applications of FUND have been published in the peer reviewed literature dating back to 1997. See 

http://www.fnu.zmaw.de/FUND.5679.0.html. 

684 
 

   

       

 

 

 

 

 

 

 

Celsius),CCCCCCCCCCCC the socio-economic and emissions baseline scenarios (the FUND default 

baseline and three baselines from the Intergovernmental Panel on Climate Change (IPCC) 

Special Report on Emissions Scenarios, SRES),DDDDDDDDDDDD and the consumption discount 

rates of approximately 2%, 3%, and 7%, where 2% and 3% are consistent with intergenerational 

discounting.EEEEEEEEEEEE Furthermore, the model was calibrated to the EPA value of a statistical 

life of $7.4 million (2006$).FFFFFFFFFFFF The FUND global estimates are the sum of the regional 

estimates within FUND. The FUND global and domestic central values in Table 5.3-1 are 

weighted averages of the FUND estimates from the sensitivity analysis. The low and high values 

are the low and high estimates across the sensitivity runs. See Table 5.3-2 for the global and 

domestic marginal benefit estimates by baseline, climate sensitivity, and discount rate. The 

weighted averages were calculated using a climate sensitivity probability density function based 

on IPCC WGI (2007) and equal weights for the alternative socioeconomic 

baselines.GGGGGGGGGGGG 

Table 5.3-2. 

Global and Domestic Marginal Benefit Estimates from FUND Modeling by Baseline, 

Climate Sensitivity (CS), and Discount Rate (DR) for an Additional Unit of Emissions in 

2005 (2006$/t CO2)
 CS = 1.5 deg C 2 3 4.5 6

Baseline DR = ~2% ~3% ~7% ~2% ~3% ~7% ~2% ~3% ~7% ~2% ~3% ~7% ~2% ~3% ~7%

Global

FUND ‐$2 ‐$5 ‐$3 $9 ‐$2 ‐$3 $43 $9 ‐$1 $140 $35 $1 $365 $81 $5

A1b ‐$6 ‐$5 ‐$3 $0 ‐$3 ‐$2 $16 $3 ‐$2 $54 $16 $0 $114 $37 $3

A2 ‐$2 ‐$6 ‐$3 $15 ‐$1 ‐$3 $68 $13 ‐$2 $240 $51 $1 $655 $125 $5

B2 ‐$4 ‐$5 ‐$3 $8 ‐$2 ‐$3 $43 $8 ‐$2 $145 $34 $1 $409 $83 $4

Domestic

FUND $0 $0 $0 $1 $0 $0 $3 $1 $0 $7 $2 $0 $11 $4 $0

A1b $0 $0 $0 $1 $0 $0 $2 $1 $0 $6 $2 $0 $10 $3 $0

A2 $0 $0 $0 $2 $0 $0 $4 $1 $0 $9 $3 $0 $15 $5 $0

B2 $0 $0 $0 $1 $0 $0 $3 $1 $0 $7 $2 $0 $11 $4 $0

CCCCCCCCCCCC In IPCC reports, equilibrium climate sensitivity refers to the equilibrium change in the annual mean 

global surface temperature following a doubling of the atmospheric equivalent carbon dioxide concentration. The 

IPCC states that climate sensitivity is “likely” to be in the range of 2°C to 4.5°C and described 3°C as a "best 

estimate", which is the mode (or most likely) value. The IPCC goes on to note that climate sensitivity is “very 

unlikely” to be less than 1.5°C and “values substantially higher than 4.5°C cannot be excluded.” IPCC WGI, 2007, 

Climate Change 2007 - The Physical Science Basis, Contribution of Working Group I to the Fourth Assessment 

Report of the IPCC, http://www.ipcc.ch/. 

DDDDDDDDDDDD The IMAGE model SRES baseline data were used for the A1b, A2, and B2 scenarios (IPCC, 2000. 

Special Report on Emissions Scenarios. A special report of Working Group III of the Intergovernmental Panel on 

Climate Change. Cambridge University Press, Cambridge). The A1b baseline represents a world focused on global 

economic growth with an increasingly globalized economy, with a balanced energy technology portfolio between 

fossil fuel and non-fossil fuel supply and consumption, and diffusion of technological advances. The A2 baseline 

represents a world focused on regional economic growth with increasing inequality between regions as developed 

regions grow more quickly than developing regions. B2 represents a world focused on both global economic growth 

and environmental improvement. 

EEEEEEEEEEEE The EPA guidance on intergenerational discounting states that “[e]conomic analyses should present a 

sensitivity analysis of alternative discount rates, including discounting at two to three percent and seven percent as 

in the intra-generational case, as well as scenarios using rates in the interval one-half to three percent as prescribed 

by optimal growth models.” (EPA, 2000)

FFFFFFFFFFFF This number may be updated to be consistent with recent EPA Office of Air and Radiation regulatory 

impact analyses that has used a value of $6.4 million (in 2006 real dollars). GGGGGGGGGGGG The climate sensitivity probability density function was calibrated to the cumulative density functions 

in Chapter 10 of IPCC WGI (2007), and the IPCC’s formal definitions for climate sensitivity likelihood. 

685 
 

 

 

Figures 5.3-2 through 5.3-5 provide the undiscounted global and domestic annual 

marginal benefits from our FUND modeling for an illustrative set of scenarios from our 

sensitivity analysis for an incremental emissions change in 2005.HHHHHHHHHHHH The figures 

illustrate the sensitivity of the global and domestic results to baseline and climate responsiveness. 

These streams of annual benefits were discounted following the common approach of Ramsey 

discounting, which incorporates changes in economic growth and the marginal utility of 

consumption over time.IIIIIIIIIIII We calibrated our discounting to produce U.S. consumption 

discount rates of approximately 2% and 3% in order to be consistent with OMB and EPA intergenerational discounting guidance. The resulting calibration produced 2005 rates of 2.7% to 

2.9% for the U.S., and 1.8% to 5.5% across regions. The rates vary by region and time period as 

regional annual growth in per capita consumption changes. 

Figure 5.3-2. 

Undiscounted Global Annual Marginal Benefits from FUND Modeling for an Emissions 

Reduction in 2005 with the FUND Default Baseline and Climate Sensitivities of 

1.5, 2.0, 3.0, 4.5, and 6.0 

$16 

$14 

$12 

$10 

$8 

$6 

$4 

$2 

$0 

-$2 

20

20

21

2

21

22

10

2020

2030

20

5

60

20

80

20

00

21

2

30

21

50

21

70

18

00

22

20

22

4

50

22

70

22

40

9

20

70

20

90

21

10

21

40

21

60

21

90

22

10

22

30

22

60

22

80

22

0

0

0

0

0 

CS6.0 FUND 

CS4.5 FUND 

CS3.0 FUND 

CS2.0 FUND 

CS1.5 FUND 

2006$/tCO2/year 

HHHHHHHHHHHH Undiscounted annual benefits are not available for the meta analysis estimates. The FUND default 

year for our runs is 2005. FUND marginal benefit estimates for subsequent years in Table 5.3-1 were computed by 

growing the 2005 values at 3%/year as discussed above. 

IIIIIIIIIIII A constant discount rate implies constant economic growth, which is unrealistic over long time horizons. 

Interest rates are a function of economic growth; and, increasing (declining) economic growth implies an increasing 

(declining) discount rate. Furthermore, increasing uncertainty in economic growth implies, among other things, 

increasing uncertainty in interest rates and declining certainty equivalent rates of returns to capital (Hansen, A.C., 

2006. “Do declining discount rates lead to time inconsistent economic advice?” Ecological Economics 60(1), 138­

144.) 

686 
Figure 5.3-3. 

Undiscounted Global Annual Marginal Benefits from FUND Modeling for an 

Emissions Reduction in 2005 with the SRES A1b, A2, B2, and FUND Default Baselines 

and a Climate Sensitivity of 3.0 

$12 

2010

2020

2030

2040

2050

2060

2070

2080

2090

2100

2110

2120

2130

2140

2150

2160

2170

2180

2190

2200

2210

2220

2230

2240

2250

2260

2270

2280

2290 

CS3.0 FUND 

CS3.0 A1b 

CS3.0 A2 

CS3.0 B2 

$10 

$8 

$6 

$4 

$2 

$0 

2006$/tCO2 

-$2 

Figure 5.3-4. 

Undiscounted U.S. Annual Marginal Benefits from FUND Modeling for an 

Emissions Reduction in 2005 with the FUND Default Baseline and 

Climate Sensitivities of 1.5, 2.0, 3.0, 4.5, and 6.0 

$0.30 

20102020203020402050206020702080209021002110212021302140215021602170218021902200221022202230224022502260227022802290 

CS6.0 FUND 

CS4.5 FUND 

CS3.0 FUND 

CS2.0 FUND 

CS1.5 FUND 

2006$/tCO2 

$0.25 

$0.20 

$0.15 

$0.10 

$0.05 

$0.00 

-$0.05 

687 
 

Figure 5.3-5. 

Undiscounted U.S. Annual Marginal Benefits from FUND Modeling for an Emissions 

Reduction in 2005 with the SRES A1b, A2, B2, and FUND Default Baselines 

and a Climate Sensitivity of 3.0 

$0.16 

2006$/tCO2 

$0.14 

$0.12 

$0.10 

$0.08 

$0.06 

$0.04 

$0.02 

$0.00 

-$0.02 

20102020203020402050206020702080209021002110212021302140215021602170218021902200221022202230224022502260227022802290 

CS3.0 FUND 

CS3.0 A1b 

CS3.0 A2 

CS3.0 B2 

From Tables 5.3-1 and 5.3-2, we see that the estimates are very sensitive to assumptions. 

The FUND sensitivity analysis shows that higher marginal benefits estimates are associated with 

higher climate sensitivities, lower economic growth per capita globally and regionally, and lower 

discount rates. In terms of the current monetized benefits, the domestic marginal benefits are a 

fraction of the global marginal benefits. Given uncertainties and omitted impacts, it is difficult 

to estimate the actual ratio of total domestic benefits to total global benefits. The estimates 

suggest that an emission reduction will have direct benefits for current and future U.S. 

populations and large benefits for global populations. The long-run and intergenerational 

impacts due to GHG emissions are evident in the difference in results across discount rates. In 

the current modeling, there are substantial long-run benefits (beyond the next two decades to 

over 100 years) and some near-term benefits as well as negative effects (e.g., agricultural 

productivity and heating demand). High discount rates give less weight to the future benefits in 

the net present value calculations, and more weight to near-term effects. Table 5.3-2 also 

illustrates that an additional unit of emissions is estimated to have a proportionally larger effect 

on the rest of the world compared to the U.S. if the climate and/or economic system turn out to 

be more sensitive (i.e., climate sensitivity of 6 degrees Celsius and A2 baseline respectively) to 

an increasing stock of GHGs in the atmosphere scenarios. Some of these points are discussed 

more below. 

5.3.3 Discussion of Marginal GHG Benefits Estimates 

This section briefly discusses important issues relevant to the marginal benefits estimates 

in Table 5.3-1. Because of the global nature of CO2 and other greenhouse gases, estimating the 

marginal benefits required a global modeling framework with consistent integrated 

socioeconomics, emissions, climate change, and impacts. Given uncertainties in socio-economic 

futures (e.g., population growth, economic growth, and technology availability and diffusion), 

corresponding GHG emissions, climate responses to emissions changes, and the bio-physical and 

688 
 

 

economic impacts associated with changes in climate, the quantified (physical and monetized) 

estimates of climate change are inherently uncertain. 

The broad range of estimates in Table 5.3-1 reflects some of the uncertainty associated 

with estimating monetized marginal benefits of climate change. The meta analysis range reflects 

differences in these assumptions as well as differences in the modeling of changes in climate and 

impacts considered and how they were modeled. EPA considers the meta analysis results to be 

more robust than the single model estimates in that the meta results reflect uncertainties in both 

models and assumptions. 

The current state-of-the-art for estimating benefits is important to consider when 

evaluating policies. There are significant partially quantified and omitted impact categories not 

captured in the estimates provided above. The IPCC Working Group II (IPCC WGII; 2007) 

concluded that current estimates are “very likely” to be underestimated because they do not 

include significant impacts that have yet to be monetized.JJJJJJJJJJJJ Current estimates do not 

capture many of the main reasons for concern about climate change, including non-market 

damages (e.g., species existence value and the value of having the option for future uses, such as 

for biomedical, tourism, or recreational purposes), the effects of climate variability, risks of 

potential extreme weather (e.g., droughts, heavy rains and wind), socially contingent effects 

(such as violent conflict or humanitarian crisis), and thresholds (or tipping points) associated 

with species, ecosystems, and potential long-term catastrophic events. Some scientists believe 

that effects on factors such as arctic summer ice, Himalayan-Tibetan Glaciers, and the Greenland 

ice sheet are more sensitive to near-term GHG emissions changes, implying that there are nonlinearities in the effects attributable to GHG emissions.KKKKKKKKKKKK Underestimation is even 

more likely when one considers that the current trajectory for GHG emissions is higher than 

what is being considered in current integrated assessment modeling (such as that reflected in the 

modeling represented in Tol, 2008, and Clarke et al., 2006). When combined with current 

regional population and income trajectories that are more asymmetric than what is currently 

modeled, this implies greater climate change and vulnerability to climate change. 

In Table 5.3-3, we provide a list of the impacts categories currently modeled in the 

FUND model, and an initial, partial list of categories of impacts that are currently not modeled in 

the FUND model and are thus not reflected in the FUND estimates. Table 5.3-4 provides an 

initial list of some more specific types of impacts reported on by the IPCC but are not currently 

captured in FUND.LLLLLLLLLLLL A key challenge for many impacts sectors is data limitations 

(primarily physical data). Note that most of the omitted impacts are likely to lead to additional 

benefits in response to reductions in GHG emissions, including international impacts that could 

affect domestic benefits (e.g., potential impact feedbacks to the United States, U.S. concern for 

international impacts, and international participation). EPA is planning to develop a full 

assessment of what is not currently being captured in FUND for the final rule. In addition, EPA 

JJJJJJJJJJJJ IPCC WGII, 2007. In the IPCC report, “very likely” was defined as a greater than 90% likelihood based on 

expert judgment. 

KKKKKKKKKKKK Ramanathan and Feng, 2008. On avoiding dangerous anthropogenic interference with the climate 

system: Formidable challenges ahead. Proceedings of the National Academy of Sciences 105:143245-14250. LLLLLLLLLLLL IPCC WGII (2007) Summary for Policy Makers and Chapter 14 North America. 

689 
plans to quantify omitted impacts and update impacts currently represented to the extent possible 

for the final rule. 

Table 5.3-3. 

Lists of Impact Categories Modeled and Omitted from Current FUND Modeling 

(see Table 5.3-4 for specific types of impacts omitted)
 

Impacts currently modeled in FUND 

•	 Agricultural production 

•	 Forestry production 

•	 Water resources 

•	 Energy consumption for space 

cooling & heating 

•	 Sea level rise dry land loss, wetland 

loss, and coastal protection costs 

•	 Forced migration due to dry land 

loss 

•	 Changes in human health (mortality, 

morbidity) associated with diarrhea 

incidence, vector-borne diseases, 

cardiovascular disorders, and 

respiratory disorders 

•	 Hurricane damage 

•	 Loss of ecosystems/biodiversity 

Examples of impacts omitted from 

current FUND modeling 

•	 Catastrophic events (e.g., Antarctic 

ice sheet collapse) 

•	 Risks from extreme weather (e.g., 

death, disease and economic 

damage from droughts, floods, and 

fires) 

•	 Air quality degradation (e.g., 

increased ozone effects including 

premature mortality, forest damage) 

•	 Increased infrastructure costs (e.g., 

water management systems, roads, 

bridges) 

•	 Increased insurance costs 

•	 Social and political unrest abroad 

that affects U.S. national security 

•	 Damage to foreign economies that 

affects the U.S. economy 

•	 Domestic valuation of international 

impacts 

•	 Costs from uncertainty and changes 

in risk 

•	 Arctic sea ice melt and global 

transportation & trade 

690 
 

 

 

Table 5.3-4. 

Initial List of Specific Types of Impacts Not Current Captured in FUND Agriculture

Reduction in growing season (Sahel/southern Africa) 

Increase in growing season in moderate climates 

Impact of precipitation changes on agriculture 

Impact of weather variability on crop production 

Biomes/ecosystems

Reverse of carbon uptake, amplification of climate change 

Earlier timing of spring events/ longer growing season 

Poleward and upward shift in habitats/species migraiton 

Shifts in ranges of ocean life 

Increases in algae and zooplankton 

Range changes/earlier migration of fish in rivers 

Increase in ocean acidification/ impacts on coral reefs 

Ecosystem service disruption (e.g. loss of cold water fish habitat in the U.S.) 

Coral bleaching due to ocean warming 

Energy

Energy production/infrastructure 

Water temperature/supply impacts on energy production 

Forest 

Forest changes with longer fire seasons, longer burning fires, and increased burn area 

Disappearance of alpine habitat in the United States 

Tropical forest dieback in the Amazon 

GDP/economy

National security/armed conflict 

Insurance costs with changes in extreme weather, flooding, and sea level rise 

Distributional effects within regions 

Societies that are highly dependent on climate-sensitive resources are highly vulnerable 

Extreme weather events 

Health

Increased deaths, injuries, infectious diseases, stress-related disorders with more frequent 

extreme weather 

Increased heavy rainfall increased risks to human health associated with waterborne disease, 

increased baterial counts 

Increases in malnutrition 

Health impacts due to interactions with air quality 

Snow/

glacier

Changes in Arctic/Antarctic ecosystems 

Enlargement and increased numbers of glacial lakes/ increased flooding 

Snow pack in SE US 

Tourism 

Changes in tourism revenues due to changes in ecosystems and weather events (e.g., 

wildfires, droughts, hurricances) 

Arctic hunting/travel/mountain sports 

Water 

River flooding 

Infrastructure, water supply 

Precipitation changes on water supply 

Increasing ground instability and avalanches 

Increased/earlier runoff in snow-fed rivers 

The current estimates are also deterministic in that they do not account for the value 

people have for changes in risk associated with the lower likelihood of potential impacts 

associated with reductions in CO2 and other GHG emissions (i.e., a risk premium). This is an 

issue that has concerned Weitzman and other economists.MMMMMMMMMMMM We plan to conduct 

a formal uncertainty analysis for the final rule to attempt to account for, to the extent possible, 

these and other changes in uncertainty. 

MMMMMMMMMMMM See Webster et al., 2003; Weitzman, M., 2007. 

http://econweb.fas.harvard.edu/faculty/weitzman/papers/ValStatLifeClimate.pdf. 

691 
 

 

 

 

In part because monetized benefit estimates reflect a subset of climate change impacts, it 

is important in evaluating policies for reducing GHGs to consider the available scientific and 

other qualitative information on climate change impacts as well. A summary of potential U.S. 

climate change impacts based on the existing literature is provided in a report by the U.S. 

Climate Change Science Program, “Scientific Assessment of the Impacts of Climate Change in 

the United States,” released in May 2008. A similar scientific overview that discusses 

international as well as domestic impacts is provided in an EPA technical support document that 

underwent interagency review and was finalized in June 2008.NNNNNNNNNNNN These reports 

contain information relevant to some of the omitted impacts categories in the tables above (e.g., 

in the EPA document, section 6f discusses abrupt climate change; section 15(a) discusses 

national security), as well as on impacts that are monetized in this analysis. 

There are two important points to keep in mind in applying the estimates in Table 5.3-1 

and this kind of modeling. First, the estimates in Table 5.3-1 are not estimates of economically 

“optimal” marginal benefits (i.e., they are not associated with an emissions reduction level where 

marginal benefits equal marginal costs). The estimates in Table 5.3-1 are only relevant for 

incremental policies relative to the projected baselines (that do not reflect potential future climate 

policies) and there is substantial uncertainty associated with the estimates themselves both in 

terms of what is being modeled and what is not being modeled, with many uncertainties outside 

of observed variability.OOOOOOOOOOOO Furthermore, the estimates only represent the value of a 

marginal emissions change in a specific year, they do not account for potential affects of current 

reductions on the value of reductions in the future. These points are important for non-marginal 

emissions changes and estimating total benefits. For example, current estimates of marginal 

emissions changes do not model threshold impacts, variability changes, or changes in the 

likelihood of these impacts. 

Second, because current marginal benefits estimates are incomplete and highly uncertain 

(with many uncertainties outside of observed variability), we cannot use them to identify an 

economically optimal (or economically efficient) standard, even for incremental changes in 

global GHG emissions, and it creates issues in applying positive net benefit criteria. The 

uncertainty shifts attention to consideration of changes in risk and points to the importance of 

considering factors beyond monetized benefits and costs. In an uncertain situation such as that 

associated with climate, EPA typically recommends that analysis consider a range of benefit and 

cost estimates, and the potential implications of non-monetized and non-quantified benefits. 

NNNNNNNNNNNN “Technical Support Document for the Endangerment Analysis for Greenhouse Gas Emissions Under 

the Clean Air Act, Sixth Order Draft” Climate Change Division, Office of Atmospheric Programs, U.S. 

Environmental Protection Agency, Washington, D.D., June 21, 2008

OOOOOOOOOOOO With projected increasing changes in climate, some types of potential climate change impacts may 

occur suddenly or begin to increase at a much faster rate, rather than increasing gradually or smoothly. In this case, 

there are likely to be jumps in the functioning of species and ecosystems, the frequency and intensity of extreme 

conditions (e.g., heavy rains, forest fires), and the occurrence of catastrophic events (e.g., collapse of the West 

Antarctic Ice Sheet). As a result, different approaches are necessary for quantifying the benefits of “small” 

(incremental) versus “large” (non-incremental) reductions in global GHGs. Marginal benefits estimates, like those 

presented above, can be useful for estimating benefits for small changes in emissions. However, for large changes 

in emissions, a more comprehensive assessment of impacts would be needed to capture changes in economic and 

biophysical dynamics and feedbacks in response to the policy. Even small reductions in global GHG emissions are 

expected to reduce climate change risks, including catastrophic risks. 

692 
 

 

Economic principles suggest that global benefits should also be considered when 

evaluating alternative GHG reduction policies. GHG emissions are different from most air 

pollutants, due to their global and intergenerational externality implications. A ton of GHG 

emitted from any location or source can result in impacts throughout the globe and across 

multiple generations. Climate change can therefore be characterized as a global and 

intergenerational public good. Typically, because the benefits and costs of most environmental 

regulations are predominantly domestic, EPA focuses on benefits that accrue to the U.S. 

population when quantifying the impacts of domestic regulation. However, OMB’s guidance for 

economic analysis of federal regulations also specifically allows for consideration of 

international effects.PPPPPPPPPPPP GHG have global and very long-run implications for climate, a 

global public good, and economic principles suggest that the full costs to society of emissions 

should be considered in order to identify the policy that maximizes the net benefits to society, 

i.e., achieves an efficient outcome (Nordhaus, 2006).QQQQQQQQQQQQ As such, estimates of global 

benefits more fully capture the value to society than domestic estimates and will result in higher 

global net benefits for GHG reductions when considered.RRRRRRRRRRRR 

Furthermore, international effects of climate change may also affect domestic benefits 

directly and indirectly to the extent that U.S. citizens value international impacts (e.g., for 

tourism reasons, concerns for the existence of ecosystems, and/or concern for others); U.S. 

international interests are affected (e.g., risks to U.S. national security or the U.S. economy from 

potential disruptions in other nations); and/or domestic mitigation decisions affect the level of 

mitigation and emissions changes in general in other countries (i.e., the benefits realized in the 

U.S. will depend on domestic and international emissions changes). The economics literature 

also suggests that policies based on direct domestic benefits will result in little appreciable 

reduction in global GHGs (e.g., Nordhaus, 1995).SSSSSSSSSSSS While these marginal benefits 

estimates are not comprehensive or economically optimal, the global estimates in Table 5.3-1 

can help guide policies towards more efficient levels of provision of the public good since they 

internalize a larger portion of the full costs to society a unit of emissions — the global and 

intergenerational externalities. 

A key challenge facing EPA is the appropriate discount rate over the longer timeframe 

relevant for GHGs. When considering climate change investments, they should be compared to 

similar investments (via the discount rate). EPA typically discounts future costs or benefits back 

PPPPPPPPPPPP OMB (2003), page 15. 

QQQQQQQQQQQQ Nordhaus, W., 2006, "Paul Samuelson and Global Public Goods,” in M. Szenberg, L. Ramrattan, and 

A. 

Gottesman (eds), Samuelsonian Economics, Oxford. 

RRRRRRRRRRRR Both the United Kingdom and the European Commission followed these economic principles in 

consideration of the global social cost of carbon (SCC) for valuing the benefits of GHG emission 

reductions in regulatory impact assessments and cost-benefit analyses (Watkiss et al, 2006). Recently, the National 

Highway Traffic Safety Administration (NHTSA) issued the final Environmental Impact Statement for their 

proposed rulemaking for average fuel economy standards for passenger cars and light trucks in which the preferred 

alternative is based on domestic marginal benefit estimates for carbon dioxide reductions. See Average Fuel 

Economy Standards, Passenger Cars and Light Trucks, MY 2011-2015, Final Environmental Impact Statement 

http://www.nhtsa.dot.gov/portal/site/nhtsa/menuitem.43ac99aefa80569eea57529cdba046a0/ 

SSSSSSSSSSSS Nordhaus, William D. (1995). “Locational Competition and the Environment: Should Countries 

Harmonize Their Environmental Policies?” in Locational Competition in the World Economy, Symposium 

1994, ed., Horst Siebert, J. C. B. Mohr (Paul Siebeck), Tuebingen, 1995. 

693 
 

 

 

 

to the present using a discount rate, where the discount rate represents how society trades off 

current consumption for future consumption. With the benefits of GHG emissions reductions 

distributed over a very long time horizon, benefit and cost comparisons are likely to be very 

sensitive to the discount rate. For policies with relatively short time horizons, up to 30 years or 

so (i.e., that affect the current generation of people), the analytic approach used by EPA is to use 

discount rates of 3% and 7% percent at a minimum.TTTTTTTTTTTT A 3% rate is consistent with 

what a typical consumer might expect in the way of a risk free market return. A 7% rate is an 

estimate of the average before-tax rate of return to private capital in the U.S. economy. 

However, what discount rates are appropriate for discounting social benefits and costs 

over the longer timeframe relevant for climate change policies? Changes in GHG emissions — 

both increases and reductions — are essentially long-run investments in changes in climate and 

the potential impacts from climate change. Investments in climate change represent longer-term 

investments in infrastructure and technologies associated with mitigation, where there are annual 

returns of avoided impacts over a period of one hundred years and longer that affect multiple 

generations. Furthermore, there is a potential for significant impacts from climate change, where 

the exact timing and magnitude of these impacts are unknown. These factors imply an uncertain 

investment environment with uncertain economic growth that varies over time. 

When there are important benefits or costs that affect multiple generations of the 

population, EPA and OMB allow for low but positive consumption discount rates (e.g., 0.5% to 

3% noted by the U.S. EPA, 1% to 3% by the OMB).UUUUUUUUUUUU In this multi-generation 

context, a three percent discount rate is consistent with observed interest rates from long-term 

investments available to current generations (net of risk premiums) as well as current estimates 

of the impacts of climate change that reflect potential impacts on consumers. A review of the 

literature indicates that rates of three percent or lower are more consistent with long-run 

uncertainty in economic growth and interest rates, considerations of issues associated with the 

transfer of wealth between generations, and the risk of high impact climate damages (which 

could reduce or reverse economic growth). Given the uncertain environment, analysis could also 

consider evaluating uncertainty in the discount rate (e.g., Newell and Pizer, 2001, 

2003).VVVVVVVVVVVV WWWWWWWWWWWW 

For the final rulemaking, we will be developing and updating the FUND model to the 

extent possible based on the latest research and peer reviewing the estimates. To improve upon 

our estimates, we hope to evaluate several factors not currently captured in the proposed 

TTTTTTTTTTTT EPA (U.S. Environmental Protection Agency), 2000. Guidelines for Preparing Economic Analyses. 

EPA 240-R-00-003. See also OMB (U.S. Office of Management and Budget), 2003. Circular A-4. September 17, 

2003. 

UUUUUUUUUUUU EPA (U.S. Environmental Protection Agency), 2000. Guidelines for Preparing Economic Analyses. 

EPA 240-R-00-003. See also OMB (U.S. Office of Management and Budget), 2003. Circular A-4. September 17, 

2003. These documents are the guidance used when preparing economic analyses for all EPA rulemakings. 

VVVVVVVVVVVV Newell, R. and W. Pizer, 2001. Discounting the benefits of climate change mitigation: How much 

do 

uncertain rates increase valuations? Pew Center on Global Climate Change, Washington, DC. WWWWWWWWWWWW Newell, R. and W. Pizer, 2003. Discounting the distant future: how much do uncertain rates 

increase valuations? Journal of Environmental Economics and Management 46: 52–71. 

694 
 

 

 

estimates due to time constraints. For example, we will quantify additional impact categories 

where possible and provide a qualitative evaluation of the implications of what is not monetized. 

We also plan to conduct an uncertainty analysis, consider complementary bottom-up analyses, 

and develop estimates of the marginal benefits associated with non-CO2 GHGs relevant to the 

RFS2 proposal (e.g., CH4, N2O, and HFC-134a).XXXXXXXXXXXX 

EPA solicits comment on the appropriateness of using U.S. and global values in 

quantifying the benefits of GHG reductions and the appropriate application of benefits estimates 

given the state of the art and overall uncertainties. We also seek comment on our estimates of 

the global and U.S. marginal benefits of GHG emissions reductions that EPA has developed, 

including the scientific and economic foundations, the methods employed in developing the 

estimates, the discount rates considered, current and proposed future consideration of uncertainty 

in the estimates, marginal benefits estimates for non-CO2 GHG emissions reductions, and 

potential opportunities for improving the estimates. We are also interested in comments on 

methods for quantifying benefits for non-incremental reductions in global GHG emissions. 

5.3.4 Total Monetized GHG Benefits Estimates 

As described in Section 2.3, annualized equivalent GHG emissions reductions associated 

with the proposal in 2022 would be 160 million metric tons of CO2 equivalent (MMT CO2eq) in 

with a 2% discount rate, and 155 and 136 MM CO2eq with discount rates of 3% and 7% 

respectively. 

This section provides the monetized total GHG benefits estimates associated with the 

proposal in 2022. As discussed above in subsection three, these estimates do not include 

significant impacts that have yet to be monetized. Total monetized benefits in 2022 are 

calculated by multiplying the marginal benefits per metric ton of CO2 in that year by the 

annualized equivalent emissions reductions. For the final rulemaking, we plan to separate the 

emissions reductions by gas and use CO2 and non-CO2 marginal benefits estimates. Non- CO2 

GHGs have different climate and atmospheric implications and therefore different marginal 

climate impacts. 

Table 5.3-5 provides the estimated monetized GHG benefits of the proposal for 2022. 

The large range of values in the tables reflects some of the uncertainty captured in the range of 

monetized marginal benefits estimates presented in Table 5.3-1.YYYYYYYYYYYY All values in this 

section are presented in 2006 real dollars. 

XXXXXXXXXXXX Due to differences in atmospheric lifetime and radiative forcing, the marginal benefit values of nonCO2 GHG reductions and their growth rates over time will not be the same as the marginal benefits of CO2 

emissions reductions (IPCC WGII, 2007). 

YYYYYYYYYYYY EPA notes, however, that the Ninth Circuit recently rejected an approach of assigning no monetized 

value to greenhouse gas reductions resulting from vehicular fuel economy. Center for Biodiversity v. NHTSA, F. 

3d, (9th Cir. 2007). 

695 
Table 5.3-5. 

Monetized GHG Benefits of the Proposed Rule in 2022 

(Billions of 2006$) 

Marginal Benefit 2% 3% 7% 

Meta global 

Low -$0.3 -$0.3 n/a 

Central $16.8 $9.6 n/a 

High $39.4 $25.5 n/a 

FUND global 

Low -$0.6 -$0.6 -$0.3 

Central $21.7 $4.0 -$0.1 

High $172.8 $31.9 $1.2 

FUND domestic 

Low $0.0 $0.0 $0.0 

Central $1.1 $0.3 $0.0 

High $4.1 $1.4 $0.0 

5.4 Quantified and Monetized Co-pollutant Health and Environmental 

Impacts 

This section describes EPA’s analysis of the co-pollutant health and environmental 

impacts that can be expected to occur as a result of this renewable fuels proposal throughout the 

period from initial implementation through 2030. GHG emissions are predominantly the 

byproduct of fossil fuel combustion processes that also produce criteria and hazardous air 

pollutants. The fuels that are subject to the proposed standard are also significant sources of 

mobile source air pollution such as direct PM, NOx, VOCs and air toxics. The proposed 

standard would affect exhaust and evaporative emissions of these pollutants from vehicles and 

equipment. The proposal would also affect emissions from upstream sources such as fuel 

production, storage, and distribution and agricultural emissions. Any decrease or increase in 

ambient ozone, PM2.5, and air toxics associated with the proposal would impact human health in 

the form of avoided or incurred premature deaths and other serious human health effects, as well 

as other important public health and welfare effects. 

As can be seen in Chapter 3, we estimate that the proposal would lead to both increases 

and decreases in criteria and air toxic pollutant emissions. Making predictions about human 

health and welfare impacts based solely on emissions changes, however, is extremely difficult. 

Full-scale photochemical modeling is necessary to provide the needed spatial and temporal detail 

to more completely and accurately estimate the changes in ambient levels of these pollutants. 

EPA typically quantifies and monetizes the PM- and ozone-related health and environmental 

impacts in its regulatory impact analyses (RIAs) when possible. However, we were unable to do 

so in time for this proposal. EPA attempts to make emissions and air quality modeling decisions 

early in the analytical process so that we can complete the photochemical air quality modeling 

and use that data to inform the health and environmental impacts analysis. Resource and time 

constraints precluded the Agency from completing this work in time for the proposal. EPA will, 

however, provide a complete characterization of the health and environmental impacts, both in 

terms of incidence and valuation, for the final rulemaking. 

This section explains what PM- and ozone-related health and environmental impacts EPA 

will quantify and monetize in the analysis for the final rules. EPA will base its analysis on peer696 
 

 

reviewed studies of air quality and health and welfare effects and peer-reviewed studies of the 

monetary values of public health and welfare improvements, and will be consistent with benefits 

analyses performed for the recent analysis of the proposed Ozone NAAQS and the final PM 

NAAQS analysis.ZZZZZZZZZZZZ,AAAAAAAAAAAAA These methods will be described in detail in the 

RIA prepared for the final rule. 

Though EPA is characterizing the changes in emissions associated with toxic pollutants, 

we will not be able to quantify or monetize the human health effects associated with air toxic 

pollutants for either the proposal or the final rule analyses. This is primarily because available 

tools and methods to assess air toxics risk from mobile sources at the national scale are not 

adequate for extrapolation to benefits assessment. In addition to inherent limitations in the tools 

for national-scale modeling of air quality and exposure, there is a lack of epidemiology data for 

air toxics in the general population. For a more comprehensive discussion of these limitations, 

please refer to the final Mobile Source Air Toxics rule.BBBBBBBBBBBBB Please refer to Chapter 3 

for more information about the air toxics emissions impacts associated with the proposed 

standard. 

5.4.1 Human Health and Environmental Impacts 

To model the ozone and PM air quality benefits of the final rules, EPA will use the 

Community Multiscale Air Quality (CMAQ) model (see Chapter 3 of the RIA for a description 

of the CMAQ model). The modeled ambient air quality data will serve as an input to the 

Environmental Benefits Mapping and Analysis Program (BenMAP).CCCCCCCCCCCCC BenMAP is 

a computer program developed by EPA that integrates a number of the modeling elements used 

in previous RIAs (e.g., interpolation functions, population projections, health impact functions, 

valuation functions, analysis and pooling methods) to translate modeled air concentration 

estimates into health effects incidence estimates and monetized benefits estimates. 

Table 5.4.1-1 lists the co-pollutant health effect exposure-response functions (PM2.5 and 

ozone) we will use to quantify the co-pollutant incidence impacts associated with the final 

standards. 

ZZZZZZZZZZZZ U.S. Environmental Protection Agency. July 2007. Regulatory Impact Analysis of the Proposed 

Revisions to the National Ambient Air Quality Standards for Ground-Level Ozone. Prepared by: Office of Air and 

Radiation. EPA-452/R-07-008. 

AAAAAAAAAAAAA U.S. Environmental Protection Agency. October 2006. Final Regulatory Impact Analysis (RIA) for 

the Proposed National Ambient Air Quality Standards for Particulate Matter. Prepared by: Office of Air and 

Radiation. 

BBBBBBBBBBBBB U.S. EPA. 2007. Control of Hazardous Air Pollutants from Mobile Sources – Regulatory Impact 

Analysis. Assessment and Standards Division. Office of Transportation and Air Quality. EPA420R-07-002. 

February. 

CCCCCCCCCCCCC Information on BenMAP, including downloads of the software, can be found at 

http://www.epa.gov/ttn/ecas/ benmodels.html. 

697 
 

 

 

Table 5.4.1-1. 

Health Impact Functions Used in BenMAP to Estimate Impacts of PM2.5 and Ozone 

Reductions 

Endpoint Pollutant Study Study Population 

Premature Mortality 

Premature mortality – daily time 

series 

O3 Multi-city 

Bell et al (2004) – Non-accidental 

Huang et al (2005) - Cardiopulmonary 

Schwartz (2005) – Non-accidental 

Meta-analyses: 

Bell et al (2005) – All cause 

Ito et al (2005) – Non-accidental 

Levy et al (2005) – All cause 

All ages 

Premature mortality —cohort 

study, all-cause 

PM2.5 Pope et al. (2002) 

Laden et al. (2006) 

>29 years 

>25 years 

Premature mortality, total 

exposures 

PM2.5 Expert Elicitation (IEc, 2006) >24 years 

Premature mortality — all-cause PM2.5 Woodruff et al. (1997) Infant (<1 year) 

Chronic Illness 

Chronic Bronchitis PM2.5 Abbey et al. (1995) >26 years 

Nonfatal heart attacks PM2.5 Peters et al. (2001) Adults (>18 years) 

Hospital Admissions 

Respiratory O3 Pooled estimate: 

Schwartz (1995) - ICD 460-519 (all 

resp) 

Schwartz (1994a; 1994b) - ICD 480­

486 (pneumonia) 

Moolgavkar et al. (1997) - ICD 480­

487 (pneumonia) 

Schwartz (1994b) - ICD 491-492, 494­

496 (COPD) 

Moolgavkar et al. (1997) – ICD 490­

496 (COPD) 

>64 years 

Burnett et al. (2001) <2 years 

PM2.5 Pooled estimate: 

Moolgavkar (2003)—ICD 490-496 

(COPD) 

Ito (2003)—ICD 490-496 (COPD) 

>64 years 

PM2.5 Moolgavkar (2000) – ICD 490-496 

(COPD) 

20-64 years 

PM2.5 Ito (2003) – ICD 480-486 (pneumonia) >64 years 

PM2.5 Sheppard (2003) – ICD 493 (asthma) <65 years 

Cardiovascular PM2.5 Pooled estimate: 

Moolgavkar (2003)—ICD 390-429 (all 

Cardiovascular) 

Ito (2003)—ICD 410-414, 427-428 

(ischemic heart disease, dysrhythmia, 

heart failure) 

>64 years 

PM2.5 Moolgavkar (2000)—ICD 390-429 (all 

Cardiovascular) 

20-64 years 

Asthma-related ER visits O3 Pooled estimate: 

Jaffe et al (2003) 

Peel et al (2005) 

5–34 years 

All ages 

All ages 

698 
 

 

 

 

 

 

 

 

Endpoint Pollutant Study Study Population 

Wilson et al (2005) 

PM2.5 Norris et al. (1999) 0-18 years 

Other Health Endpoints 

Acute bronchitis PM2.5 Dockery et al.(1996) 8-12 years 

Upper respiratory symptoms PM2.5 Pope et al. (1991) Asthmatics, 9-11 

years 

Lower respiratory symptoms PM2.5 Schwartz and Neas (2000) 7-14 years 

Asthma exacerbations PM2.5 Pooled estimate: 

Ostro et al. (2001) (cough, wheeze and 

shortness of breath) 

Vedal et al. (1998) (cough) 

6-18 years 

Work loss days PM2.5 Ostro (1987) 18-65 years 

School absence days O3 Pooled estimate: 

Gilliland et al. (2001) 

Chen et al. (2000) 

5-17 years 

Minor Restricted Activity Days 

(MRADs) 

O3 Ostro and Rothschild (1989) 18-65 years 

PM2.5 Ostro and Rothschild (1989) 18-65 years 

Endpoint Pollutant Study Study Population 

Premature Mortality 

Premature mortality – daily time 

series 

O3 Multi-city 

Bell et al (2004) – Non-accidental 

Huang et al (2005) - Cardiopulmonary 

Schwartz (2005) – Non-accidental 

Meta-analyses: 

Bell et al (2005) – All cause 

Ito et al (2005) – Non-accidental 

Levy et al (2005) – All cause 

All ages 

Premature mortality —cohort 

study, all-cause 

PM2.5 Pope et al. (2002) 

Laden et al. (2006) 

>29 years 

>25 years 

Premature mortality, total 

exposures 

PM2.5 Expert Elicitation (IEc, 2006) >24 years 

Premature mortality — all-cause PM2.5 Woodruff et al. (1997) Infant (<1 year) 

Chronic Illness 

Chronic Bronchitis PM2.5 Abbey et al. (1995) >26 years 

Nonfatal heart attacks PM2.5 Peters et al. (2001) Adults (>18 years) 

Hospital Admissions 

Respiratory O3 Pooled estimate: 

Schwartz (1995) - ICD 460-519 (all 

resp) 

Schwartz (1994a; 1994b) - ICD 480­

486 (pneumonia) 

Moolgavkar et al. (1997) - ICD 480­

487 (pneumonia) 

Schwartz (1994b) - ICD 491-492, 494­

496 (COPD) 

Moolgavkar et al. (1997) – ICD 490­

496 (COPD) 

>64 years 

Burnett et al. (2001) <2 years 

PM2.5 Pooled estimate: 

Moolgavkar (2003)—ICD 490-496 

(COPD) 

Ito (2003)—ICD 490-496 (COPD) 

>64 years 

699 
 

 

 

 

 

 

 

 

 

Endpoint Pollutant Study Study Population 

PM2.5 Moolgavkar (2000) – ICD 490-496 

(COPD) 

20-64 years 

PM2.5 Ito (2003) – ICD 480-486 (pneumonia) >64 years 

PM2.5 Sheppard (2003) – ICD 493 (asthma) <65 years 

Cardiovascular PM2.5 Pooled estimate: 

Moolgavkar (2003)—ICD 390-429 (all 

Cardiovascular) 

Ito (2003)—ICD 410-414, 427-428 

(ischemic heart disease, dysrhythmia, 

heart failure) 

>64 years 

PM2.5 Moolgavkar (2000)—ICD 390-429 (all 

Cardiovascular) 

20-64 years 

Asthma-related ER visits O3 Pooled estimate: 

Jaffe et al (2003) 

Peel et al (2005) 

Wilson et al (2005) 

5–34 years 

All ages 

All ages 

PM2.5 Norris et al. (1999) 0-18 years 

Other Health Endpoints 

Acute bronchitis PM2.5 Dockery et al.(1996) 8-12 years 

Upper respiratory symptoms PM2.5 Pope et al. (1991) Asthmatics, 9-11 

years 

Lower respiratory symptoms PM2.5 Schwartz and Neas (2000) 7-14 years 

Asthma exacerbations PM2.5 Pooled estimate: 

Ostro et al. (2001) (cough, wheeze and 

shortness of breath) 

Vedal et al. (1998) (cough) 

6-18 yearsa 

Work loss days PM2.5 Ostro (1987) 18-65 years 

School absence days O3 Pooled estimate: 

Gilliland et al. (2001) 

Chen et al. (2000) 

5-17 yearsb 

Minor Restricted Activity Days 

(MRADs) 

O3 Ostro and Rothschild (1989) 18-65 years 

PM2.5 Ostro and Rothschild (1989) 18-65 years a

 The original study populations were 8 to 13 for the Ostro et al. (2001) study and 6 to 13 for the Vedal et al. (1998) 

study. Based on advice from the Science Advisory Board Health Effects Subcommittee (SAB-HES), we extended 

the applied population to 6 to 18, reflecting the common biological basis for the effect in children in the broader age 

group. See: U.S. Science Advisory Board. 2004. Advisory Plans for Health Effects Analysis in the Analytical Plan 

for EPA’s Second Prospective Analysis –Benefits and Costs of the Clean Air Act, 1990—2020. EPA-SABCOUNCIL-ADV-04-004. See also National Research Council (NRC). 2002. Estimating the Public Health Benefits 

of Proposed Air Pollution Regulations. Washington, DC: The National Academies Press. 

b

 Gilliland et al. (2001) studied children aged 9 and 10. Chen et al. (2000) studied children 6 to 11. Based on 

recent advice from the National Research Council and the EPA SAB-HES, we have calculated reductions in school 

absences for all school-aged children based on the biological similarity between children aged 5 to 17.5.4.2 

5.4.2 Monetized Impacts 

Table 5.4.2-1 presents the monetary values we will apply to changes in the incidence of 

health and welfare effects associated with the final standards. 

700 
 

 

 

 

Table 5.4.2-1. Valuation Metrics Used in BenMAP to Estimate Monetary Benefits 

Valuation 

Endpoint Valuation Method (2000$) 

Premature mortality Assumed Mean VSL $5,500,000 

Chronic Illness

 Chronic Bronchitis WTP: Average Severity $340,482

 Myocardial Infarctions, Nonfatal Medical Costs Over 5 Years. Varies by --- 

age and discount rate. Russell (1998) 

Medical Costs Over 5 Years. Varies by --- 

age and discount rate. Wittels (1990) 

Hospital Admissions

 Respiratory, Age 65+ COI: Medical Costs + Wage Lost $18,353 

 Respiratory, Ages 0-2 COI: Medical Costs $7,741

 Chronic Lung Disease (less COI: Medical Costs + Wage Lost $12,378 

 Asthma) 

 Pneumonia COI: Medical Costs + Wage Lost $14,693 

 Asthma COI: Medical Costs + Wage Lost $6,634 

 Cardiovascular COI: Medical Costs + Wage Lost (20- $22,778 

64) 

COI: Medical Costs + Wage Lost (65- $21,191 

99) 

ER Visits, Asthma	 COI: Smith et al. (1997) $312 

COI: Standford et al. (1999) $261 

Other Health Endpoints 

 Acute Bronchitis WTP: 6 Day Illness, CV Studies $356

 Upper Respiratory Symptoms WTP: 1 Day, CV Studies $25 

 Lower Respiratory Symptoms WTP: 1 Day, CV Studies $16 

 Asthma Exacerbation WTP: Bad Asthma Day, Rowe and $43 

Chestnut (1986) 

Work Loss Days Median Daily Wage, County-Specific --- 

 Minor Restricted Activity Days WTP: 1 Day, CV Studies $51

 School Absence Days Median Daily Wage, Women 25+ $75 

Worker Productivity Median Daily Wage, Outdoor --- 

Workers, County-Specific, Crocker 

and Horst (1981) 

Environmental Endpoints 

 Recreational Visibility WTP: 86 Class I Areas ---

Source: Dollar amounts for each valuation method were extracted from BenMAP version 2.4.5. 

5.4.3 Other Unquantified Health and Environmental Impacts 

In addition to the co-pollutant health and environmental impacts we will quantify for the 

analysis of the final standards (listed in the preceding sections), there are a number of other 

health and human welfare endpoints that we will not be able to quantify because of current 

limitations in the methods or available data. These impacts are associated with emissions of air 

toxics (including benzene, 1,3-butadiene, formaldehyde, acetaldehyde, acrolein, and ethanol), 

ambient ozone, and ambient PM2.5 exposures. For example, we have not quantified a number of 

known or suspected health effects linked with ozone and PM for which appropriate health impact 

functions are not available or which do not provide easily interpretable outcomes (i.e., changes in 

heart rate variability). Additionally, we are currently unable to quantify a number of known 

welfare effects, including reduced acid and particulate deposition damage to cultural monuments 

701 
and other materials, and environmental benefits due to reductions of impacts of eutrophication in 

coastal areas. For air toxics, the available tools and methods to assess risk from mobile sources 

at the national scale are not adequate for extrapolation to benefits assessment. In addition to 

inherent limitations in the tools for national-scale modeling of air toxics and exposure, there is a 

lack of epidemiology data for air toxics in the general population. Table 5.4.3-1 lists these 

unquantified health and environmental impacts. 

702 
Table 5.4.3-1. Unquantified and Non-Monetized Potential Effects 

Pollutant/Effects Effects Not Included in Analysis - Changes in: 

Ozone Healtha	 Chronic respiratory damage 

Premature aging of the lungs 

Non-asthma respiratory emergency room visits 

Exposure to UVb (+/-)d
 

Ozone Welfare Yields for 

-commercial forests 

-some fruits and vegetables
 

-non-commercial crops 

Damage to urban ornamental plants 

Impacts on recreational demand from damaged forest aesthetics 

Ecosystem functions 

Exposure to UVb (+/-) 

PM Healthb	 Premature mortality - short term exposuresc
 

Low birth weight
 

Pulmonary function
 

Chronic respiratory diseases other than chronic bronchitis 

Non-asthma respiratory emergency room visits 

Exposure to UVb (+/-) 

PM Welfare Residential and recreational visibility in non-Class I areas 

Soiling and materials damage
 

Damage to ecosystem functions 

Exposure to UVb (+/-) 

Nitrogen and Sulfate Commercial forests due to acidic sulfate and nitrate deposition 

Deposition Welfare Commercial freshwater fishing due to acidic deposition 

Recreation in terrestrial ecosystems due to acidic deposition 

Existence values for currently healthy ecosystems 

Commercial fishing, agriculture, and forests due to nitrogen deposition 

Recreation in estuarine ecosystems due to nitrogen deposition 

Ecosystem functions 

Passive fertilization 

CO Health Behavioral effects 

Hydrocarbon Cancer (benzene, 1,3-butadiene, formaldehyde, acetaldehyde, ethanol)
 

(HC)/Toxics Healthe	 Anemia (benzene) 

Disruption of production of blood components (benzene)
 

Reduction in the number of blood platelets (benzene) 

Excessive bone marrow formation (benzene) 

Depression of lymphocyte counts (benzene)
 

Reproductive and developmental effects (1,3-butadiene, ethanol) 

Irritation of eyes and mucus membranes (formaldehyde) 

Respiratory irritation (formaldehyde)
 

Asthma attacks in asthmatics (formaldehyde)
 

Asthma-like symptoms in non-asthmatics (formaldehyde) 

Irritation of the eyes, skin, and respiratory tract (acetaldehyde)
 

Upper respiratory tract irritation and congestion (acrolein) 

HC/Toxics Welfaree Direct toxic effects to animals 

Bioaccumulation in the food chain 

Damage to ecosystem function 

Odor 

a

 In addition to primary economic endpoints, there are a number of biological responses that have been associated 

with ozone health effects including increased airway responsiveness to stimuli, inflammation in the lung, acute 

703 
 

 

 

inflammation and respiratory cell damage, and increased susceptibility to respiratory infection. The public health 

impact of these biological responses may be partly represented by our quantified endpoints. 

b

 In addition to primary economic endpoints, there are a number of biological responses that have been associated 

with PM health effects including morphological changes and altered host defense mechanisms. The public health 

impact of these biological responses may be partly represented by our quantified endpoints. 

c While some of the effects of short-term exposures are likely to be captured in the estimates, there may be
 

premature mortality due to short-term exposure to PM not captured in the cohort studies used in this analysis. 

However, the PM mortality results derived from the expert elicitation do take into account premature mortality 

effects of short term exposures. 

d

 May result in benefits or disbenefits. 

e

 Many of the key hydrocarbons related to this rule are also hazardous air pollutants listed in the Clean Air Act. 

Please refer to Chapter 3 for more information about the health and welfare effects associated with air toxics. 

While there will be impacts associated with air toxic pollutant emission changes that 

result from the final standards, we will not attempt to monetize those impacts. This is primarily 

because currently available tools and methods to assess air toxics risk from mobile sources at the 

national scale are not adequate for extrapolation to incidence estimations or benefits assessment. 

The best suite of tools and methods currently available for assessment at the national scale are 

those used in the National-Scale Air Toxics Assessment (NATA). The EPA Science Advisory 

Board specifically commented in their review of the 1996 NATA that these tools were not yet 

ready for use in a national-scale benefits analysis, because they did not consider the full 

distribution of exposure and risk, or address sub-chronic health effects.DDDDDDDDDDDDD While 

EPA has since improved the tools, there remain critical limitations for estimating incidence and 

assessing benefits of reducing mobile source air toxics. EPA continues to work to address these 

limitations; however, we do not anticipate having methods and tools available for national-scale 

application in time for the analysis of the final rules. Please refer to the final Mobile Source Air 

Toxics Rule RIA for more discussion.EEEEEEEEEEEEE 

DDDDDDDDDDDDD Science Advisory Board. 2001. NATA – Evaluating the National-Scale Air Toxics Assessment for 

1996 – an SAB Advisory. http://www.epa.gov/ttn/atw/sab/sabrev.html. EEEEEEEEEEEEE U.S. EPA. 2007. Control of Hazardous Air Pollutants from Mobile Sources – Regulatory Impact 

Analysis. Assessment and Standards Division. Office of Transportation and Air Quality. EPA420R-07-002. 

February. 

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Chapter 6: Impacts on Water 

6.1 Feedstock Production and Water Quality 

As the production and price of corn and other biofuel feedstocks increase, there may be 

substantial impacts to both water quality and water quantity. To analyze the impact, EPA 

focused on corn production for several reasons. Corn acres have increased dramatically, 20 

percent in 2007 from 2006, an increase of over 15 million additional corn acres for a total of 93.6 

million acres. Over two-thirds of the new corn acres came from soybean production.944 Most of 

the remaining acres came from the conversion to corn from cotton. Although corn acres declined 

seven percent to 87.3 million acres in 2008 due to strong prices for other commodities including 

soybeans, total corn acres remained the second highest since 1946.945 

There are three major pathways for contaminants to reach water from agricultural lands: 

runoff from the land’s surface, subsurface tile drains, or leaching to ground water. A variety of 

management factors influence the potential for contaminants such as fertilizers, sediment, and 

pesticides to reach water from agricultural lands. These factors include nutrient and pesticide 

application rates and application methods, use of conservation practices and crop rotations by 

farmers, and acreage and intensity of tile drained lands. Additional factors outside an 

agricultural producers control include soil characteristics, climate, and proximity to waterbodies. 

6.1.1 Corn Production and Water Quality 

The rapid growth in corn acres may have major implications for water quality. Unlike 

soybeans and other legumes, corn needs large amounts of fertilizer, especially nitrogen fertilizers 

to produce economic yields. Of all current and potential feedstocks for biofuels, corn has the 

greatest application rates of both fertilizer and pesticides per acre and accounts for the largest 

share of nitrogen use among all crops.946 If fertilizers are applied at rates or times when the corn 

cannot use them, they are available to runoff or leach to water. Corn generally utilizes only 40 to 

60 percent of applied nitrogen. The remaining nitrogen is available to leave the field and runoff 

to surface waters, leach into ground water, or volatilize to the air where it can return to water 

through depositional processes. Farmers were expected to apply an additional one million tons 

of nitrogen fertilizer to the 2007 corn crop.947 

Historically, corn has been grown in rotation with other crops such as wheat, hay, oats, 

and especially soybeans. As corn prices increase relative to prices for other crops, farmers chose 

to grow corn every year (continuous corn). Much of the recent growth in corn acres has come 

from reductions in a corn-soybean rotation to continuous corn. Although the amount of losses of 

nitrogen fertilizers to ground and surface water vary, continuous corn loses significantly more 

nitrogen annually than a corn-soybean rotation.948 In 2005, the last year for which data is 

available, the U.S. average nitrogen fertilization rate for corn was 138 pounds per acre. For 

soybeans the average rate was 16 pounds per acre.949 Soybeans fix nitrogen, so they do not 

require as much fertilizer for adequate growth. 
 

Continuous corn may have additional impacts on the rates of fertilizer and pesticide use. 

Continuous corn has lower yields per acre than corn grown in rotation. In response, farmers may 

add higher rates of nitrogen fertilizer to try to match yields of corn grown in rotation. 

Alternatively, if farmers maintain fertilization rates with these reduced yields, the amount of 

unused nutrients will increase and eventually be lost to the environment. Growing continuous 

corn also increases population densities of pests such as corn rootworm. Farmers may increase 

use of pesticides to control these pests. Total corn herbicide use may also increase due to the 

additional corn acres, especially for atrazine, the most commonly used herbicide on corn. 

There are potential toxicity concerns with volatilization of pesticide active ingredients,950 

in addition to concerns with contamination of foods and drinking water. Furthermore, raising 

acreage under corn production will increase the quantity of pesticide products in use. Further 

assessment is necessary to determine whether there is the potential for adverse human health 

effects from any increase in pesticide use associated with increased domestic corn production. 

The most commonly used types of pesticides associated with corn production and storage 

largely belong to two broad use categories, herbicides and insecticides. The majority of the more 

common corn herbicide products presently on the market contain an organochlorine-type (OC) 

active ingredient (a.i.). For the most part, OC herbicides inhibit cell division and growth while a 

subgroup of these products, the atrazine-containing OC herbicides, inhibit plant photosynthesis. 

Another type of common corn herbicide, the phosphonoglycene or glyphosate–containing 

organophosphate (OP) herbicides, inhibit protein synthesis in plants. Several of the common 

corn herbicide compounds, such as acetochlor, carbaryl and alachlor, are classified by EPA as 

known or likely human carcinogens and oral exposure to some of these a.i. compounds at high 

enough levels has resulted in adverse health effects, on organs such as the liver or kidney in 

animals.951, 952, 953 

The majority of common corn insecticides are split fairly evenly between OP- and 

carbamate-type a.i. compounds, with the top selling corn insecticide products, by sales of a.i. by 

weight, generally contain methomyl. Methomyl is an N-methyl-carbamide compound which 

inhibits the acetylcholinesterase enzyme, causing neurotoxicity in both insects and humans.954 It 

is classified by EPA as an E/unlikely human carcinogen955 and its use is regulated as a 

compound highly toxic to most aquatic and land animals. 

High corn prices may encourage farmers to grow corn on land where row crops are not 

currently grown. If land is not in row crop production, it generally is an indication that the land 

is marginal for row crop production though the land may still be used for agriculture, such as 

pasture land. Typically, agricultural producers apply far less fertilizer and pesticide on pasture 

land than land in row crops. Corn yield on these marginal lands will be lower, limiting nutrient 

uptake and causing a higher percentage of nutrients under standard fertilization rates to be 

underutilized and ultimately lost to the environment. However since nitrogen fertilizer prices are 

tied to natural gas prices, fertilizer costs have increased significantly. According to U. S. 

Department of Agriculture (USDA) Economic Research Service, nitrogen fertilizer prices 

increased 44.5 percent from July 2007 to July 2008.956 It is unclear how agricultural producers 

responded to these increases in both corn and fertilizer prices. 

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EPA does not have sufficient data to determine the impact of high corn prices on the 

fertilization rates of traditional corn acres or other agricultural land brought into corn production. 

Agricultural producers may increase nitrogen fertilizer application rates on all corn acres to 

increase yields or the higher cost and more efficient of the fertilizer may limit rate increases. 

The USDA National Agricultural Statistics Service has announced that it will discontinue its 

national Agriculture Chemical Use reports, collected since 1990, the only survey of its kind. 

Therefore, it will be very difficult to obtain future information on fertilizer and pesticide 

application rates. 

Tile drains are another important factor in determining the losses of fertilizer from 

cropland. Tile drainage consists of subsurface tiles, pipes, or drainage ditches that move water 

from wet soils to surface waters quickly so crops can be planted. Tile drainage has allowed large 

expanses of historic wetland soils to become productive agriculture lands. However, the tile 

drains also move fertilizers and pesticides more quickly to surface waters without any of the 

attenuation that would occur if these contaminants moved through soils or wetlands. The highest 

proportion of tile drainage occurs in the Upper Mississippi and the Ohio-Tennessee River 

basins.957 Significantly increased use of conservation practices such as improved drainage 

management and constructed wetlands are necessary to reduce high nitrogen loadings from tile 

drained lands. 

6.1.2 Impact on Farm Bill Conservation Programs 

The increase in corn production and prices may also have significant impacts on 

conservation programs funded by the USDA. USDA funds a variety of voluntary programs to 

help agricultural producers implement conservation practices on their operations. These 

programs fall into two basic categories: land retirement and working lands. 

USDA’s largest land retirement program and its largest conservation program is the 

Conservation Reserve Program (CRP). Under CRP farmers receive annual rental payments 

under 10- to 15- year contracts to take land out of agricultural production and plant grasses or 

trees on those acres. Generally farmers put land into CRP because it is not as productive and has 

other characteristics that make the cropland more environmentally sensitive, such as high erosion 

rates. The 2008 Farm Bill (Food, Conservation and Energy Act of 2008) lowered the cap on 

CRP acres from 39.2 million acres to 32 million acres. Prior to the passage of the new farm bill, 

farmers had already not renewed their contracts on over two million acres of CRP in response to 

higher crop prices. USDA expects another 4.6 million acres to come out of CRP between 2007 

and 2010, 1.4 million acres in major corn producing states.958 

CRP acres provide valuable environmental benefits both for water quality and for wildlife 

habitat. CRP is an important component of rare grassland habitats in the Midwest and Great 

Plains.959 CRP payments are based on the average agricultural land rental rates in the area. As 

land values increase due to increase in crop prices, CRP payments are not keeping up with the 

higher land rental rates. Farmland in Iowa increased an average of 18 percent in 2007 from 2006 

prices.960 Midwestern states, where much of the nation’s corn is grown, tend to have 

reenrollment rates lower than the national average. 

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The largest USDA conservation program on working lands is the Environmental Quality 

Incentives Program (EQIP). About $1 billion is given to farmers annually to implement 

conservation practices on their farms. Farmers are paid a percentage of the cost of installing the 

practices, generally ranging from 50 to 90 percent. Conservation practices encompass a wide 

range that can have a significant impact on pollutants reaching ground or surface water from 

crop production. EQIP cost-shares with farmers for important practices such as nutrient 

management, cover crops, livestock manure storage, and riparian buffers. Like CRP, high corn 

prices may have an impact on the willingness of agricultural producers to participate in EQIP. 

Producers may require higher payments to offset potential loss of profits through implementation 

of conservation practices. 

The effectiveness of agricultural conservation practices in controlling runoff and/or 

leaching of nutrients, sediment, and pesticides at the field level has been established by 

numerous scientific studies across many geographic areas. However, the usefulness of these 

practices in achieving water quality goals is dependent on their placement within watersheds. To 

most effectively protect water quality, conservation practices should be targeted to the most 

vulnerable areas of watersheds. Conservation practices designed to meet wildlife goals will need 

different targeting mechanisms to ensure adequate habitat. USDA through the Conservation 

Effects Assessment Project (CEAP) is trying to evaluate the effectiveness of controlling 

pollution from agricultural lands at the watershed level.FFFFFFFFFFFFF In order to ensure that Farm 

Bill conservation programs meet their environmental quality goals, the EPA’s Science Advisory 

Board report to the Gulf of Mexico Task Force (SAB) also recommends implementing the 

practices through competitive bidding to ensure that the highest environmental benefit is 

achieved at the least cost.961 It also warns that voluntary programs without economic incentives 

are unlikely to be effective to control nitrogen and phosphorus, except for a few practices. 

The most cost-effective practices on working lands include: riparian buffers; crop 

rotation; appropriate rate, timing, and method of nutrient application; cover crops; and, on tiledrained lands, treatment wetlands and controlled drainage. These practices have significant 

water pollution reduction benefits that vary based on the site-specific conditions and on the 

implementation and operation and maintenance of the practice. For example, controlled 

drainage can reduce nitrogen loads by 30 percent; treatment wetlands by 40 percent to 90 

percent; vegetative buffers by 12 percent to 90 percent. 

6.1.3 Other Agricultural Biofuel Feedstocks 

While corn is the most common feedstock for biofuel production by far, under this 

proposal, in later years other agricultural feedstocks will become increasingly important. These 

feedstocks will have dramatically different impacts on water quality. Biodiesel feedstocks, 

primarily soybeans, as well as cellulosic feedstock such as switchgrass or popular trees are not 

expected to have significant water quality impacts. As noted previously, soybeans require little 

to no additional nitrogen fertilizer. However, soybeans have less residue compared to corn, so 

sediment runoff could be more of a concern, depending on how each crop is managed. 

Switchgrass may be a more favorable biofuels crop for reducing water impacts. It is a native 

plant which does not require high inputs of fertilizers or pesticides and since it is a perennial 

FFFFFFFFFFFFF See http://www.nrcs.usda.gov/technical/nri/ceap/index.html 

708 
crop, there is limited sediment runoff compared to annual crops. There is very minimal acreage 

of switchgrass grown commercially at the present time, so it is difficult to predict what inputs 

farmers will use to cultivate it. Some concern has been expressed about farmers increasing 

switchgrass fertilizer application rates to dramatically increase yields. 

Corn stover, at the present time, appears to be one of the most viable feedstock for 

cellulosic ethanol, especially in the Corn Belt states. Corn stover is the above ground stalks, 

husks, and corn cobs that remain once the corn grain is harvested. Farmers keep the corn stover 

on their cropland to maintain the productivity of the soil. Corn stover maintains the soil organic 

carbon which has many benefits as a source of nutrients, preventing erosion by wind and water, 

and increasing soil aeration and water infiltration. Wilhelm, et al962 looked at the amount of corn 

stover that could be harvested for biofuel production and still maintain soil carbon. In all the 

soils they evaluated more stover was needed to maintain the soil carbon than for controlling 

erosion. For a more general discussion of cellulosic ethanol production, see Chapter V, Section 

V.B.2. More research is needed to identify the amount of stover that can be removed and retain 

these important productivity and environmental benefits. 

Different conservation systems and conservation practice standards will need to be 

developed and adopted for cellulosic feedstocks, such as corn stove, switchgrass, and trees for 

biofuels production. USDA will need to continue to adjust current standards and develop 

additional standards, where needed, to permit cellulosic feedstocks to be produced and utilized in 

a sustainable manner. 

6.2 Ecological Impacts 

6.2.1 Nutrients 

Nitrogen and phosphorus enrichment due to human activities is one of the leading 

problems facing our nation’s lakes, reservoirs, and estuaries. Nutrient enrichment is also a 

contributing factor to stream degradation. It has negative impacts on aquatic life in streams; 

adverse health effects on humans and domestic animals; aesthetic and recreational use 

impairment; and excessive nutrient input into downstream waterbodies, such as lakes. Excess 

nutrients in streams can lead to excessive growth of phytoplankton (free-floating algae) in slowmoving rivers, periphyton (algae attached to a surface) in shallow streams, and macrophytes 

(aquatic plants large enough to be visible to the naked eye) in all waters. Unsightly filamentous 

algae can impair the aesthetic enjoyment of streams. In more extreme situations, excessive 

growth of aquatic plants can slow water flow in flat streams and canals, interfere with 

swimming, and clog the screens on water intakes of water treatment plants and industries. 

Nutrient enrichment in streams has also been demonstrated to affect animal communities 

in these waterbodies. For example, declines in invertebrate community structure have been 

correlated directly with increases in phosphorus concentration. High concentrations of nitrogen 

in the form of ammonia are known to be toxic to aquatic animals. Excessive levels of algae have 

also been shown to be damaging to invertebrates. Finally, fish and invertebrates will experience 

growth problems and can even die if either oxygen is depleted or pH increases are severe; both 

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of these conditions are symptomatic of eutrophication. As a biologic system becomes more 

enriched by nutrients, different species of algae may spread and species composition can shift; 

however, unless such species shifts cause clearly demonstrable symptoms of poor waterquality—such as fish kills, toxic algae, or very long streamers of filamentous algae—the general 

public is unlikely to be aware of this potential ecological concern. 

Nutrient pollution is widespread. The most widely known examples of significant 

nutrient impacts include the Gulf of Mexico and the Chesapeake Bay. For these two areas alone, 

there are 35 states that contribute the nutrient loadings. There are also known impacts in over 80 

estuaries/bays, and thousands of rivers, streams, and lakes. The significance of this impact has 

led EPA, States, and the public to come together to place an unprecedented priority on public 

partnerships, collaboration, better science, and improved tools to reduce nutrient pollution. 

Virtually every state and territory is impacted by nutrient-related degradation of our 

waterways. All but one state and two territories have waterbodies that are polluted by nutrients. 

States have listed over 10,000 waterbodies that have nutrient and nutrient-related impairments. 

Fifteen states have more than 200 nutrient-related waterbodies each. Reducing nutrient pollution 

is a priority for EPA. 

The Wadeable Streams Assessment provided the first statistically defensible summary of 

the condition of the nation’s streams and small rivers.963 To perform the assessment, EPA, 

states, and tribes collected chemical, physical, and biological data at 1,392 perennial stream 

locations to determine the biological condition of these waters and the primary stressors affecting 

their quality. Research teams collected samples at sites chosen using a statistical design to 

ensure representative results. The results of the analysis provide a clear assessment of the 

biological quality of wadeable, perennial streams and rivers across the country. 

The Wadeable Streams Assessment found that excess total nitrogen is the most pervasive 

biological stressor for the nation. Approximately 32 percent of the nation’s stream length shows 

high concentrations of nitrogen compared to reference conditions. Phosphorus exhibits 

comparable patterns to nitrogen and is the second most-pervasive stressor for the nation’s stream 

length. Streams with relatively high concentrations of nutrients or excess streambed sediments 

are two to four times more likely to exhibit poor biological conditions. 

The National Water Quality Inventory: Report to Congress, prepared under section 

305(b) of the Clean Water Act, summarizes water quality reports submitted by the states and 

territories to EPA. Historically, the National Water Quality Inventories have repeatedly shown 

that nutrients are a major cause of ambient water quality use impairments. In the most recent 

report summarizing the 2002 reports from state, nutrients are identified as the leading cause of 

water pollution in assessed lakes and the second leading cause of pollution in assessed estuaries 

and bays.964 Sediment is the leading cause of pollution in assessed rivers and streams. 

Agriculture is the largest known source of water quality impairment to both assessed rivers and 

streams and lakes and reservoirs. 

6.2.2 Air Deposition of Nitrogen to Water 

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Nitrogen oxide (NOx) emissions from fossil fuel combustion can add to the load of 

nitrogen to waterbodies around the country. Under the high pressure and temperature conditions 

in a vehicle engine, nitrogen and oxygen in the air react to form NOx. Depending on climate and 

other variables, the atmospheric NOx falls back to the ground as rain, snow, fog, or dry 

deposition. NOx is deposited directly on waterbodies or falls on the land and can run off to 

waterbodies. NOx from both stationary sources and vehicles results in significant loadings of 

nitrogen from air deposition to waterbodies around the country965, including the Chesapeake 

Bay966, Long Island Sound967, and Lake Tahoe968. Much of the nitrogen deposition from 

vehicles falls on impervious surfaces, such as roads and parking lots where it runs off into 

streams. Road drainage systems generally channel runoff quickly and accelerate the nitrogen 

loadings downstream. In the Chesapeake region, vehicle exhaust remains the single largest 

source of fossil-fuel derived nitrogen pollution.969 Air deposition of nitrogen accounts for more 

than half of all nitrogen loadings to Lake Tahoe.970 

6.3 Gulf of Mexico 

Production of corn for ethanol may exacerbate existing serious water quality problems in 

the Gulf of Mexico. Nitrogen fertilizer applications to corn are already the major source of total 

nitrogen loadings to the Mississippi River.971 A large area of low oxygen, or hypoxia, forms in 

the Gulf of Mexico every year, often called the “dead zone”. Hypoxia threatens commercial and 

recreational fisheries in the Gulf because fish and other aquatic species cannot live in the low 

oxygen waters. The primary cause of the hypoxia is excess nutrients (nitrogen and phosphorus) 

from the Upper Midwest flowing into the Mississippi River to the Gulf. These nutrients trigger 

excessive algal growth (or eutrophication) resulting in reduced sunlight, loss of aquatic habitat, 

and a decrease in oxygen dissolved in the water. 

The hypoxic zone in 2008 was the second largest since measurements began in 1985 -- 

8,000 square miles, an area larger than the state of Massachusetts, and slightly larger than the 

2007 measurement.972 The average size of the hypoxic zone over the past five years has been 

6,600 square miles. 

The Mississippi River/Gulf of Mexico Watershed Nutrient Task Force’s “Gulf Hypoxia 

Action Plan 2008” lays out two major goals for reducing water quality problems in the 

Mississippi River/Atchafalaya River Basin: 1) reduce the five-year running average areal extent 

of the Gulf of Mexico hypoxic zone to 2,000 square miles by 2015 and 2) implement nutrient 

and sediment reductions to protect public health and aquatic life and reduce negative impacts of 

water pollution. The Gulf of Mexico Action Plan calls for an acceleration of actions to reduce 

the hypoxia in the Gulf. In order to meet these goals, the Action Plan calls for a 45 percent 

reduction in both nitrogen and phosphorus reaching the Gulf.973 EPA’s Science Advisory Board 

(SAB) report to the Task Force said that an additional reduction in nitrogen and phosphorus 

reduction will be necessary as a result of increased corn production for ethanol and climate 

change impacts.974 The SAB also found that the Gulf of Mexico ecosystem appeared to have 

undergone a shift so that now the system is more sensitive to nutrient inputs than in the past and 

inducing a larger response in hypoxia. 

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Under the Gulf Hypoxia Action Plan, “USDA will encourage the increased use of its 

nutrient management standard to minimize nutrient loss from fields to help alleviate the impact 

of increased biofuels production on nutrient loads to the Gulf”.975 The nutrient management 

standard requires farmers to account for all plant-available nutrient sources immediately 

available or rendered available throughout the crop production cycle. 

6.3.1 Nutrient Loads to the Gulf of Mexico 

The U.S. Geological Survey (USGS) has estimated that the spring delivery of nutrients to 

the Gulf of Mexico in 2008 was among the highest since the early 1980s. Spring nutrient 

delivery is one of the main factors that control the size of the hypoxic zone. In relation to the 

long-term spring average, total nitrogen was about 35 to 40 percent higher (817,000 tons) and 

total phosphorus was a record 60 to 85 percent higher (83,000 tons). The large nutrient 

contributions are primarily due to near record-breaking streamflows in spring 2008 in the 

Mississippi River Basin. Streamflows were about 50 percent higher this year compared to the 

long-term spring average flows since about 1980. Nutrient contributions for a given spring vary 

depending on the amount of flow in the Mississippi-Atchafalaya River Basin, as well as average 

stream water nutrient concentrations. 

Alexander, et al. modeled the sources of nutrient loadings to the Gulf of Mexico using the 

USGS SPARROW (spatially referenced regression on watershed attributes) model.976 They 

estimated that agricultural sources contribute more than 70 percent of the delivered nitrogen and 

phosphorus. Corn and soybean production accounted for 52 percent of nitrogen delivery. 

Atmospheric deposition was the second largest nitrogen source at 16 percent. Animal manure on 

pasture and rangeland are the main sources of phosphorus loadings, contributing 37 percent. 

Corn and soybean contributed 25 percent of the phosphorus; other crops 18 percent, and urban 

areas, 12 percent. 

6.3.2 Recent Analyses of Impact of Corn Ethanol Production on Nutrient Loadings to the 

Gulf 

Since over 80 percent of corn grown in the U.S. is produced in the Gulf of Mexico 

watershed, concern has been expressed about the impact on Gulf hypoxia of increasing corn 

production for ethanol. Several recent scientific reports have estimated the water quality impact 

of that increase in corn production. 

Donner and Kucharik modeled increases in nitrogen export to the Gulf as a result of corn 

ethanol volumes increasing from 2007 production levels to 15 billion gallons in 2022.977 They 

concluded that the expansion of corn-based ethanol production could make it almost impossible 

to meet the Gulf of Mexico nitrogen reduction goals without “radical shift” in feed production, 

livestock diet, and management of agricultural lands. The study estimated a mean dissolved 

inorganic nitrogen load increase of 10 to18 percent from 2007 to 2022 to meet the 15 billion 

gallon corn ethanol goal, depending on the rate of corn yield increases and potential efficiency 

increases in the conversion of corn to ethanol. 

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EPA’s Science Advisory Board (SAB) report to the Mississippi River/Gulf of Mexico 

Watershed Task Force estimated the additional annual nitrogen loadings to the Gulf due to the 

increase in corn acres from 78.3 million acres in 2006 to 93.7 million acres in 2013.978 The SAB 

estimated that this scenario will result in an additional national annual loading of almost 300 

million pounds of nitrogen. An estimated 80 percent of that nitrogen loading or 238 million 

pounds will occur in the Mississippi-Atchafalaya River basin and contribute nitrogen to the 

“dead zone” in the Gulf of Mexico. 

USGS is using SPARROW to model water quality impacts in the Upper Mississippi 

River Basin due to increased corn production for ethanol. EPA intends to compare the results of 

the analysis described in the next section with the SPARROW results for the final rule. 

6.4 Upper Mississippi River Basin Analysis 

To provide a quantitative estimate of the impact of this proposal and production of corn 

ethanol generally on water quality, EPA conducted an analysis that focused on agricultural 

production in the Upper Mississippi River Basin (UMRB). The UMRB drains approximately 

189,000 square miles, including large parts of the states of Illinois, Iowa, Minnesota, Missouri, 

and Wisconsin. Small portions of Indiana, Michigan, and South Dakota are also within the 

basin. EPA selected the UMRB because it is representative of the many potential issues 

associated with ethanol production, including its connection to major water quality concerns 

such as Gulf of Mexico hypoxia, large corn production, and numerous ethanol production plants. 

In 2005, there were approximately 23.6 million acres of corn in the UMRB. About 75 

percent of ethanol production is expected to be in the states in the Corn Belt region.979 More 

discussion about corn production can be found in Section 1.5.1. On average the UMRB 

contributes about 39 percent of the total nitrogen loads and 26 percent of the phosphorus loads to 

the Gulf of Mexico.980 The Ohio/Tennessee River Basin is the highest contributor of nitrogen 

loads to the Gulf at 41 percent. The high percentage of nitrogen from these two basins is 

primarily due to the large inputs of fertilizer for agriculture and the extensive systems of tile 

drains. According to USGS, nitrogen loads to the Gulf ranged from 810,000 metric tons to 2.2 

million metric tons between 1985 and 2005. Phosphorus loads to the Gulf ranged from 80,700 

metric tons to 180,000 metric tons during that same 20- year period.981 Although nitrogen inputs 

to the UMRB in recent years is fairly level, there is a 21 percent decline in loads. The Science 

Advisory Board report attributes this decline to higher amount of nitrogen removed during 

harvest, due to higher crop yields.982 However, most of the reduction in the spring was from 

nitrogen forms other than nitrate, an important nitrogen form fueling the algal growth which 

leads to hypoxia.983 For the same period phosphorus inputs increased 12 percent. 

In 2005, the U.S. produced approximately 3.9 billion gallons of ethanol, mostly from 

corn kernels. Corn-based ethanol production is expected to reach at least 15 billion gallons in 

order for industry to comply with the RFS2 standards. Of the potential crops for biofuels 

production, corn has the highest rates of fertilizer and pesticide application, leading to the 

concern that higher corn production will result in increased loading of nutrients, pesticides, and 

sediment to waterbodies, including major rivers and estuaries. This analysis examines the 

713 
impact of total production of corn-based ethanol in 2010, 2015, 2020, and 2022 from an ethanol 

production baseline of approximately four billion gallons in 2005. 

6.4.1 SWAT Model 

EPA selected the SWAT (Soil and Water Assessment Tool) model to assess nutrient 

loads from changes in agricultural production in the UMRB. Models are the primary tool that 

can be used to predict future impacts based on alternative scenarios. SWAT is a physical process 

model developed to quantify the impact of land management practices in large, complex 

watersheds. SWAT, primarily developed by USDA’s Agricultural Research Service and the 

Texas A & M University Blackland Research and Extension Center, is a public domain model. 

EPA determined that SWAT was the most appropriate model to use for this analysis 

because it has been widely used and validated in watersheds both nationally and 

internationally.984 SWAT has been applied extensively to support water quality and Total 

Maximum Daily Load (TMDL) planning throughout the United States. SWAT is a basin-scale 

continuous simulation model that operates on a daily time step and is designed to predict the 

nonpoint source loadings and resulting water quality impacts of water, sediment, and agricultural 

chemicals (nutrients and pesticides) from a watershed. The model can assess a wide variety of 

impacts of alternative management practices and land use changes. The model is physically 

based, computationally efficient, and capable of continuous simulations over long periods of 

time, ranging from days to years to decades. Major model components include weather, 

hydrology, erosion/sedimentation, soil temperature, plant growth, nutrients, pesticides, bacteria, 

agricultural management, stream routing and pond/reservoir routing. 

SWAT has several very important strengths that enabled EPA to develop a robust 

representation of the hydrology and water quality of the UMRB: 

1) Watersheds can be modeled to evaluate the relative impact of changes in 

management practices, climate, and vegetation on water quality or other variables of 

interest; 

2) SWAT uses readily available inputs commonly available from various 

government agencies; 

3) It can simulate crop and plant communities and provide crop yield and plant 

biomass, essential to estimate past trends and project accurately into the future; 

4) Simulation of very large basins or a variety of management strategies can be 

performed expeditiously; 

5) Long-term impacts spanning several decades can be studied. Time- and 

climate-variable pollutant contributions can be simulated along with the impact on 

downstream water bodies spanning several decades; and 

714 
 

6) The model code has been validated on hundreds of basins throughout the 

United States and abroad. 

In addition, prior applications of SWAT for hydrology and nutrient simulation in the 

UMRB had been completed and were available as a starting foundation for the modeling efforts 

and focus of this study.985 986 Further technical information regarding SWAT can be found at: 

http://www.brc.tamus.edu/swat. 

6.4.1.1 Baseline Model Scenario 

In order to assess alternative potential future conditions within the UMRB, such as 

alternative levels of increased corn production, EPA developed a SWAT model of a baseline 

scenario for current conditions to which the results of future condition model runs can be 

compared. This analysis evaluated the impact of increased corn production for biofuels by 

establishing a baseline prior to the rapid increase in corn acres planted in 2007. EPA used a 

different baseline for this analysis than the reference case based on the AEO projections used in 

most of the other analyses in this proposal. EPA intends to conduct additional analyses for the 

final rule that will compare the reference case biofuel volumes to the RFS2 volumes. 

For simplicity’s sake, we refer to the baseline as 2005, but like most water quality 

modeling, we had to use a range of data sets for the baseline scenario inputs. As noted above 

corn acres did not increase significantly until the 2007 crop year. In developing the baseline 

scenario, it was necessary to select a target year, or window of years, that represent the 

conditions on the watershed. For this study the year 2005 was selected as the mid-point of the 

target period for baseline conditions. As with most models of this scale, it was not possible to 

have all of the data sources come from the exact same time period. It is a common modeling 

practice to combine the best available data sources for model development in an attempt to 

characterize the baseline condition within a short time window or period. The majority of the 

data sources were from the years 2000 through 2006. In addition, selected assumptions about the 

baseline scenario were made using 2005 as the reference year. In particular, the baseline values 

for average corn yield (150 bushels per acre) and the percentage of corn producing ethanol (12%, 

from the RFS1 preamble of May 2007) were based on the year 2005. In reality, the baseline 

scenario represents watershed conditions within a two to three year period centered on the target 

year of 2005. 

Since one of the driving forces in the SWAT model is the water balance, climate data is 

key to accurately predicting the movement of nutrients and sediment. SWAT was applied (i.e. 

calibrated) to the UMRB using weather data from the NRCS climatic data center for a 40-year 

period from 1960 to 2001 and flow and water quality data from 13 USGS gauges on the 

mainstem of the Mississippi River, spatially distributed from the upper reaches in Minnesota and 

Wisconsin to the UMRB outlet below Grafton, Illinois. In addition, the weather data has been 

spatially interpolated to assign one weather station per subwatershed. 

To establish the land use for the baseline scenario, SWAT was setup on 131 

subwatersheds [8-digit Hydrologic Unit Code (HUC)] for the entire UMRB using the 2001 

National Land Cover Data (NLCD)987 and Cropland Data Layer (CDL)988. The CDL contains 

715 
 

crop specific digital data layers, suitable for us in geographic information system applications. 

The CDL program focuses on classifying corn/soybean/rice/cotton agricultural regions in many 

of the Midwestern and Mississippi delta states using remote-sengin imagery and on-the-ground 

monitoring. The USDA-NRCS STATSGO provided the soils data for the entire analyses. The 

primary input data is the USDA 1997 National Resource Inventory (NRI), which provided land 

use, soil, and data on management practices on the land.989 1997 is the most current year for 

which this data is available. 

In addition, information from the Conservation Tillage Information Center and USDANASS Census of Agriculture 2002/1997 were used to identify the cropping rotation and 

management practices for the agricultural land areas by these same 131 subwatersheds. Based 

on the management information at this level, each sub-watershed was assigned appropriate 

management and tillage practices. 

Drainage tiles are one of the critical man-made hydrology structures that changes the 

natural hydrological cycle significantly at both surface and subsurface (lateral flow) levels. 

There are no clear records of where the tiles are within the UMRB, other than a few research 

articles that attempted to estimate the location and extent of the tile drainage coverage. In this 

study, similar literature values were used to estimate and identify the areas that have the tile 

system to drain the excess water and nutrients in a timely manner. First, the STATSGO database 

was used to identify the very poorly drained soils, somewhat poorly drained soils, and poorly 

drained soils. Then, slope and land use maps were overlaid on these poorly drained soils to 

identify the potential tile drainage system. Only slopes <1% and agricultural land uses were 

identified as areas that may potentially be served with tile drainage system. 

The tillage practice information in the UMRB was obtained at the county level from 

Conservation Technology Information Center990. There are five major tillage types. Three of 

them (no-tillage, ridge-tillage, and mulch-tillage) belong to conservation tillage, and the other 

two types of tillage (reduced-tillage and intensive-tillage) are non-conservation tillage. The 

county acreages of this tillage information were overlaid on 8-digit HUCs to estimate the percent 

of each tillage practices by crop within each HUC. 

To estimate nutrient applications on cropland, we started by estimating the livestock and 

the amount of manure produced. The livestock numbers came from the agricultural statistics for 

each county based on the 2002 Census of Agriculture for each 8-digit HUC. (Only cattle and 

hogs numbers were used since they are the dominant livestock types in the UMRB.) Then, the 

manure production of each 8-digit HUC was obtained through multiplying the number of cattle 

and hogs and the manure production rates as outlined in ASABE, 2005.991 If the total amount of 

the manure production exceeded 20 percent of the estimated total fertilizer application in one 

HUC, manure application and chemical fertilizer application was used as SWAT model input to 

simulate in that HUC. The manure was applied to only those areas that are agricultural land use, 

even during rotation. For example, only hay, corn, and row crops get manure application, not 

legume crops such as alfalfa or soybean. So, if an area had a corn and soybean rotation, then 

only during corn growing period the manure was applied. Even though manure was applied, 

chemical fertilizer was used to supplement the manure application where and when needed. In 

areas where the manure was not applied, chemical fertilizer was applied to grow the agricultural 

716 
 

crops. Chemical nitrogen fertilizer at applied at 1.3 times the amount of nitrogen taken off at 

harvest. 

The 42-year SWAT model runs were performed and the results analyzed to establish 

runoff, sediment, nitrogen, and phosphorous loadings from each of the 131 8-digit HUC 

subwatersheds and the larger 4-digit subbasins, along with the total outflow from the UMRB and 

at the various USGS gage sites distributed along the Mississippi River mainstem. These results 

provided the Baseline Scenario model values to which the future alternatives are compared. 

The current national average for corn yield of 150 bushels per acre (bu/ac) was used to 

establish baseline yield levels. The baseline average yield for the UMRB was established at 131 

bushels per acre. This baseline yield is due to the significant amount of crop area in northern 

states where yield values are lower than the national average. 

6.4.1.2 Alternative Scenarios 

SWAT scenario analyses were performed for the years 2010, 2015, and 2022 with corn 

ethanol volumes of 12 billion gallons a year (BGY) for 2010, and 15 BGY for both 2015 and 

2022. These volumes were adjusted for the UMRB based on a 42.3 percent ratio of ethanol 

production capacity within the UMRB compared to national capacity. This fraction was 

determined by overlaying a coverage of nationwide ethanol plants with a coverage of the 

UMRB. Production from ethanol plants within the study area were totaled and then divided by 

the nationwide production. Both current production and planned expansion were included in the 

totals. Ethanol location and production information were taken from the Renewable Fuels 

Association table of ethanol refinery locations in April 2008.992 The resulting UMRB ethanol 

production goals were converted into the corresponding required corn production acreage, i.e. 

the extent of corn acreage needed to meet those ethanol production goals. More discussion about 

corn production can be found in Section 1.5.1 

The SWAT model was run with the available input climate record, 1960-2001, with the 

model run under conditions of the increased corn production and yields noted above. Separate 

model runs were performed for each of the three projection years, and the model results were 

analyzed to provide loadings for comparison with the baseline loadings. 

6.4.1.2.1 Corn 

Increases in corn yield were built into the future scenarios, with an annual increase of 

1.23 percent. This produced yield increases to 139 bushels per acre (bu/ac) (2010), 148 bu/ac 

(2015) and 162 bu/ac (2022). Thus, after the 2015 scenario, these yield increases translated into 

less corn acreage being needed to meet the ethanol production goals. Corn acres in the UMRB 

grew from 23.6 million acres in 2005 to 34.1 million acres in 2010 to 36.3 million acres in 2015, 

an increase of 54 percent. In 2022, corn dropped to 34.6 million acres. 

6.4.1.2.2 Nitrogen 

717 
Total nitrogen loads increased by 5.5 percent from the baseline to the 2010 scenario. 

Scenarios beyond 2010 then showed decreasing total nitrogen loads with the 2022 scenario 

showing less than a one percent increase over the baseline. It is important to note that these 

results only estimate loadings from the Upper Mississippi River basin, not the entire Mississippi 

River watershed. As noted earlier, the UMRB contributes about 39 percent of the total nitrogen 

loads and 26 percent of total phosphorus loads to the Gulf of Mexico. This modeled decrease in 

nitrogen loads is likely attributed to the increased yield production of future scenarios, resulting 

in greater plant uptake of nitrogen. Additionally, less corn area was needed for the 2020 and 

2022 scenarios due to the increased yield values. 

Approximately 24-25 percent of nitrogen leaving agricultural fields was either taken up 

by aquatic plants or volatilized before reaching the outlet of the UMRB at Grafton, Illinois. 

Even though much of the nitrogen that is volatilized from streams and rivers and near-coastal 

waters is removed from the total loading to water, it is not necessarily eliminated as an 

environmental concern. Conversion of the nitrate to nitrogen gas through denitrification is 

generally an incomplete chemical process. Five percent or more of the nitrogen can be converted 

to nitrous gas, a powerful greenhouse gas that is 300 times the climate-warming potential of 

carbon dioxide, the major greenhouse gas of environmental concern. Thus, a water pollutant 

becomes an air pollutant until it is either captured through biological sequestration or converted 

fully to elemental nitrogen. 

6.4.1.2.3 Phosphorus 

The scenarios showed an increase in phosphorous loads at a slightly lower percentage 

than nitrogen 

6.4.1.2.4 Sediment 

Total sediment outflow showed very little change (less than one percent) over all 

scenarios. This is primarily due to the corn being modeled as a well-managed crop in terms of 

sediment loss, primarily due to the corn stover remaining on the fields following harvest. 

Table 6.4-1. 

 Changes in nutrient loadings within the Upper Mississippi River Basin 

(from the 2005 Baseline Scenario)

 2005 

Baseline 2010 2015 2020 2022 

Nitrogen 1897.0 + 5.1% + 4.2% + 2.2% +1.6% 

million lbs 

Phosphorus 176.6 + 2.3% + 1.1% + 0.6% + 0.4% 

million lbs 

718 
Table 6.4-2. 

 Changes to the Mississippi River at Grafton, Illinois from the Upper Mississippi River Basin 

(from the 2005 Baseline Scenario) 

2005 

Baseline 2010 2015 2020 2022 

Average corn 141 150 158 168 171 

yield 

(bushels/acre) 

Nitrogen 1433.5 + 5.5% + 4.7% + 2.5% + 1.8% 

million lbs 

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

lbs 

Sediment 6.4 + 0.5% + 0.3% + 0.2% + 0.1% 

million tons 

6.4.2.3 Potential Future Analysis 

Due to time and resource constraints, other alternative scenarios have not been analyzed. 

After evaluating comments on this proposal, if time and resources permit, EPA may conduct 

additional water quality analyses using the SWAT model in the UMRB. Potential future 

analyses could include: 1) determination of the most sensitive assumptions in the model, 2) 

water quality impacts from the changes in ethanol volumes relative to other reference cases, 3) 

comparisons between the assumptions and results of the Forest and Agricultural Sector 

Optimization Model (FASOM) used to model the impacts of this proposal on the agriculture 

sector and SWAT, 4) removing higher percentages of corn stover for cellulosic ethanol, 5) a case 

study of a smaller watershed to evaluate local water quality impacts that are impossible to 

ascertain at the scale of the UMRB, and/or 6) changes in loadings of a widely used corn 

herbicide, atrazine. 

6.5 Climate Change Impacts 

Although climate change is expected to be an important factor in future crop production 

in the Upper Mississippi River Basin, EPA has not modeled the impact of climate change on 

corn yields for a variety of reasons. Climate change requires a long period of observation. Over 

the short time frame reflected in this proposal, precipitation and temperature increases will be 

small and indistinguishable from the natural variability of the climate. 

Crop yield changes resulting from climate change depend on the atmospheric carbon 

dioxide level, the crop, and the base temperature. Yield also depends on the characteristics of 

the crop relative to the timing of precipitation and of extreme temperature events. All of these 

variables make an estimation of actual climate-induced yield loss very difficult to develop. 

Farmer adaptation may mitigate the effects of climate change on agriculture to some degree. 

Adaptations are influenced by many unpredictable factors, including government policy, prices, 

research and development, and technical assistance. Climate model simulations generally 

indicate that most locations in the upper Midwest will warm more than the global average and 

719 
 

will receive more precipitation than current – though estimates vary considerably depending on 

the model used and initial conditions. 

6.6 Chesapeake Bay Watershed 

The Chesapeake Bay Commission and others have expressed concerns about the water 

quality impact of increased corn production for ethanol may have on the Chesapeake Bay.993,994 

The Chesapeake Bay watershed stretches across more than 64,000 square miles, encompassing 

parts of six states — Delaware, Maryland, New York, Pennsylvania, Virginia and West Virginia 

— and the entire District of Columbia. The Chesapeake's land-to-water ratio (14:1) is the largest 

of any coastal water body in the world. This is why land use and land management have such 

significant influences on the health of the Bay. In its annual State of the Bay report in 2007, the 

Chesapeake Bay Foundation gave the Bay a score of 28 on a scale where 70 means the Bay is 

“saved” and 100 is pristine. The Foundation said that “the health of the Chesapeake Bay is 

dangerously out of balance”.995 

Agricultural lands account for nearly a quarter of the watershed, and contribute more 

nutrients to the Bay than any other land use. Agricultural operations produce about 41 percent of 

the nitrogen and 47 percent of the phosphorus loads going to the Bay. Agriculture also 

contributes about 63 percent of the Bay’s sediment. Municipal and industrial wastewater 

treatment plants throughout the watershed are responsible for 21 percent of the total nitrogen 

pollution and 22 percent of the total phosphorus pollution delivered to the Bay. 

In 2000, Chesapeake Bay Program partners (states, federal agencies, universities, nongovernmental agencies) agreed to reduce nitrogen pollution from an estimated 285 million 

pounds per year to no more than 175 million pounds by 2010. Similarly they pledged to reduce 

phosphorus from about 19 million pounds per year to less than 13 million pounds. While there 

have been steady declines in nitrogen and phosphorus, they have not been adequate to meet the 

established goals. The watershed must essentially quadruple the pace of the Bay cleanup to meet 

the 2010 commitment. To restore water quality in the Bay, all of the basin’s more than 87,000 

farms will need to implement best management practices (BMPs) at levels never before seen in 

this country. The states have committed to implement close to 30 different agricultural BMPs as 

part of their restoration strategies. 

At least 25 percent and possibly a third of the nitrogen entering the Bay comes from air 

deposition. The principal sources of emissions are power plants, cars and trucks, agriculture, and 

off-road sources such as construction equipment, lawn mowers and aircraft. While population 

increased about eight percent during the last decade, vehicle miles traveled rose 26 percent. 

More discussion about nitrogen oxides emission impacts can be found in Chapter 3.2. 

The Bay watershed receives significant levels of nitrogen oxides and other airborne 

pollutants from its large airshed (which is about six and a half times the size of the watershed), as 

far west as Ohio and Indiana. Air deposition of nitrogen on the land adds to the burden that must 

be dealt with by farmers, local governments and other landowners. 

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6.6.1 Agricultural Production Effects 

Due to the significant acreage within the Chesapeake Bay watershed that is devoted to 

agricultural production (approximately 22 percent), increases in corn acreage can potentially 

contribute to changes in nutrient loads to the Bay. High demand for corn reflected in record corn 

prices have played a substantial role in encouraging producers to alter their typical crop 

production rotations and crop acreage, contributing to noteworthy changes in crop acreages 

across the watershed. A technical review committee convened by the Chesapeake Bay 

Commission estimated that 300,000 new acres of corn could be added in the Bay watershed in 

the coming years.996 This new corn acreage could potentially contribute an additional five 

million pounds of nitrogen to the Bay. The Bay Program partners are trying to reach a 90 

million pound reduction in nitrogen from all sources. However, it is estimated that 17 million 

pounds of nitrogen could be offset if all agriculture acres used cover crops as a conservation 

practice after harvest. 

Strong market forces also encourage agricultural operators to increase grain production 

possibly by increasing the conversion of non-row crop acreage (hay, pasture and fallow or idle 

lands) to row crop production. Grain row crops can add more nutrients per acre to the Bay than 

hay and pasture due to production intensity, management systems, and nutrient efficiency of the 

crop. 

6.6.1.1 Base Analysis Assumptions 

The Chesapeake Bay Program Watershed Model Phase 4.3 (CBWM) and Vortex were 

utilized in the analysis of potential shifts in nutrient loading to the Bay based on reported 

changes to agricultural crop production from 2005 to 2008. These agricultural production 

changes are partially the result of the rapid expansion of biofuel production within the United 

States, supported by market-driven commodity price increases, government policies, or a 

combination of both. The CBWM is a dynamic watershed model used to characterize nutrient 

and sediment loads, and changes in these loads, due to management actions for decision 

support.GGGGGGGGGGGGG 

In developing the agricultural production trend analysis within the Chesapeake Bay 

watershed, the USDA’s National Agricultural Statistics Service’s (NASS) 2007 and 2008 

Projected Plantings report on reported crop acreages was modified to target only the Bay 

watershed. 

6.6.1.2 Corn Production Analysis 

Analyzing corn production acreage figures for the period from 2005 to 2008 from the 

NASS 2007 and 2008 Projected Planting reports, a measurable upward trend was evident for 

corn acreage plantings across the Bay watershed over the analysis period. This upward trend 

increased sharply between 2006 and 2007 and decreased for the 2007 and 2008 period. Despite 

the recent downward trend, total corn acreage increased over the analysis period by almost 

66,000 acres. 

GGGGGGGGGGGGG For more information on the CBWM see http://www.chesapeakebay.net/model.htm. 

721 
 

6.6.1.3 Corn Nutrient Load Analysis 

Employing a modeled analysis of the USDA-NASS Prospective Plantings report using 

the Chesapeake Bay Watershed Model Version 4.3 and Vortex, considerable increases of 

potential nitrogen loads to the Bay are associated with increased corn acreage. The decrease of 

corn acreage in the 2007 to 2008 period does not offset the total increase in acreage and nitrogen 

yields between 2005 and 2008. Total nitrogen loads increased by almost 2.4 million pounds. 

6.6.1.4 Land Use Conversion Analysis 

The agricultural production trends between 2005 and the present not only indicate an 

overall increase in the number of acres under corn production, but also an increase in the total 

acres of land under row crop production by over 355,000 acres. Since agricultural land uses 

within the Chesapeake Bay watershed are continuously decreasing due to urban development, 

the increase in row crop acreage may come at the expense of other cropping systems, or 

agricultural land uses such as hay, pasture or idle lands. 

6.6.1.5 Land Use Conversion Nitrogen Load Analysis 

The USDA-NASS Prospective Plantings reports and the Chesapeake Bay Program 

Watershed Model indicate a continuous total conversion of non-row crop agricultural lands over 

the period from 2005 to 2008 to more intensive row crop production. The non-row crop land 

uses typically produce less nitrogen yields to the Bay, thus additional acres converted to grain 

production can also increase nitrogen loads significantly. This analysis estimates that nitrogen 

loads increase by 8.8 million pounds. 

If time and resources allow, the Chesapeake Bay Program proposes to analyze the 

potential impacts within the Chesapeake Bay watershed of the implementation of the RFS2 for 

the FRM using available systems and models at our disposal. The models that would potentially 

be used in the analysis would include Phase 5.2 of the Chesapeake Bay Watershed Model 

(CBWM), the Nutrient and Sediment Scenario Builder (NSSB), the Chesapeake Bay Estuarine 

Water Quality Sediment Transport Model (CBEWQSTM) and the Chesapeake Bay Land Change 

Model (CBLCM). The CBWM is a dynamic watershed model used to characterize nutrient and 

sediment loads, and changes in these loads, due to management actions for decision support. 

The NSSB is being developed to determine nutrient and sediment loads under multiple land uses 

and crop types with variable organic and inorganic nutrient inputs. The CBEWQSTM 

determines the effects of nutrient and sediment load changes to the attainment of water quality 

standards. The CBLCM simulates changes in land use as a result of locally projected increases 

in population out to the year 2030. 

The scope of the analysis is proposed to include incremental and delivered nitrogen, 

phosphorus and sediment to the Chesapeake Bay, and the effect of management changes to the 

attainment of water quality standards. 

722 
 

6.7 Ethanol Production 

Under the Clean Water Act, all point sources of pollution, including ethanol plants, must 

have a permit to discharge to water bodies or to municipal wastewater treatment plants for both 

industrial process water and stormwater. The permit regulates the amount of pollutants that can 

be discharged. There are three principle sources of discharges to water from ethanol plants: 

reject water from water purification, cooling water blowdown, and off-batch ethanol. 

6.7.1 Water Discharges 

Water is required at ethanol facilities for processing and for the production of steam that 

is typically used in biomass pretreatment and ethanol distillation processes. An ethanol plant’s 

wastewater is typically comprised of cooling tower blowdown, boiler blowdown, and water 

softener discharge. The majority of the process water is lost as steam in the distillation process. 

In addition, stormwater runoff from the facility may be contaminated from precipitation (rain or 

snow) coming in contact with plant operations (industrial plant yards, material and waste 

handling, storage areas, shipping and receiving areas, residuals sites) and requires adequate 

control and management.997 

While some ethanol facilities get their process water from municipal water supplies, most 

use on-site wells to produce the process water for the ethanol process. Most groundwater 

sources are not suitable for process water because of their mineral content. Therefore, the water 

must be treated for use in ethanol production. The most common method of groundwater 

treatment is reverse osmosis. Reverse osmosis uses specialized filtration and pressure to produce 

pure water while concentrating the groundwater minerals into reject water. The minerals in the 

reject water are site-specific, but they can include: calcium carbonate, magnesium carbonate, 

sulfate, iron, and sodium. For every two gallons of pure water produced, about a gallon of brine 

is discharged as reject water. Most estimates of water consumption in ethanol production are 

based on the use of clean process water and neglect the water discharged as reject water. 

The largest source of wastewater discharge is reverse osmosis reject water from process 

water purification. The reverse osmosis process concentrates groundwater minerals to levels 

where they can have water quality impacts. The concentrated minerals can show toxicity due to 

osmotic concentration and the presence of some ions such as sulfate or copper. There is really 

no means of “treating” these ions to reduce toxicity, other than further concentration and 

disposal, or use of instream dilution. Some facilities have had to construct long pipelines to get 

access to dilution so they can meet water quality standards. 

Ethanol plants also discharge cooling water blowdown, where some cooling water is 

discharged to avoid the buildup of minerals in the cooling system. These brines are similar to the 

reject water described above. In addition, if off-batch ethanol product or process water is 

discharged, the waste stream can have high Biochemical Oxygen Demand (BOD) levels. BOD 

directly affects the amount of dissolved oxygen in rivers and streams. The greater the BOD, the 

more rapidly oxygen is depleted in the stream. This means less oxygen is available to higher 

forms of aquatic life. The consequences of high BOD are the same as those for low dissolved 

oxygen: aquatic organisms become stressed, suffocate, and die. 

723 
 

 

Ethanol production facilities are important transportation hubs. For instance, a facility in 

Iowa produces about 130 million gallons of ethanol in a year. On an average workday, 175 

tractor-trailers bring in corn, ethanol goes out in 12 rail tankers, and 8 rail cars are filled with 

dried distillers grain to be used as animal feed. This intensity of vehicle travel can have local 

water impacts from stormwater runoff, spills, etc. similar to any other rail and trucking terminal. 

6.7.2 Water Use 

Older generation production facilities used 4-6 gallons of process water to produce a 

gallon of ethanol, but newer facilities use less than 3 gallons of water in the production process. 

Most of this water savings is gained through improved recycling of water and heat in the process: 

the conservation of heat energy and water go hand-in-hand. This energy savings is a key 

economic advantage for newer plants. A gallon of ethanol contains about 70,000 Kcal of energy. 

Older plants used 35-40,000 Kcal of energy to produce a gallon of ethanol, but newer facilities 

use only 25-28,000 Kcal per gallon. 

The abundance or lack of water supply is a local issue, and there have been concerns with 

water consumption as new plants go online. Some facilities are tapping into deeper aquifers as a 

source of water. These deeper water resources tend to contain higher levels of minerals and this 

can further increase the concentration of minerals in reverse osmosis reject water. 

6.7.3 Distillers Grain with Solubles 

One important co-product of ethanol production is distillers grain with solubles (DGS). 

Due to the increase in ethanol production and the price of corn, DGS has become an increasing 

important feed component for confined livestock. About one-third of the corn processed into 

ethanol is converted into DGS. Therefore approximately 45 million tons of DGS will be 

produced for the 15 billion gallons of corn ethanol produced by 2015. Concerns have been 

raised about the relatively higher phosphorus content of DGS compared to traditional feeds. 

Livestock producers may partially replace corn or other feeds with DGS for both 

economic and production reasons. Different livestock species can tolerate varying amounts of 

DGS in their diets. The majority of DGS are fed to beef and dairy cows. Current 

recommendations allow beef and dairy cows diets to include from 15-40 percent DGS. 

Recommendations for poultry and swine diets are generally less than 15 percent DGS. Although 

specific analysis of DGS can vary between ethanol plants, compared to corn, DGS are higher in 

crude protein (nitrogen) and three to four times higher in phosphorus.998 

The increase in nitrogen and phosphorus from DGS in livestock feed has potential 

implications for water quality. When nitrogen and phosphorus are fed in excess of the animal’s 

needs, these nutrients are excreted in the manure. Most livestock manure is applied to crops, 

especially corn, as a source of nutrients. When manure is applied at rates above the nutrient 

needs of the crop or at times the crop can not use the nutrients, the nitrogen and phosphorus can 

runoff to surface waters or leach or ground waters. Excess nutrients from manure nutrients have 

the same impact on water quality as excess nutrients from other sources. 

724 
 

 

 

Several recent studies have indicated that DGS may also have an impact on food safety. 

Cattle fed DGS have a higher prevalence of a major food-borne pathogen, E. coli O157, than 

cattle without DGS in their diets. More research is needed to confirm these studies and devise 

methods to eliminate the potential risks.999 

Livestock producers can limit the potential pollution from manure applications to crops 

through a variety of techniques. USDA’s Natural Resources Conservation Service (NRCS) has 

developed a standard for a comprehensive nutrient management plan (CNMP) to address the 

issue of proper use of livestock manure.1000 Agricultural producers who use manure should test 

the nitrogen and phosphorus content before application of the manure. Due to the substantially 

higher phosphorus content of manure from livestock fed DGS, producers will potentially need 

significantly more acres to apply the manure so that phosphorus will not be applied at rates 

above the needs of the crops. This is a particularly important concern in areas where 

concentrated livestock production already produces more phosphorus in the manure than can be 

taken up by crops or pasture land in the vicinity. 

6.7.4 Water Quality Impact from Ethanol Leaks and Spills 

The potential for exposure to fuel components and/or additives can occur when 

underground fuel storage tanks leak fuel into ground water that is used for drinking water 

supplies or when spills occur that contaminate surface drinking water supplies. Ethanol 

biodegrades quickly and is not necessarily the pollutant of greatest concern in these occurrences. 

Instead, ethanol’s high biodegradability can cause the plume of BTEX (benzene, toluene, 

ethylbenzene and xylenes) compounds in gasoline to extend farther (by as much as 70 

percent1001) and persist longer in ground water, thereby increasing potential exposures to these 

compounds. Particularly large plumes of benzene can be expected when: there is a large area of 

the aquifer that is contaminated with liquid phase gasoline; the background concentration of 

sulfate-reducing bacteria (which biodegrade ethanol and benzene) in the ground water is low; the 

rate of ethanol biodegradation is low; and the flow velocity of the ground water is high. More 

detail on ethanol biodegradation and a summary of laboratory and field studies of ethanol spills 

will be forthcoming in the EPAct 2005 Report to Congress on Fuel Additive Replacements for 

MTBE in late 2008. 

With the increasing use of ethanol in the fuel supply nationwide, it is important to 

understand the impact of ethanol on the existing tank infrastructure. Given the corrosivity and 

different material compatibility requirements of ethanol, there is concern regarding the increased 

potential for leaks from existing gas stations and subsequent impacts on drinking water supplies. 

In 2007, there were 7,500 reported releases from underground storage tanks. Since 

approximately 50 percent of the gasoline used in the U.S. contains ethanol, approximately 3,750 

of those releases likely contained some amount of ethanol. Therefore, EPA is undertaking 

analyses designed to assess the potential impacts of ethanol blends on tank infrastructure and 

leak detection systems and determine the resulting water quality impacts. 

An additional hazard from spills from fuels containing ethanol is risk of potential 

explosions. Laboratory and field studies have found biodegradation of ethanol can produce 

concentrations of methane in excess of the water solubility of methane (i.e., more methane was 

725 
 

produced than could be dissolved by the available water). This methane could bubble out of the 

ground water and enter the soil gas at explosive concentrations, although it is not possible to 

quantify the risk at this time. EPA is beginning development of modeling software for the 

assessment of fuels of varying composition on ground water, with simulation of methane 

production being one component of this work. 

6.8 Water Use and Wastewater from Biodiesel Plants 

Biodiesel plants use much less water than ethanol plants in production of biofuel. Water 

is not used in conversion of oil to biodiesel, but is used for washing impurities from the finished 

product. Water use is variable, but is usually less than one gallon of water for each gallon of 

biodiesel produced. Larger well-designed plants use water more sparingly, while smaller 

producers and hobbyists use more water. Some facilities recycle washwater, which reduces water 

consumption. 

The strength of process wastewater from biodiesel plants is highly variable. Most 

production processes produce washwater that has very high BOD levels. Essentially the strength 

of the wastewater is based on glycerin and methanol content. Larger facilities are segregating 

glycerin as a side product and have efficient methanol recovery, while smaller plants are more 

likely to dispose of glycerin, excess methanol, and washwater as a single waste stream. Crude 

glycerin is an important side product from the biodiesel process and has many uses. It is about 

10 percent of the final product. The rapid development of the biodiesel industry has caused a 

glut of glycerin production and many facilities dispose of glycerin. 

The high strength of these wastes can overload and disrupt the biological processes in 

municipal treatment plants. The normal wastewater going into a municipal sewage treatment 

plant has a BOD 200mg/l. Washwater from the biodiesel process with efficient recovery of 

methanol, containing small amounts of glycerin, can have a BOD of 10,000 – 15,000 mg/L. 

Pure glycerin has a BOD of nearly 1,000,000 mg/L. There have been several cases of 

wastewater treatment plant upsets due to these shock loadings from releases of glycerin from 

biodiesel production facilities. Unfortunately, these have been due to slug loadings to small 

wastewater treatment plants. Other states such as Illinois and Alabama have also had problems 

with discharges from small biodiesel plants. In addition, there have been incidences of outright 

dumping of glycerin. One such event resulted in a large fish kill in Missouri. 

Producers that choose to dispose of glycerin can be regulated under several EPA 

programs, depending on the practice. EPA strongly supports the beneficial use of glycerin as a 

product. 

While the market for refined glycerin is glutted with an excess supply, there are many 

known uses for glycerin feedstock. As prices for glycerin go down, many of these known 

products will show a better profit margin and demand for glycerin will increase. Most larger 

facilities are segregating crude glycerin for refining into usable feedstock for other products. 

Refining can range from minimal processing up to creation of a food grade product. Nationally, 

there is a lot of research on the creation of new value added products (ethanol, propylene glycol, 

726 
 

etc.) using glycerin as a feedstock. Most of these projects are in university labs, but a few are up 

to pilot scale. These new technologies will go online at full scale within the next few years, and 

are an important part of the profit stream for the industry. 

6.9 Potential Impacts to Drinking Water and Public Health 

Under the Safe Drinking Water Act (SDWA), EPA establishes enforceable safety 

standards for drinking water provided by public water systems (PWS). For chemicals, the 

standard is typically called a maximum contaminant level (MCL). A PWS is “a system for the 

provision to the public of water for human consumption through pipes or other constructed 

conveyances, if such system has at least fifteen service connections or regularly serves at least 

twenty-five individuals.” If the source water for a PWS does not meet the MCL, the PWS must 

take measures to reduce the contamination to safe levels and that may entail installing expensive 

drinking water treatment technology e.g., ion exchange (IE), granulated activated carbon (GAC) 

or reverse osmosis (RO). 

EPA anticipates that increased corn production for ethanol will increase the occurrence of 

nitrate, nitrite, and atrazine in sources of drinking water. New corn acreage may result in 

increase in the application of fertilizers and herbicides, especially on marginal lands that are not 

as productive. The ethanol production process may generate new or increased discharges, 

injection or infiltration of process waste water that could adversely affect the nation’s surface 

water and ground water used for drinking water. 

In addition to potential additional contamination of sources of drinking water, surface and 

ground water supplies may be strained by increased production of irrigated corn for ethanol and 

the ethanol production process itself in local and regional areas. Increased pumping from 

agricultural aquifers to support ethanol production may accelerate the long running depletion of 

aquifers which has been documented by the USGS. According to U. S. Geological Survey 

(USGS) data, more than 72 billion gallons a day are already being pumped from the “thirty 

regional principle aquifers with the greatest amount of ground water use”, with irrigation 

accounting for slightly more than 75 percent of those withdrawals.1002 The water table of the 

Ogallala aquifer has declined by over 150 feet in some areas since the 1950s due to increasingly 

large withdrawals.1003 Aquifers provide water for domestic and other uses, and contribute to the 

base flow of many streams and lakes that support aquatic habitats and other ecoservices such as 

fishing and swimming. Lower stream levels combined with the increased pollutant loadings may 

concentrate pollutants. Higher pollutant concentrations may require increased drinking water 

treatment. The accelerated depletion of agricultural aquifers and surface water supplies may be 

exacerbated by an increase in the incidence of droughts that are predicted under many climate 

change scenarios. 

6.9.1 Nitrogen 

The nitrogen fertilizers that are applied to corn and other agricultural crops can end up in 

drinking water sources where they can impact human health. The two nitrogen compounds of 

concern are nitrate and nitrite. Nitrate is the most stable form of nitrogen in water. 

727 
 

EPA has established the MCL for nitrate-nitrogen at 10 parts per million (ppm) and for 

nitrite at 1 ppm. Infants below six months who drink water containing nitrate and/or nitrite in 

excess of the MCL could become seriously ill and, if untreated, may die.1004 Symptoms include 

shortness of breath and blue baby syndrome. This health effects language is not intended to 

catalog all possible health effects for nitrate. Rather, it is intended to inform people of the most 

significant and probable health effects, associated with nitrate and nitrite in drinking water. 

Most nitrogen in water is converted to nitrates. Since nitrates are very soluble and do not 

bind to soils, they have a high potential to migrate to ground water. Because they do not 

evaporate, nitrates and nitrites are likely to remain in water until consumed by plants or other 

organisms. Primary sources of nitrate which may contaminate drinking water are human 

sewage, livestock manure, and fertilizers. 

In 2007, there were 562 public water systems, serving 257, 558 people, reporting 

violations of the nitrate MCL.1005 If a utility’s routine compliance monitoring indicates that 

nitrate or nitrite concentrations are above the MCL, the water system must implement measures 

such as treatment or blending to reduce the concentration so that it is below the MCL (e.g., find a 

new source of water, adjust existing treatment or install new treatment). Also, utilities must 

monitor the finished water every quarter and provide notification to consumers of the MCL 

exceedance. 

Since there is no nationally consistent sampling of ambient water used by public water 

systems, the relative contribution of nitrate detections from the various sources is generally 

unknown. 

6.9.2 Atrazine 

Atrazine is estimated to be the most widely used herbicide in the United States for control 

of weeds. Atrazine was the second most frequently detected pesticide in EPA's National Survey 

of Pesticides in Drinking Water Wells. EPA's Pesticides in Ground Water Database indicates 

numerous detections of atrazine at concentrations above the MCL in ground water in several 

states, including Delaware, Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Missouri, 

Nebraska and New York.1006 In 1993, EPA and the atrazine registrants initiated a monitoring 

program to focus on the most significant exposures associated with agricultural and residential 

uses -- exposures through drinking water. To this point, levels found in PWS have been low. 

Through the PWS monitoring program, EPA is ensuring that exposures to atrazine in drinking 

water do not reach levels that pose a risk to public health. 

The MCL for atrazine is three parts per billion (ppb). MCL violations are not triggered 

by single measurement above the MCL but by the running annual average concentration from 

four quarterly samples in which at least one measurement during that period exceeds 3 ppb. 

Some people who drink water containing atrazine well in excess of the MCL over a period of 

many years could experience problems with their cardiovascular system or reproductive 

difficulties. This health effects language is not intended to catalog all possible health effects for 

atrazine. Rather, it is intended to inform people of the most significant and probable health 

effects, associated with atrazine in drinking water. 

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Atrazine may be released to the environment in wastewater from herbicide manufacturing 

facilities and through its use as an herbicide. Microbial activity and other chemicals may 

breakdown atrazine in soil and water, particularly in alkaline conditions. Sunlight and 

evaporation do not reduce its presence. It may bind to some soils, but generally tends to leach to 

ground water. Atrazine is not likely to be taken up in the tissues of plants or animals. 1007

 In A Review of Contaminant Occurrence in Public Water Systems, published in 1999, 

EPA found atrazine in the finished water of 21 percent of the surface water systems.1008 

Atrazine was found at concentrations exceeding the MCL in 10.7 percent of the surface water 

systems and, in 83 percent of those systems, atrazine was found at concentrations that would 

have been in violation of the MCL. As noted above, MCL violations are not triggered by single 

excursions above the MCL but by the running annual average concentration from four quarterly 

samples in which the measurement of at least one of those samples exceeds three ppb. However 

in one of the states where atrazine is widely used e.g., for corn production, the percentage of 

single samples exceeding the MCL was as high as 77.8 percent for surface water systems serving 

less than 500 people; see Table 6.1. 

Table 6.9-1. 

 Percentage of Surface Water Systems with Detections of Atrazine 

for a High Occurrence State, 1999 

POPULATION <500 500 – 3,300 3,301 – 

10,000 

10,001 – 

50,000 > 50,000 

> MRLa 100% 100% 96.2% 96.3% 55.6% 

> MCLb 77.8% 71.1% 57.7% 18.5% 22.2% 

a The MRL, or minimum reporting level, is the lowest concentration at which the contaminant can be consistently 

and reliably detected. U.S. Environmental Protection Agency, A Review of Contaminant Occurrence in Public 

Water Systems, EPA 816-R-99-006, 1999, Table V.A.2, page D-2. b

 U.S. Environmental Protection Agency, ibid, p. D-3. 

In 2003, EPA estimated that single atrazine measurements greater than the MCL would 

be observed in 26 to 57 public water systems serving a range of 24,400 – 260,300 people. 1009 

Because atrazine is used mostly as a pre-emergent herbicide on corn, the surface water 

concentrations typically spike during growing season then taper off for the rest of the year. Even 

though many surface water systems encounter concentrations above the MCL during the growing 

season, very few experience MCL violations based on the average concentration over four 

consecutive quarters. In 2007, only one water system serving 740 people officially reported a 

MCL violation.1010 

From 1992 through 2001, the USGS observed atrazine in 90 percent of the samples it 

took from 83 stream sites in agricultural areas as part of its National Water Quality Assessment 

(NAWQA). Although it does not target exclusively drinking water intakes or wells, the 

NAWQA program “provides an understanding of water-quality conditions and how those 

729 
 

conditions may vary locally, regionally, and nationally...”.1011 Atrazine was observed in 71 

percent of the samples from 30 urban stream sites during the same period. For ground water, 

USGS observed atrazine in 42 percent of the samples it took from wells in agricultural areas and 

in 31 percent of the samples from urban wells. The detection limits for this study were very low 

and 95 percent of the sampling results from streams in agricultural areas, where the highest 

concentrations of atrazine were found, were below 2.4 ppb which is 80 percent of the MCL of 3 

ppb. 

6.9.3 Future availability of more recent occurrence data 

EPA anticipates releasing the chemical occurrence data covering the years 1999 – 2006 

from states for publication in 2009 as part of the six year review of drinking water standards. 

Once those data sets are publicly available, they will be useful in updating the occurrence data 

published here for nitrate and atrazine. 

6.10 Water Quantity Concerns 

 Biofuel production based on current and projected approaches and processes, future 

alternative fuel development and production could markedly increase the demand for various 

fresh water resources. Two potential needs could increase water demand: quantities of water to 

produce biomass as a feedstock, and the additional water demand for refining of bio-ethanol and 

biodiesel fuels (by up to a factor of three relative to traditional refining). From a regional 

perspective, water demand for crop production would be relatively much larger than biorefinery 

demand; crop production needs would be approximately 200 times the water needed to refine 

biofuels.1012 . 

With growth of ethanol production, water supply reliability related to crop demand for 

biomass feedstock will remain an issue. The amount of water needed to grow feedstocks for 

biofuels can be considerable – for example, the ratio of water consumed to produce the corn 

itself for ethanol is nearly one thousand gallons per gallon of corn ethanol. Large scale 

production of perennial energy crops involving tens of millions of acres, even when rain-fed, can 

have water resource impacts and unintended local consequences due to alterations of hydrologic 

flows. The timing of the water demand may also be critical; water is often plentiful in one 

season but scarce in another. 

Growing crops for biofuel production is likely to have significant regional and local 

impacts, including the potential to change irrigation water use, and thus local water availability. 

The feasibility and sustainability of water diversions for biomass irrigation will vary depending 

on the region. Moreover, siting of some ethanol plants is already occurring where the water 

resource is already under duress, for example on the High Plains aquifer. 

 Biofuel refineries create additional local scale demand for water withdrawals and 

consumption. It is difficult to generalize about the impact on local water supplies, however, 

some community supplies have been stressed by the water requirements of ethanol facilities. 

730 
 

However, from a national and regional perspective, relative to the water incorporated in the 

feedstock, water use in biorefineries is quite small. A typical corn ethanol plant consumes 

slightly more than four gallons water per gallon of ethanol produced; biodiesel refining even 

less, about one gallon of water per gallon of biodiesel. (Petroleum refining consumes about 1.5 

gallons water per gallon fuel produced.) Biodiesel refining requires much less water per unit of 

energy produced than bioethanol. Consumptive use is about one gallon water per gallon, but 

may be up to three gallons per gallons. However, biofuels crops may be irrigated with 

wastewater that is biologically and chemically unsuitable for use with food crops. On the other 

hand, cellulosic materials require a different process, and are thought to use 9.5 gallons water per 

gallon fuel produced -- but this would be expected to decline as efficiency increases (currently 

projected to be lowered to two to six gallons per gallon). 

Geographic impacts of biofuel refining vary. Currently, the Midwest and Southeast have 

most of the production. In Iowa, water consumption alone from ethanol refining already 

accounts for about seven percent of all industrial water use, and is projected to be 14 percent by 

2012 -- or about 50 million gallons per day. A typical ethanol plant now producing 50 million 

gallons per year means a minimum of 175 million gallons (nearly 480,000 per day) used in a 

year. In the Great Lakes-St. Lawrence region, newer facilities under construction will have 

capacities of 100 million gallons per year.1013 For a 100 million gallon per year corn ethanol 

plant, water consumption is one million gallons of water/day (equates to daily water 

consumption of a town of 20,000). 

Research is needed to establish water use requirements across the entire biofuel 

production chain. Information needs related to biomass feedstock production include the 

assessment and quantification of impacts of increased irrigation of energy crops and resulting 

biofuel cost/benefit tradeoffs for both starch/sugar/oil biofuel crops, and the lignocellulosic 

biofuel crops. An assessment is also needed of the impacts on hydrologic flows of regional 

expansion of perennial energy crop production. These include the impacts and risks tradeoffs, 

e.g., altered flows due to deep extensive root systems and dense canopies, as well as a need for 

management practices/metrics, e.g. relatively large absolute water consumption, and additional 

irrigation necessary. Changing climate adds an additional element of uncertainty in making 

assessments of water use. 

Many uncertainties exist regarding estimating water needs for irrigating cellulosic 

feedstocks in particular. Reasons include: water data is less available for proposed cellusosic 

feedstock than for common crops, evapotranspiration rates of marginal lands used for these crops 

are unknown, and water demand by heretofore unirrigated native grasses is unknown. 

There are some mitigating factors on increased demand for water by biofuels. Both the 

impacts and regulatory opportunities for mitigation of water impacts are likely to be at the state 

and local levels. For example, rainfall harvesting, efficient irrigation water transport and use of 

reclaimed water can lead to more efficient agricultural water use for both corn and cellulosic 

ethanol crops. Also, biorefineries are increasingly incorporating water recycling. 

The economics of the energy-water distribution linkage are important in biofuels 

production. At a macroscale, the high prices of energy driving the increased production of 

731 
biofuels will likely affect water availability and use, e.g., conveyance costs related to irrigation 

waters will also increase with energy costs, possibly leading to water conservation that may 

counter the expanded water use for crops. Also, the value of crops relative to their water demand 

matters: water rights can often be bought and sold if the value of the crop is sufficiently high. 

Finally, there is the potential for a low water use alternative biomass feedstock to 

develop: oil-producing macro-algae. These algae can be grown without land, using 

nontraditional waters, and CO2 waste streams as a nutrient source. Such fuels can have 

significantly higher energy density and are potentially more fungible within existing 

transportation fuel infrastructure than ethanol. 

732 
Chapter 7: Initial Regulatory Flexibility Analysis 

This chapter discusses our Initial Regulatory Flexibility Analysis (IRFA) which evaluates 

the potential impacts of the proposed standards on small entities. The Regulatory Flexibility Act, 

as amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 

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. Pursuant to this requirement, we have prepared an 

IRFA for the proposed rule. Throughout the process of developing the IRFA, we conducted 

outreach and held meetings with representatives from the various small entities that could be 

affected by the rulemaking to gain feedback, including recommendations, on how to reduce the 

impact of the rule on these entities. The small business recommendations stated here reflect the 

comments of the small entity representatives (SERs) and members of the Small Business 

Advocacy Review Panel (SBAR Panel, or ‘the Panel’). 

7.1 Overview of the Regulatory Flexibility Act 

In accordance with section 609(b) of the Regulatory Flexibility Act, we convened an 

SBAR Panel before conducting the IRFA. A summary of the Panel’s recommendations is 

presented in the preamble of this proposed rulemaking. Further, a detailed discussion of the 

Panel’s advice and recommendations is found in the Final Panel Report contained in the docket 

for this proposed rulemaking. 

Section 609(b) of the Regulatory Flexibility Act further directs the Panel to report on the 

comments of small entity representatives and make findings on issues related to identified 

elements of the IRFA under section 603 of the Regulatory Flexibility Act. Key elements of an 

IRFA are: 

- a description of and, where feasible, an estimate of the number of small entities to which 

the proposed rule will apply; 

- projected reporting, record keeping, and other compliance requirements of the proposed 

rule, including an estimate of the classes of small entities which will be subject to the 

requirements and the type of professional skills necessary for preparation of the report or 

record; 

- an identification, to the extent practicable, of all other relevant Federal rules which may 

duplicate, overlap, or conflict with the proposed rule; 

- any significant alternatives to the proposed rule which accomplish the stated objectives of 

applicable statutes and which minimize any significant economic impact of the proposed 

rule on small entities. 

733 
The Regulatory Flexibility Act was amended by SBREFA to ensure that concerns 

regarding small entities are adequately considered during the development of new regulations 

that affect those entities. Although we are not required by the Clean Air Act to provide special 

treatment to small businesses, the Regulatory Flexibility Act requires us to carefully consider the 

economic impacts that our rules will have on small entities. The recommendations made by the 

Panel may serve to help lessen these economic impacts on small entities when consistent with 

Clean Air Act requirements. 

7.2 Need for the Rulemaking and Rulemaking Objectives 

A detailed discussion on the need for and objectives of this proposed rule are located in 

the preamble to the proposed rule. As previously stated, section 1501 of the Energy Policy Act 

of 2005 (EPAct) amended section 211 of the Clean Air Act (CAA) by adding section 211(o) 

which required the Environmental Protection Agency (EPA) to promulgate regulations 

implementing a renewable fuel program. The final Renewable Fuels Standard (RFS1) program, 

which began on September 1, 2007, created a specific annual level for minimum renewable fuel 

use that increases over time — resulting in a requirement that 7.5 billion gallons of renewable 

fuel be blended into gasoline (for highway use only) by 2012. 

The Energy Independence and Security Act of 2007 (EISA) amended section 211(o), and 

the RFS program, by requiring higher volumes of renewable fuels, to result in 36 billion gallons 

of renewable fuel by 2022. EISA also expanded the purview of the RFS1 program by requiring 

that these renewable fuels be blended into diesel fuel (both highway and nonroad) in addition to 

gasoline. This expanded the pool of regulated entities, so the obligated parties under this RFS2 

NPRM will now include certain refiners, importers, and blenders of these fuels that were not 

previously covered by the RFS1 program. In addition to the total renewable fuel standard 

required by EPAct, EISA added standards for three additional types of renewable fuels to the 

program (advanced biofuel, cellulosic biofuel, and biomass-based diesel) and requires 

compliance with all four standards. 

7.3 Definition and Description of Small Entities 

Small entities include small businesses, small organizations, and small governmental 

jurisdictions. For the purposes of assessing the impacts of the proposed rule on small entities, a 

small entity is defined as: (1) a small business that meets the definition for business based on the 

Small Business Administration’s (SBA) size standards; (2) a small governmental jurisdiction that 

is a government of a city, county, town, school district or special district with a population of less 

than 50,000; and (3) a small organization that is any not-for-profit enterprise which is 

independently owned and operated and is not dominant in its field. 

Small businesses (as well as large businesses) would be regulated by this rulemaking, but 

not small governmental jurisdictions or small organizations as described above. As set by SBA, 

the categories of small entities that will potentially be affected by this rulemaking are defined in 

734 
Table 7.3-1 provides an overview of the primary SBA small business categories potentially 

affected by this regulation. 

Table 7.3-1. Small Business Definitions 

Industry 

Defined as small entity 

by SBA if less than or 

equal to: 

NAICSa

 codes 

Gasoline and diesel fuel refiners 1,500 employeesb 324110 

a

 North American Industrial Classification System 

b

 EPA has included in past fuels rulemakings a provision that, in order to qualify for the small refiner 

flexibilities, a refiner must also produce no greater than 155,000 bpcd crude capacity 

EPA used a variety of sources to identify which entities are appropriately considered 

“small.” EPA used the criteria for small entities developed by the Small Business 

Administration under the North American Industry Classification System (NAICS) as a guide. 

Information about the characteristics of refiners comes from sources including the Energy 

Information Administration (EIA) within the U.S. Department of Energy, oil industry literature, 

and previous rulemakings that have affected the refining industry. EPA then found employment 

information for these companies using the business information database Hoover’s Online (a 

subsidiary of Dun and Bradstreet). These refiners fall under the Petroleum Refineries category, 

324110, as defined by NAICS. 

7.4 Summary of Small Entities to Which the Rulemaking Will Apply 

Small entities that will be subject to the renewable fuel standard include: domestic 

refiners that produce gasoline and/or diesel, and importers of gasoline and/or diesel into the U.S. 

Based on 2007 data, EPA believes that there are about 95 refiners of gasoline and diesel fuel. Of 

these, EPA believes that there are currently 21 refiners producing gasoline and/or diesel fuel that 

meet the SBA small entity definition of having 1,500 employees or less. Further, we believe that 

three of these refiners own refineries that do not meet the definition of a “small refinery” that 

Congress specified under section 211(o). It should be noted that because of the dynamics in the 

refining industry (i.e., mergers and acquisitions), the actual number of refiners that ultimately 

qualify for small refiner status under the RFS2 program could be different from this initial 

estimate. 

7.5 Related Federal Rules 

The primary federal rules that are related to the proposed RFS2 program are: the Mobile 

Source Air Toxics rule (Federal Register Vol. 72, p. 8428, February 26, 2007), the RFS1 rule 

(Federal Register Vol. 72, p. 23900, May 1, 2007), and the Technical Amendment Direct Final 

Rulemaking for RFS1 (Federal Register Vol. 73, p. 71560, November 25, 2008). 

735 
7.6 Projected Reporting, Recordkeeping, and Other Compliance 

Requirements 

For any fuel control program, EPA must have assurance that any fuel produced meets all 

applicable standards and requirements, and that the fuel continues to meet those standards and 

requirements as it passes downstream through the distribution system to the ultimate end user. 

Registration, reporting, and recordkeeping are necessary to track compliance with the RFS2 

requirements and transactions involving RINs. As discussed in Sections III.J and IV.E of the 

preamble to the proposed rule, the proposed compliance requirements under the RFS2 program 

are in many ways similar to those required under the RFS1 program, with some modifications to 

account for the new requirements of EISA. 

7.7 Regulatory Alternatives 

The Panel’s findings and discussions are based on the information that was available 

during the term of the Panel and issues that were raised by the SERs during the outreach 

meetings and in their written comments. It was agreed that EPA should consider the issues 

raised by the SERs (and issues raised in the course of the Panel) and that EPA should consider 

the comments on flexibility alternatives that would help to mitigate any adverse impacts on small 

businesses. Alternatives discussed throughout the Panel process include those offered in the 

development of this rule. A summary of the Panel’s recommendations, along with those 

provisions that are being proposed in this action, are detailed below. A full discussion of the 

regulatory alternatives and hardship provisions discussed and recommended by the Panel, all 

written comments received from SERs, and summaries of the outreach meetings that were held 

with the SERs can be found in the SBREFA Final Panel Report, located in the rulemaking 

docket. All of the flexibilities that were proposed in the rulemaking for small businesses are 

described in Section IV.B of the preamble to the proposed rule. 

In general, SERs stated that they believed that small refiners would face challenges in 

meeting the new standards. More specifically, they voiced concerns with respect to the RIN 

program itself, uncertainty (with the required renewable fuel volumes, RIN availability, and 

cost), and the desire for a RIN system review. 

One concern that was raised by EPA with regard to provisions for small refiners in the 

RFS2 rule is that this rule presents a very different situation than the small refinery versus small 

refiner concept from RFS1. This situation deals with whether EPA has the authority to provide 

small refineries that are operated by a small refiner with an extension of time that would be 

different from (and more than) the temporary exemption specified by Congress in section 

211(o)(9) for small refineries. For those small refiners who are covered by the small refinery 

provisions, Congress has specifically adopted a relief provision aimed at their refineries. This 

provides a temporary extension through December 31, 2010 and allows for further extensions 

only if certain criteria are met. EPA believes that providing small refineries (and thus, small 

refiners who own small refineries) with an additional exemption different from that provided by 

section 211(o)(9) raises concerns about inconsistency with the intent of Congress. Congress 

spoke directly to the relief that EPA may provide for small refineries, including those small 

736 
refineries operated by small refiners, and limited it to a blanket exemption through December 31, 

2010, with additional extensions if the criteria specified by Congress were met. An additional or 

different extension, relying on a more general provision in section 211(o)(3), would raise 

questions about consistency with the intent of Congress. 

It was agreed that EPA should consider the issues raised by the SERs and discussions had 

by the Panel itself, and that EPA should consider comments on flexibility alternatives that would 

help to mitigate negative impacts on small businesses to the extent legally allowable by the 

Clean Air Act. Alternatives discussed throughout the Panel process included those offered in 

previous EPA rulemakings, as well as alternatives suggested by SERs and Panel members. A 

summary of these recommendations is detailed below, and a full discussion of the regulatory 

alternatives and hardship provisions discussed and recommended by the Panel can be found in 

the SBREFA Final Panel Report. A complete discussion of the provisions for which we are 

requesting comment and/or proposing in this action can be found in Section IV.B of this 

preamble. Also, the Panel Report includes all comments received from SERs (Appendix B of 

the Report) and summaries of the two outreach meetings that were held with the SERs. In 

accordance with the RFA/SBREFA requirements, the Panel evaluated the aforementioned 

materials and SER comments on issues related to the IRFA. The Panel’s recommendations from 

the Final Panel Report are discussed below. 

7.7.1 Panel Recommendations 

7.7.1.1 Panel Process 

The purpose of the Panel process is to solicit information as well as suggested flexibility 

options from the SERs, and the Panel recommended that EPA continue to do so during the 

development of the RFS2 rule. Recognizing the concerns about EPA’s authority to provide 

extensions to a subset of small refineries (i.e., those that are owned by small refiners) different 

from that provided to small refineries in section 211(o)(9), the Panel recommended that EPA 

continue to evaluate this issue, and that EPA request comment on its authority and the 

appropriateness of providing extensions beyond those authorized by section 211(o)(9) for small 

refineries operated by a small refiner. The Panel also recommended that EPA propose to provide 

the same extension provision of 211(o)(9) to small refiners who do not own small refineries as is 

provided for small refiners who do own small refineries. 

7.7.1.2 Delay in Standards 

The RFS1 program regulations provide small refiners who operate small refineries as 

well as small refiners who do not operate small refineries with a temporary exemption from the 

standard through December 31, 2010. Small refiner SERs suggested that an additional 

temporary exemption for the RFS2 program would be beneficial to them in meeting the 

standards. EPA evaluated a temporary exemption for at least some of the four required RFS2 

standards for small refiners. The Panel recommended that EPA propose a delay in the effective 

date of the standards until 2014 for small entities, to the maximum extent allowed by the statute. 

However, the Panel recognized that EPA has serious concerns about its authority to provide an 

extension of the temporary exemption for small refineries that is different from that provided in 

737 
CAA section 211(o)(9), since Congress specifically addressed an extension for small refineries 

in that provision. 

The Panel did recommend that EPA propose other avenues through which small 

refineries and small refiners could receive extensions of the temporary exemption. These 

avenues, as discussed in greater detail in the preamble to the proposed rule (sections IV.B, and 

XII.C.6.c.v and vi), are a possible extension of the temporary exemption for an additional two 

years following a study of small refineries by the Department of Energy (DOE) and provisions 

for case-by-case economic hardship relief. 

7.7.1.3 Phase-in 

Small refiner SERs’ suggested that a phase-in of the obligations applicable to small 

refiners would be beneficial for compliance, such that small refiners would comply by gradually 

meeting the standards on an incremental basis over a period of time, after which point they 

would comply fully with the RFS2 standards, EPA has serious concerns about its authority to 

allow for such a phase-in of the standards. CAA section 211(o)(3)(B) states that the renewable 

fuel obligation shall “consist of a single applicable percentage that applies to all categories of 

persons specified” as obligated parties. This kind of phase-in approach would result in different 

applicable percentages being applied to different obligated parties. Further, as discussed above, 

such a phase-in approach would provide more relief to small refineries operated by small refiners 

than that provided under the small refinery provision. Thus the Panel recommended that EPA 

should invite comment on a phase-in, but not propose such a provision. 

7.7.1.4 RIN-related Flexibilities 

The small refiner SERs requested that the proposed rule contain provisions for small 

refiners related to the RIN system, such as flexibilities in the RIN rollover cap percentage and 

allowing all small refiners to use RINs interchangeably. Currently in the RFS1 program, EPA 

allows for 20 percent of a previous year’s RINs to be “rolled over” and used for compliance in 

the following year. A provision to allow for flexibilities in the rollover cap could include a 

higher RIN rollover cap for small refiners for some period of time or for at least some of the four 

standards. Since the concept of a rollover cap was not mandated by section 211(o), EPA 

believes that there may be an opportunity to provide appropriate flexibility in this area to small 

refiners under the RFS2 program but only if it is determined in the DOE small refinery study that 

there is a disproportionate effect warranting relief. The Panel recommended that EPA request 

comment on increasing the RIN rollover cap percentage for small refiners, and further that EPA 

should request comment on an appropriate level of that percentage. 

The Panel recommended that EPA invite comment on allowing RINs to be used 

interchangeably for small refiners, but not propose this concept because under this approach 

small refiners would arguably be subject to a different applicable percentage than other obligated 

parties (similar to the phase-in approach discussed above). This concept would also fail to 

require the four different standards mandated by Congress (e.g., conventional biofuel could not 

be used instead of cellulosic biofuel or biomass-based diesel). 

738 
7.7.1.5 Program Review 

With regard to the suggested program review, EPA raised the concern that this could lead 

to some redundancy since EPA is required to publish a notice of the applicable RFS standards in 

the Federal Register annually, and that this annual process will inevitably include an evaluation 

of the projected availability of renewable fuels. Nevertheless, the SBA and OMB Panel 

members stated that they believe that a program review could be helpful to small entities in 

providing them some insight to the RFS program’s progress and alleviate some uncertainty 

regarding the RIN system. As EPA will be publishing a Federal Register notice annually, the 

Panel recommended that EPA include an update of RIN system progress (e.g., RIN trading, RIN 

availability, etc.) in this notice and that the results of this evaluation be considered in any request 

for case-by-case hardship relief. 

7.7.1.6 Extensions of the Temporary Exemption Based on a Study of Small Refinery 

Impacts 

The Panel recommended that EPA propose in the RFS2 program the provision at 40 CFR 

80.1141(e) extending the RFS1 temporary exemption for at least two years for any small refinery 

that DOE determines would be subject to disproportionate economic hardship if required to 

comply with the RFS2 requirements. 

Section 211(o)(9)(A)(ii) requires DOE to perform a study of the economic impacts of the 

RFS requirements on small refineries. The study, which is required to be completed by 

December 31, 2008, must assess and determine whether the RFS requirements would impose a 

disproportionate economic hardship on small refineries. Small refineries that are found to be in a 

disproportionate economic hardship situation will receive an extension of the temporary 

exemption for at least two years. 

The Panel also recommended that EPA work with DOE in the development of the small 

refinery study, specifically to communicate the comments that SERs raised during the Panel 

process. 

7.7.1.7 Extensions of the Temporary Exemption Based on Disproportionate Economic 

Hardship 

While SERs did not specifically comment on the concept of hardship provisions for the 

upcoming proposal, the Panel noted that under CAA section 211(o)(9)(B) small refineries may 

petition EPA for case-by-case extensions of the small refinery temporary exemption on the basis 

of disproportionate economic hardship. Refiners may petition EPA for this case-by-case 

hardship relief at any time. 

The Panel recommended that EPA propose in the RFS2 program a case-by-case hardship 

provision for small refineries similar to that provided at 40 CFR 80.1141(e)(1). The Panel also 

recommended that EPA propose a case-by-case hardship provision for small refiners that do not 

operate small refineries that is comparable to that provided for small refineries under section 

211(o)(9)(B), using its discretion under CAA section 211(o)(3)(B). This would apply if EPA 

739 
does not adopt an automatic extension for small refiners, and would allow those small refiners 

that do not operate small refineries to apply for the same kind of extension as a small refinery. 

The Panel recommended that EPA take into consideration the results of the annual update of RIN 

system progress and the DOE small refinery study in assessing such hardship applications. 

7.7.2 Provisions Proposed in the NPRM 

This section describes the provisions being proposed in the preamble to the proposed rule 

related to small refiners. 

7.7.2.1 Delay in Standards 

As discussed in Section IV.B of the preamble to this proposed rule, the RFS1 program 

regulations provide small refiners who operate small refineries (and any refiner who operates a 

small refinery), as well as those small refiners who do not operate small refineries, with a 

temporary exemption from the standards through December 31, 2010. EPA has evaluated an 

additional temporary exemption for small refiners for the required RFS2 standards, and this 

exemption has also been evaluated with respect to EPA’s concerns about the authority to provide 

an extension of the temporary exemption for small refineries that is different from that provided 

in CAA section 211(o)(9). EPA believes that the limitations of the statute do not necessarily 

allow the Agency the discretion to provide an exemption for small refiners only (i.e., small 

refiners but not small refineries) beyond that provided in section 211(o)(9). Thus, EPA is 

proposing to continue the RFS1 temporary exemption through December 31, 2010 for small 

refineries and all qualified small refiners; further, EPA is proposing provisions that address 

extensions of the small refinery/small refiner temporary exemption, as section 211(o)(9) does 

allow for extensions beyond December 31, 2010. We are also requesting comment on the 

interpretation of our authority under the CAA and the appropriateness of providing an extension 

to small refiners only beyond that authorized by section 211(o)(9). 

7.7.2.2 Phase-in 

As discussed above in Section 7.7.1.3, EPA also has concerns that section 211(o) does 

not give the Agency the discretion to allow for a phase-in approach to the standards as it would 

result in different applicable percentages being applied to different obligated parties, provide 

more relief to small refineries operated by small refiners than that provided under the small 

refinery provision. However, we are inviting comment on the concept of a phase-in provision 

for all small refiners. 

7.7.2.3 RIN-related Flexibilities 

With regard to the small refiner SERs’ request that the proposed rule contain provisions 

for small refiners related to the RIN system, we do not believe it would be appropriate to propose 

a change to the RIN rollover cap for small refiners in this action, given the findings from the 

DOE small refinery study (“EPACT 2005 Section 1501 Small Refineries Exemption Study”). 

However, we are requesting comment on the concept of increasing the RIN rollover cap 

percentage for small refiners. We are also requesting comment on an appropriate level of that 

740 
percentage. Further, as recommended by the Panel, we are not proposing to allow RINs to be 

used interchangeably for small refiners; however we are inviting comment on such an approach. 

7.7.2.4 Program Review 

As noted above, we have slight concerns that such a review could lead to some 

redundancy since EPA is required to publish a notice of the applicable RFS standards in the 

Federal Register annually, and this annual process will inevitably include an evaluation of the 

projected availability of renewable fuels. Nevertheless, we agree with the Panel’s 

recommendation on including an update of RIN system progress (e.g., RIN trading, publiclyavailable information on RIN availability, etc.) in the annual Federal Register notice. Thus, we 

are proposing to include elements of RIN system progress—such as RIN trading and 

availability—in the annual Federal Register RFS2 standards notice, and we are requesting 

comment on additional elements to include in this notice. 

7.7.2.5 Extensions of the Temporary Exemption Based on a Study of Small Refinery 

Impacts 

As previously noted, there are two provisions in section 211(o)(9) that allow for an 

extension of the temporary exemption beyond December 31, 2010. One involves the study by 

DOE, as mentioned above, concerning whether compliance with the renewable fuel requirements 

would impose disproportionate economic hardship on small refineries, and would grant an 

extension of at least two years for a small refinery that DOE determines would be subject to such 

disproportionate hardship. Another provision authorizes EPA to grant an extension for a small 

refinery based upon disproportionate economic hardship, on a case-by-case basis. 

We believe that these avenues of relief should be utilized by those small refiners who are 

covered by the small refinery provision; and we believe that it is appropriate to consider allowing 

petitions to EPA for an extension of the temporary exemption based on disproportionate 

economic hardship for those small refiners who are not covered by the small refinery provision 

(again, per our discretion under section 211(o)(3)(B)); to ensure that all small refiners have the 

same relief available to them as small refineries do. 

Thus, we are proposing hardship provisions for small refineries in the RFS2 program 

similar to those provided at 40 CFR 80.1141(e). First, we are proposing to extend the temporary 

exemption for at least two years for any small refinery that DOE’s small refinery study 

determines would face disproportionate economic hardship in meeting the requirements of the 

RFS2 program (per CAA section 211(o)(9)(A)(ii)(I)). Second, we are proposing that any small 

refinery may apply for a case-by-case hardship at any time on the basis of disproportionate 

economic hardship per section 211(o)(9)(B). 

As discussed in section IV.B.2.c of the preamble to the proposed rule, the findings from 

DOE’s small refinery study indicate that no small refineries are subject to disproportionate 

economic hardship under the proposed RFS2 program and that the small refinery exemption 

should not be extended beyond December 31, 2010. However, DOE noted in the study that if 

circumstances were to change and/or the RIN market became non-competitive or illiquid, 

741 
individual small refineries have the ability to petition EPA for an extension of their small 

refinery exemption. 

For those small refiners that do not operate small refineries, we are also proposing a caseby-case hardship provision using our discretion under CAA section 211(o)(3)(B). Such a 

provision would allow those small refiners that do not operate small refineries to apply for the 

same kind of case-by-case extension as a small refinery. 

7.8 Conclusions 

Based on our outreach, fact-finding, and analysis of the potential impacts of our 

regulations on small businesses, the Panel concluded that the proposed provisions for small 

refiners would be beneficial in minimizing the effects of the proposed rule on small refiners. 

Of the 15 small entities with publicly available sales data, we were able to estimate 

annual costs, and thus use this information to complete a preliminary screening analysis. To 

perform this analysis, we used a cost-to-sales ratio test (a ratio of the estimated annualized 

compliance costs to the value of sales per company). Costs were analyzed using both a 

“Reference Case” crude oil cost of $53 per barrel and a “High Case” crude oil cost of $92 per 

barrel. 

For the 14 small refiners with available data, we found that: 21 percent (3 refiners) of 

small refiners were affected at less than 1 percent of their sales (i.e., the estimated costs of 

compliance with the proposed rule would be less than 1 percent, of their sales) and 79 percent 

(11 refiners) were affected at greater than 3 percent of their sales using the Reference Case costs. 

Using the High Case costs, all small refiners were affected at less than 1 percent of their sales. 

Please note that these costs do not include the available subsidies for the blending of ethanol of 

45 cents per gallon for ethanol and $1.00 per gallon for biodiesel/renewable diesel. Thus, the 

actual compliance costs will be considerably lower. 

For a complete discussion of the economic impacts of the proposed rulemaking, see 

Chapter 5, the economic impact analysis chapter, of this Draft Regulatory Impact Analysis. 

742 
Appendix A: Biodiesel Effects on Heavy-Duty Highway Engines 

and Vehicles 

A.1 Executive Summary 

Due to the continuing interest in the use of biodiesel fuels, the Environmental Protection 

Agency has conducted a comprehensive analysis of the emission impacts of biodiesel using 

publicly-available heavy-duty, in-use diesel chassis and engine exhaust emissions data. 

We investigated the emission impacts on NOx, PM, HC, and CO of 20 volume percent 

biodiesel fuels produced from various animal- and plant-based feedstock materials tested under 

several cycles in this analysis. Average NOx emissions were found to increase 2.2%, while PM, 

HC, and CO were found to decrease 15.6%, 14.1%, and 13.8% respectively, for all test cycles 

run on 20 vol% soybean-based biodiesel fuel at a significance level of P < 0.05 (See Table A.1­

1). 

Table A.1-1. 

Emission impacts for all cycles tested on 20 vol% soybean-based 

biodiesel fuel relative to an average base fuel
 

Emissions Percent Change in 

Emissions 

NOx 

PM 

HC 

CO 

+2.2% 

-15.6% 

-14.1% 

-13.8% 

These results are consistent with the exhaust emission impacts for heavy-duty, in-use 

diesel engines found in our 2002 Draft Technical Report, entitled "A Comprehensive Analysis of 

Biodiesel Impacts on Exhaust Emissions." This report can be found in the docket to this 

rulemaking, EPA-HQ-OAR-2005-0161. 

The current analysis also found that heavy-duty engine dynamometer data was 

statistically indistinguishable from heavy-duty chassis dynamometer data for NOx and HC at a 

significance level of p < 0.05. Likewise, results for Detroit Diesel Corporation (DDC) engines, 

used in many test programs, were found to be statistically similar to results for other engines for 

NOx, CO, and HC at a significance level of p < 0.05. 

The results of the current analysis also point to a load-dependence of NOx emissions for 

heavy-duty highway engines and chasses. The difference in NOx emissions between our results 

here and those of various other researchers appears to be attributable to an artifact of the selected 

test cycle profile. Analyzing the NOx emissions data as a function of load, as we do here -- as 

opposed to a particular test cycle profile -- reconciles the difference and supports the NOx 

emission-load-dependence hypothesis for heavy-duty highway engines and chasses posited by 

Sze et al. and corroborated by Eckerle et al. 

743 
 

A.2 Biodiesel Effects on Heavy-Duty Highway Engines and Vehicles 

A.2.1 Introduction 

We investigated the emission impacts on NOx, PM, CO, and HC of 20 volume percent 

(vol%) biodiesel fuels produced from various feedstock materials tested under several vehicle 

and engine test cycles. The data used in this analysis is comprised of data used in EPA's 2002 

Draft Technical Report, entitled "A Comprehensive Analysis of Biodiesel Impacts on Exhaust 

Emissions Draft Technical Report", hereafter referred to as the 2002 Draft Technical Report. 

Data from that report was supplemented with pertinent data sources published in the scientific 

and automotive literature between 2002 and 2007. The supplemental data was comprised of late 

model year engines, vehicles, and technology groups. A list of all data sources used in this 

analysis appears in the appendix. 

The focus of the analysis proceeded from general to specific terms, through seven fuelcycle combinations, summarized below. In Case 1, the most-general fuel-cycle combination, we 

examined all heavy-duty engine and chassis cycles run on plant- and animal-based biodiesel 

fuels; in Case 5a, 5b, and 5c, the most-specific fuel-cycle combinations, we examined heavyduty engine and chassis data for light-, medium-, and heavy-duty cycles using soybean-based 

biodiesel. The latter analysis was designed to examine load-dependence of NOx emissions for 

heavy-duty highway engines and chasses first posited by EPA in 2007 (see Sze et al.). This 

research was further elucidated by Eckerle et al. While feedstock materials varied for the seven 

fuel-cycle combinations presented here, all analyses were conducted using 20 vol% biodiesel 

fuels. 

A summary of fuel-cycle combinations used in the analysis appears below. 

• Case 1: All cycles tested on plant-based (soybean, rapeseed/canola, and coconut) and 

animal-based (tallow, lard, and grease) biodiesel fuels, 

• Case 2: All cycles tested on soybean-based biodiesel fuel, 

• Case 3: FTP and UDDS cycles tested on soybean-based biodiesel fuel, 

• Case 4: Detroit Diesel Corporation (DDC) and non-DDC engines tested on 

 soybean-based biodiesel fuel, 

• Case 5a: Engines and chasses tested on soybean-based biodiesel fuel run on light-duty 

cycles, 

• Case 5b: Engines and chasses tested on soybean-based biodiesel fuel run on 

 medium-duty cycles, and 

• Case 5c: Engines and chasses tested on soybean-based biodiesel fuel run on heavy-duty 

cycles. 

744
 
The results of the analysis of the seven fuel-cycle combinations appear in Section 

A.2.3.2. The results of the analysis of the NOx emissions load-dependence appear in Section 

A.2.3.3 and a discussion of the observed load-dependence impacts in the context of relevant 

literature and the 2002 Draft Technical Report appear in Section A.2.3.4. 

In the 2002 Draft Technical Report, we focused our analysis on data from heavy-duty 

highway engines, since this data was the most abundant in our database and since it was unclear 

to what extent testing on a chassis dynamometer might differ from testing on an engine 

dynamometer. However, some researchers criticized the conclusions of the report for its 

disproportionate reliance on engine data. These researchers argued that these engines may not 

behave in a manner indicative of the actual, in-use fleet or that chassis-generated data may be 

better-suited for NOx emissions testing. 

Some researchers also criticized the conclusions of our 2002 Draft Technical Report, 

citing its disproportionate reliance on DDC engine data. These researchers argued that these 

engines may not behave in a manner indicative of the actual, in-use fleet as a whole. To help 

address these concerns, we supplemented the database for the 2002 Draft Technical Report with 

non-DDC engine data. In the current analysis, non-DDC engines represent 59.0% of all engines 

present in the supplemented database. 

To investigate these concerns, we carried out an analysis to determine the compatibility 

of heavy-duty highway engine data with heavy-duty highway chassis data. Establishing 

compatibility between heavy-duty highway engine data and heavy-duty highway chassis data 

would allow us to make more-complete use of all emissions data in the database. In turn, this 

would allow us to perform more robust statistical analyses. The results of this engine and chassis 

data compatibility analysis are presented in Section A.2.3.1. Section A.2.2 contains a discussion 

of the data screening criteria and methodology used in this analysis. 

A.2.2 Data screening and methodology 

The data used in this analysis is comprised of data initially used in our 2002 Draft 

Technical Report, supplemented by pertinent data published between 2002 and 2007. The 

supplemental data included late model year engines, vehicles, and technology groups. A list of 

data sources used in this analysis appears in the appendix to this document. 

A criticism raised by the 2002 Draft Technical report was that its analysis relied too 

heavily upon data from early model year engines and that these engines may not behave in a 

manner indicative of the actual, in-use fleet as a whole. To help address this concern, we 

supplemented the existing database of over 800 observations with approximately 560 additional 

observations comprised of late model year engines, vehicle, and technology groups. 

Candidate data were first screened to verify that they met EPA data QC/QA requirements 

as well as criteria consistent with the goals of the analysis before inclusion into the database (See 

Section II of the 2002 Draft Technical Report for a discussion of EPA data QC/QA 

considerations). New data meeting these criteria were entered into the database developed for 

the 2002 Draft Technical Report. These criteria are described in Section A.2.2.1. 

745 
A.2.2.1 Criteria for selecting data 

Candidate data were screened to verify that they met criteria consistent with the goals of 

the analysis before inclusion into the database. For instance, the analysis was limited to No. 1 

and No. 2 diesel fuel and related blends that can be used in typical heavy-duty diesel engines 

without engine modifications. As a result, all emulsions and non-biodiesel oxygenated blends 

with more than 20 vol% oxygenate were excluded from the final database used in the analysis. 

Also, synthetic fuels, such as those produced using the Fischer-Tropsch process, rather than 

refinery streams, were excluded from the final database. 

We also limited this study to vehicles and engines that had already been sold 

commercially or had a high probability of being sold in the future. Vehicles and engines with 

experimental technologies that had no immediate plans for commercialization, such as those with 

innovative combustion chamber geometries, were excluded from the database. Likewise, singlecylinder research engines were excluded from consideration, even though the associated full-size 

parent engine might have been appropriately included in the database, had it been tested. Singlecylinder engines do not appear in heavy-duty applications. By definition, such engines have 

lower total horsepower and displacement, both of which may influence the way in which 

biodiesel impacts emissions. 

The pairing of diesel and biodiesel fuels used in a particular study also played a role in 

determining if data from that study would be included in our analysis. For example, we excluded 

data from all studies that did not test at least two different biodiesel concentrations on the same 

engine, one of which could be 0 vol% biodiesel. 

There were a number of instances in which data from one study was repeated in other 

studies. This might occur if the authors published the same dataset in multiple scientific journals 

to maximize exposure, or if the authors presented a previously-published set of data in a new 

publication for the purposes of comparing the two datasets. Such duplicative data was also 

excluded from our database. 

Also, each prospective data source was screened to verify that it contained raw, not 

aggregated, data. In cases where raw data was not published in a study, attempts were made to 

obtain it from the study author(s). Raw data obtained from author(s) were included in our 

database after successful screening. 

A.2.2.2 Criteria for selecting test cycles 

We selected cycles which were representative of actual, in-use operating conditions. 

While the Federal Test Procedure (FTP) transient cycle most-closely reflects actual, in-use 

operating conditions, we included data from a number of other studies that used atypical test 

cycles which were adequately comprehensive in their number, selection of modes, and/or in their 

transient speed-load traces, so that the resulting emission measurements may still be informative. 

746
 
Data collected under test cycles that were unique, contained only a single steady-state 

mode, or used two- or three-nonstandard modes for testing, were typically excluded from the 

database. Non-FTP/UDDS test cycles represented about 24 percent of all data in the database. 

A total of eight different cycles, with two variants, representing a variety of load levels 

were included in our database. A description of the test cycles included in our analysis appears 

below. 

• AVL 8-Mode Test – An eight-mode steady-state engine test procedure, designed to 

correlate with FTP cycle exhaust emission results. Only NOx emissions data generated 

by the AVL 8-Mode test was included in our database. 

• Combined International Local Cycle and Commuter (CILCC) – A transient cycle 

developed by NREL for testing Class 4 to Class 6 vehicles. It is intended to simulate 

urban delivery driving conditions for heavy-duty vehicles. 

• City-Suburban Heavy-Vehicle Cycle (CSHVC) – A transient cycle developed by West 

Virginia University. It is intended to simulate low-speed urban/ suburban driving 

conditions of heavy-duty vehicles and is punctuated with frequent stops. 

• Freeway Cycle – A transient cycle intended to simulate four-lane highway driving 

conditions of heavy-duty vehicles, including entrance and exit ramps. 

• Federal Test Procedure (FTP) – The heavy-duty transient cycle currently used by EPA 

for emission, certification, and other testing of heavy-duty on-road engines; the cycle 

most-closely reflects actual, in-use operating conditions and was developed to simulate a 

variety of heavy-duty truck and bus driving conditions in cities and on expressways. 

• Highway Cycle (HWY) – A high-speed highway cruise cycle based on the Heavy 

Heavy-Duty Diesel Truck chassis cycle developed by the California Air Resources Board 

and previously used in the Coordinating Research Council E-55 program. 

• Rowan University Composite School Bus Cycle (RUCSBC) – A school bus cycle 

developed by Rowan University. 

• Urban Dynamometer Driving Schedule (UDDS) – A heavy-duty chassis dynamometer 

test. Our database includes data from the UDDS cycle and two variants simulating light 

(6,000 lbs) and heavy (28,000 lbs) test weight conditions. 

The summary of the test cycles included in our analysis appears in Table A.2-1. 

747 
Table A.2-1. Test cycles included in this analysis 

Test Cycle Description Duration 

AVL 8 Eight-mode steadystate cycle n/a 

CILCC Heavy-duty urban 

delivery cycle 

53 min 

12 sec 

CSHVC 

Heavy-duty citysuburb low-speed 

cycle 

28 min 

20 sec 

Freeway Heavy-duty highway 

cycle 

27 min 

20 sec 

FTP Heavy-duty engine 

certification cycle 20 min 

HWY High-speed cruise 

cycle from CRC E-55 

12 min 

40 sec 

RUCSBC School bus cycle 21 min 

50 sec 

UDDS Heavy-duty chassis 

cycle 

17 min 

40 sec 

UDDS 6k UDDS variant based 

on EPA data 

17 min 

40 sec 

UDDS 28k UDDS variant based 

on CRC E-55 data 

17 min 

40 sec 

A.2.2.3 Criteria for selecting feedstock materials 

Biodiesel fuel can be produced from a wide variety of feedstock materials. While the 

studies that comprise our database included only a portion of the many feedstock materials 

possible, they do represent the most-common feedstock materials. The biodiesel feedstock 

materials found in our database and their percentages are listed in Table A.2-2. 

748
 
 

Table A.2-2. Biodiesel feedstock materials in the database 

Feedstock 

Materials 

Number of 

Observations 

Percentage of 

Observations 

Soybean 556 77.1% 

Rapeseed/Canola 95 13.2% 

Grease a 42 5.8% 

Tallow 19 2.6% 

Coconut 6 0.8% 

Lard 3 0.4% 

a Includes high free fatty acid (HFFA) and low free fatty acid (LFFA) 

Given the limited data available for some feedstock materials, we aggregated all biodiesel 

feedstock materials into three general categories: plant-based biodiesel, soybean-based biodiesel 

(a subset of plant-based biodiesel), and animal-based biodiesel (See Table A.2-3 for a listing of 

biodiesel feedstock materials aggregated into the categories used in our database). 

Table A.2-3. 

Biodiesel feedstock materials aggregated 

into categories used in the database 

Aggregated Feedstock 

Material Category 

Number of Observations 

in Category 

Plant-based 657 

Soybean-based 556 

Animal-based 64 

A.2.2.4 Overview of methodology 

This section summarizes the statistical approach used in this analysis, which employed 

the SAS/STAT software procedure PROC MIXED. This procedure can treat some variables as 

fixed-effects and others as random-effects. 

For instance, the NOx fixed-effect was expressed as a function of percent biodiesel (0 or 

20 vol%), vehicle class (Class 1-2a or Class 2b-8), the interaction of percent biodiesel and 

vehicle class, test cell type (chassis test cell or engine test cell), and the interaction between test 

cell type and percent biodiesel. Each fixed-effect term is tested and removed if found not 

749 
 

significant. Additional fixed-effect terms were added to the model when examining DDC and 

non-DDC engines. The random-effects examined were the test cell type and its interaction with 

percent biodiesel, test cycle, and the biodiesel source. 

After creating the initial model, the distribution of mixed-model residuals are examined; 

residuals with absolute values greater than four standard deviations from a mean of 0 are 

considered outliers and removed from further consideration. 

The final model evaluates the statistical significance of the difference between fuels 

containing 20 vol% biodiesel and the base fuel, containing no biodiesel. A significance criterion 

of p < 0.05 was used for all analysis. See Section II of the 2002 Draft Technical Report for 

additional discussion and derivations. 

A.2.3 Results 

This section contains the results of the biodiesel emissions impact analysis described in 

Section A.2.2. The results of the analysis of the compatibility of heavy-duty highway chassis 

and engine data appear in Section A.2.3.1. The results of the analysis of the seven fuel-cycle 

combinations appear in Section A.2.3.2, including the analysis of DDC engines versus non-DDC 

engines. The results of the analysis of the NOx emissions load-dependence appear in Section 

A.2.3.3 and a discussion of the observed load-dependence impacts placed in the context of 

relevant literature and the 2002 Draft Technical Report appear in Section A.2.3.4. 

A.2.3.1 Compatibility of heavy-duty highway chassis and engine data 

The primary objective of the analysis was to quantify the impacts of biodiesel fuels. One 

aspect of the analysis was to determine if heavy-duty highway emissions engine data in our 

database was comparable to heavy-duty highway chassis data for purposes of our statistical 

analysis. Much of the database (66%) consisted of heavy-duty highway engine data, with the 

balance of the data comprising heavy-duty highway chassis data. Establishing compatibility 

between engine and chassis data would allow us to make more complete use of all emissions data 

in the database, which, in turn, would allow us to perform more robust statistical analyses. 

Moreover, some researchers criticized the conclusions of our 2002 Draft Technical 

Report, citing its disproportionate reliance on engine data. These researchers argued that these 

engines may not behave in a manner indicative of the actual, in-use fleet as a whole or that 

chassis-generated data might be better-suited for purposes of biodiesel emissions testing. To 

investigate these claims, we undertook an analysis to determine the compatibility of heavy-duty 

highway engine data with heavy-duty highway vehicle data. 

Using a significance level of p < 0.05 for all statistical analysis, engine data was found to 

be statistically comparable to chassis data for NOx and PM emissions. This finding is supported 

by the research of NREL, whose examination of published data suggests that there exists no 

discrepancy between engine and vehicle testing data (See NREL Milestone 10.4). See Table 

A.2-4 for a summary of fuel-cycle combinations for which heavy-duty highway engine data was 

statistically comparable to heavy-duty highway chassis data for regulated pollutants. 

750
 
 

 

 

Table A.2-4. 

Fuel-cycle combinations for which heavy-duty highway engine 

data was statistically comparable to heavy-duty highway 

chassis data for regulated pollutants 

Regulated Pollutants 

NOx PM CO HC 

Fuel-Cycles 

Case 1 x X 

Case 2 x X 

Case 3 x X 

Case 4 x X 

Case 5a x X 

Case 5b x X 

Case 5c x X 

x denotes heavy-duty highway engine data that is statistically 

comparable to heavy-duty highway chassis data. 

Emissions of PM and CO for heavy-duty highway engines and chasses were not found to 

be statistically comparable to each other for any of the seven fuel-cycle combinations. Based 

upon our experience with chassis test cells, it is difficult to accurately quantify PM exhaust 

emissions, as chassis-based testing is often deficient and non-standardized vis-à-vis 40CFR86­

2007 and 40CFR1065 for test specification and test equipment, respectively. Deficiencies 

associated with non-standardized chassis test cells may produce high test-to-test variability. 

Likewise, CO emissions are difficult to accurately quantify on both heavy-duty engine and 

chassis test cells and may also produce high test-to-test variability. 

High test-to-test variability curtails the ability to accurately capture and discern small 

differences in exhaust emissions, particularly PM and CO exhaust emissions. This variability 

may help to explain why engine and chassis data are not comparable in our analysis for CO and 

PM emissions. 

In cases where heavy-duty highway engine data is statistically comparable to heavy-duty 

highway chassis data, engine and chassis data are pooled to produce the appropriate statistic. In 

other cases, we believe that the use of engine data alone results in a more-representative statistic, 

which we report here. The results for the following analysis reflect this approach. 

A.2.3.2 Fuel-cycle results 

Seven fuel-cycle combinations were identified for our statistical analysis, ranging from a 

general case, combining testing of all test cycles and all cycles and on all biodiesel fuel feedstock 

materials to cycles aggregated into light-, medium-, and heavy-duty test cycle categories, which 

were run exclusively on 20 vol% soybean-based biodiesel fuel. Heavy-duty highway engine and 

chassis emissions data were statistically comparable for NOx and HC and were subsequently 

751 
pooled for our analysis. Heavy-duty highway engine and chassis emissions data were not 

statistically comparable for PM and CO, so only engine results are presented here. The results 

for each of the seven fuel-cycle combinations appears below. All results presented are 

statistically significant at a significance level of p < 0.05. 

Case 1: All cycles tested on all biodiesel fuels 

Our first fuel-cycle combination examined data collected on all cycles included in the 

database and from all vehicles and engines tested on both plant-based (soybean, rapeseed/canola 

and coconut) and animal-based (tallow, lard, and grease) biodiesel fuels (See Table A.2-1 for a 

listing of all cycles used in the Case 1, Case 2, and Case 4 analyses). 

For plant-based and animal-based biodiesel fuels, NOx emissions were found to increase 

a statistically-significant 2.0% relative to the base fuel, whereas, PM, CO, and HC emissions 

were found to decrease by 13.6%, 13.5%, and 18.7%, respectively, relative to the base fuel. 

Case 2: All cycles tested on soybean-based biodiesel fuels 

Our second fuel-cycle combination examined all cycles specified in Case 1, but only 

involved vehicles and engines tested on soybean-based biodiesel fuels. 

For soybean-based biodiesel, NOx emissions were found to increase by 2.2%, whereas 

PM, CO, and HC emissions were found to decrease by 15.6%, 13.8%, and 14.1%%, respectively, 

relative to the base fuel. Case 1 and Case 2 differ in their fuel composition. The biodiesel tested 

in Case 1 is composed of 20 vol% animal- and plant-based biodiesel, whereas in Case 2, the fuel 

is composed of 20 vol% soybean-based biodiesel only. The results suggest that the removal of 

animal-based and/or rapeseed/canola/coconut-based biodiesel fuel feedstock materials may have 

a slight impact on some exhaust emissions. Increases in emissions of 0.2 %, 2.0%, and 0.3% are 

observed for NOx, PM, and CO, respectively, relative to a soybean-based biodiesel discussed in 

Case 2. HC emissions decrease by 4.6% relative to a soybean-based biodiesel. 

Several hypotheses have been advanced by researchers in an attempt to help explain the 

differences in exhaust emissions between plant-based and animal-based biodiesel feedstock 

materials; these are, however, outside the scope of the current analysis and are not discussed 

here. 

Case 3: FTP and UDDS cycles tested on soybean-based biodiesel fuels 

Our third fuel-cycle combination examined only engines and vehicles tested on soybeanbased biodiesel fuel over only the FTP and UDDS cycles. Together, FTP and UDDS cycles 

comprise 76% of the database observations. 

For soybean-based biodiesel, NOx emissions were found to increase by 3.2%, whereas 

PM, CO, and HC emissions were found to decrease by 15.6%, 15.9%, and 13.7%, respectively, 

relative to the base fuel. 

The results of this analysis suggest that the emission impacts associated with heavy-duty 

highway engines and chasses tested on 20 vol% soybean-based biodiesel and run on FTP/UDDS 

cycles produce an increase in exhaust emissions of 1.0% for NOx and 2.1% for CO, relative to 

all engine and chassis cycles run on the same fuels. HC emissions decrease by 0.4% relative to 

752
 
 

all engine and chassis cycles and PM emissions appear to be relatively unaffected. These results 

were statistically significant at a significance level of p < 0.05. 

As the FTP and UDDS cycles may more-closely represent actual, in-use operating 

conditions encountered by heavy-duty highway engines and vehicles, it is possible that the Case 

3 results may be a better indicator of actual, in-use biodiesel emissions impacts. 

Case 4: DDC vs. non-DDC engines tested on soybean-based biodiesel fuels 

Our fourth fuel-cycle combination separately examined DDC and non-DDC engines 

tested on the cycles specified in Case 1 and Case 2 using soybean-based biodiesel fuel. 

Our analysis found that DDC heavy-duty engine data was statistically comparable to nonDDC heavy-duty engine data for NOx, CO, and HC emissions at a significance level of p < 0.05. 

DDC heavy-duty engines and non-DDC heavy-duty engines did not behave in a statistically 

similar manner for PM emissions, however. In this regard, the results of our analysis suggest 

that DDC heavy-duty engines behave in the same manner in which non-DDC heavy-duty 

engines behave in our database for NOx, CO, and HC emissions. As such, this finding should 

help alleviate earlier concerns that the disproportionate representation of DDC engines may 

produce results which are not indicative of the database as a whole or the in-use fleet. 

Case 5a: Light-duty cycles tested on soybean-based biodiesel fuels 

Our fifth fuel-cycle combination examined heavy-duty engine and chassis data for lightduty cycles specified in Table A.2-5 and tested on soybean-based biodiesel fuel. 

For soybean-based biodiesel tested on light-duty cycles, NOx, PM, CO, and HC 

emissions were found to decrease by 1.0%, 19.0%, 9.9%, and 14.2% respectively, relative to the 

base fuel. 

753 
Table A.2-5. Cycle composition by case 

Case Number Case Description Individual 

Cycles 

Case 5a Light-duty cycles 

CILCC 

CSHVC 

UDDS6k 

Case 5b Medium-duty 

cycles 

AVL8 (NOx) 

Freeway 

FTP 

RUCSBC 

UDDS 

UDDS28k 

Case 5c Heavy-duty cycles HWY55 

Case 5b: Medium-duty cycles tested on soybean-based biodiesel fuels 

Our sixth fuel-cycle combination examined heavy-duty engine and chassis data for 

medium-duty cycles specified in Table A.2-5 and tested on soybean-based biodiesel fuel. 

For soybean-based biodiesel tested on medium-duty cycles, NOx emissions were found 

to increase by 2.5%, relative to the base fuel, whereas PM, CO, and HC emissions were found to 

decrease by 19.0%, 14.0%, and 14.2%, and respectively, relative to the base fuel. 

Case 5c: Heavy-duty cycles tested on soybean-based biodiesel fuels 

Our seventh fuel-cycle combination examined heavy-duty engine and chassis data for 

heavy-duty cycles specified in Table A.2-5 and tested on soybean-based biodiesel fuel. 

For soybean-based biodiesel tested on heavy-duty cycles, NOx emissions were found to 

increase by 5.1%, relative to the base fuel, whereas PM, CO, and HC emissions were found to 

decrease by 32.6%, 22.0%, and 14.2%, respectively, relative to the base fuel. Unlike Case 5a 

and 5b, the PM emissions results were significant and greater than those of the light-duty and 

medium-duty cases. A summary of these results appears in Table A.2-6. 

754
 
 

 

 

Table A.2-6. 

Summary of emissions results for seven fuel-cycle combinations 

for heavy-duty highway engines and chasses 

Regulated Pollutants 

NOx PM a CO a HC 

Fuel-Cycles 

Case 1 +2.0% -13.6% -13.5% b -18.7% 

Case 2 +2.2% -15.6% -13.8% -14.1% 

Case 3 +3.2% -15.6% -15.9% -13.7% 

Case 4 +2.4% -16.9% -13.9% -14.3% 

Case 5a -1.0% 

-19.0% 

-9.9% 

Case 5b +2.5% -14.0% -14.2%

Case 5c +5.1% -32.6% -22.0% 

a Only engine data. 

b

 Not significant.
 

A.2.3.3 Load-dependant emissions impacts 

We initially identified the load-dependence of NOx emissions in heavy-duty highway 

engines in 2007 (See Sze et al.) and these results were later corroborated by Eckerle et al. The 

results of Sze et al. and Eckerle et al. were based largely upon new engine and chassis studies (as 

well as modeling efforts), which were aimed specifically at examining the load-dependent NOx 

emissions phenomenon. 

In the current research, however, our work is retrospective insofar as we examined data 

from a broad array of pre-existing studies, none of which were designed to examine the loaddependant NOx emissions impacts. As such, this analysis occasionally suffers from the 

experimental design limitations associated with the pre-existing studies. One such limitation is 

the use of test cycles which do not realistically reflect actual, in-use operating conditions. Such 

data can skew results and obscure evidence of the load-dependence of NOx emissions. Such a 

situation is discussed in Case 5a. 

Case 5a, 5b, and 5c: Load-dependant emissions impact on NOx 

The load-dependence of NOx emissions observed in this analysis is apparent when 

comparing Case 5a (light-load cycles) to Case 5b (medium-load cycles) to Case 5c (heavy-load 

cycles). However, results for the light-load conditions in Case 5a may not be representative of 

in-use vehicle operation. 

Case 5a: Confounding effects of lightly-loaded conditions 

The load-dependence of NOx emissions evident in the research of Sze et al. and Eckerle 

et al. was based upon medium- and heavy-duty cycles, not lightly-loaded cycles as in Case 5a. 

755 
 

 

We believe that our current findings for NOx emissions under lightly-loaded conditions 

may not be representative of the operating conditions typically encountered in actual, in-use fleet 

operations. As in-use heavy-duty highway engines and vehicles do not typically operate under 

the lightly-loaded conditions encountered in the cycles which comprise our light-duty category, 

the practical significance of the NOx emissions results for Case 5a is questionable. 

Further, the NOx emissions results for Case 5a are also suspect when compared to Cases 

1-4 and 5b-5c, all of which indicate that there is a statistically-significant increase in NOx 

emissions of between 2.0% and 5.1%. 

As such, we place greater significance on the results obtained under medium- (Case 5b) 

and heavy-load (Case 5c) conditions, since they more-accurately mirror typical, in-use fleet 

operations and, as a result, provide a more realistic representation of operating conditions 

encountered in-use. 

Case 5b vs. Case 5c: Load-dependant NOx emission impacts 

Since the medium-loading conditions associated with these cycles are typical of actual, 

in-use fleet operations, these cycles provide a more realistic representation of operating 

conditions encountered by actual fleet usage. As such, we place greater significance on these 

results. 

The difference in NOx emissions between our results here and those of other researchers 

appears to be attributable to an artifact of the selected test cycle profile. Analyzing the NOx 

emissions data as a function of load, as we do here -- as opposed to a particular test cycle profile 

-- reconciles the difference and supports the NOx emission-load-dependence hypothesis for 

heavy-duty highway engine and chasses posited by Sze et al. and corroborated by Eckerle et al. 

The discussion of load-dependant NOx emission impacts in the context of our research appears 

in Section A.2.3.4. 

A.2.3.4 Relevant studies 

We initially identified the load-dependence of NOx emissions in heavy-duty highway 

engines in 2007 (See Sze et al.) and these results were later corroborated by Eckerle et al. The 

results of Sze et al. and Eckerle et al. were based largely upon new engine and chassis studies (as 

well as modeling efforts), which were aimed specifically at examining the load-dependent NOx 

emissions phenomenon. 

In the current research, however, our work is retrospective insofar as we examined data 

from a broad array of pre-existing studies, none of which were designed to examine the loaddependant NOx emissions impacts. As such, this analysis occasionally suffers from the 

experimental design limitations associated with the pre-existing studies. One such limitation is 

the use of test cycles which do not realistically reflect actual, in-use operating conditions. Such 

data can skew results and obscure evidence of the load-dependence of NOx emissions. Such a 

situation is discussed in Case 5a. 

756
 
 

2002 Draft Technical Report 

In 2002, the EPA conducted a comprehensive analysis of the emission impacts of 

biodiesel using publicly available data. Entitled "A Comprehensive Analysis of Biodiesel 

Emissions Impacts on Exhaust Emissions," the 2002 Draft Technical Report made use of 

statistical regression analysis to correlate the concentration of biodiesel in conventional diesel 

fuel with changes in regulated and unregulated pollutants for heavy-duty highway engines. 

Figure A.2-1 presents basic emission correlations for NOx, PM, CO, and HC developed 

in the 2002 Draft Technical Report as a function of soybean-based biodiesel concentration. 

Table A.2-7 presents results specifically for 20 vol% soybean-based biodiesel. 

757 
P

ercent chang

e in

e

missions

 

Figure A.2-1. 

Emission impacts from the 2002 Draft Technical Report by percent biodiesel content for 

soybean-based biodiesel added to an average base fuel 

20% 

10% 

0% 

-10% 

-20% 

-30% 

-40% 

-50% 

-60% 

-70% 

-80% 

0 20 40 60 80 100 

NOx 

PM 

CO 

HC 

Percent biodiesel 

Table A.2-7. 

Emission impacts from the 2002 Draft Technical Report 

for 20 vol% soybean-based biodiesel added to an average base fuel 

Emissions Percent Change in 

Emissions 

NOx 

PM 

HC 

CO 

+2.0% 

-10.1% 

-21.1% 

-11.0% 

We found that the results of the current analysis, which examined heavy-duty highway 

engine and chassis data, are consistent with the findings of our 2002 Draft Technical Report, 

which examined heavy-duty highway engine data only. Compared to the 2002 Draft Technical 

Report, NOx emissions were found to increase 2.2% while PM, HC, and CO emissions were 

found to decrease by 15.6%, 14.1%, and 13.8%, respectively, in the current study. These are 

shown in Figure A.2-2 as points overlaid on the results of the 2002 Draft Technical Report. 

758
 
P

ercent chang

e in

e

missions

 

 

Figure A.2-2. 

Emission impacts from the 2002 Draft Technical Report by percent biodiesel content for 

soybean-based biodiesel added to an average base fuel 

with new results overlaid 

20% 

10% 

0% 

-10% 

-20% 

-30% 

-40% 

-50% 

-60% 

-70% 

-80% 

0 20 40 60 80 100 

NOx 

PM 

CO 

HC 

Percent biodiesel 

SAE paper by Sze et al. 

Sze et al. conducted a series of paired fuel tests comparing certification-grade highway 

diesel fuels with 5 to 50 vol% soybean-based biodiesel blends. Each fuel pair was tested for up 

to seven transient cycles representing various load conditions, using a 2006 model year Cummins 

ISB compression ignition engine. 

The authors concluded that biodiesel NOx impact on the test engine is directly 

proportional to average cycle power or fuel consumption and biodiesel content (See Figure A.2­

3). 

759 
45 

Figure A.2-3. 

NOx emissions for 20 vol% and 50 vol% soybean-based biodiesel fuel versus average cycle 

power for various heavy-duty highway engine and chassis cycles 

NOx (Biodiesel Blend) - NOx (B0), (g/hr) 

5 

0 

R2 = 0.99 

R2

 = 0.99 

10 

15 

20 

25 

30 

35 

40 

0 20 40 60 80 100 120 140 160 

Average Cycle Power (hp) 

B20 HWY 

B20 FTP 

B20 WHTC 

B20 UDDS 28k 

B20 UDDS 6k 

B20 HWY 172 

B20 NRTC 

B50 HWY 

B50 FTP 

B50 UDDS 28k 

B50 UDDS 6k 

Except for the most lightly-loaded cycle, the results show statistically significant 

differences in NOx emissions for all fuel pairs. The average NOx emissions due to biodiesel 

were found to increase over each cycle, ranging from 0.9 to 6.6% for 20 vol% and 2.2 to 17.2% 

for 50 vol% biodiesel fuels. The load-dependence of NOx emissions observed by Sze et al. is 

consistent with the findings presented in this report for Cases 5a, 5b, and 5c as well as those of 

Eckerle et al. 

To further elucidate the load-dependent nature of NOx emissions, Sze et al. reanalyzed 

chassis-generated NOx emissions data from NREL as a function of fuel consumption (a 

surrogate for average cycle power) and found it to be in close agreement with EPA engine test 

data. This is depicted in Figure A.2-4. Data from NREL using the same engines tested instead 

on a chassis dynamometer are also shown in the figure and follow the same trend, with an R2

 = 

0.99 with and without the inclusion of the NREL dataset. 

760
 
Figure A.2-4. 

NOx emissions for 20 vol% soybean-based biodiesel fuel versus average cycle power for 

various heavy-duty highway engine and chassis cycles, 

including NREL chassis testing data 

45 B20 NREL chassis data 

B20 HWY

40 B20 FTP R2

 = 0.996
 

B20 WHTC
 35 B20 UDDS 28k 

B20 UDDS 6k
 

30
 B20 HWY 172
 

B20 NRTC
 

0 5 10 15 20 25 30 

Fuel Consumption (kg/hr) 

B50 HWY 25 

B50 FTP 

B50 UDDS 28k 20 B50 UDDS 6k 

With NREL chassis data 

15
 R2

 = 0.99
 

10
 

Without NREL chassis data
 

5
 R2 = 0.99 

0 

NOx (Biodiesel Blend) - NOx (B0), (g/hr) 

SAE paper by Eckerle et al. 

The load-dependence of NOx emissions was also examined by Eckerle et al., who 

generated engine data using 20 vol% soybean-based biodiesel to calibrate chemical kinetic 

models. These models were used to examine NOx production during the combustion process. 

The authors concluded that the NOx effect associated with burning biodiesel blends over a duty 

cycle depends, in part, on the duty cycle average power and that higher duty cycle average power 

corresponded to larger increases in NOx emissions. 

761 
Appendix to Biodiesel Effects on Heavy-Duty Highway Engines and Vehicles 

Studies included in database 

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Bouché, T., M. Hinz, R. Pitterman, "Optimising Tractor CI Engines for Biodiesel Operation," 

SAE paper no. 2000-01-1969 

Callahan, T.J., C.A. Sharp, "Evaluation of Methyl Soyate/Diesel Fuel Blends as a Fuel for Diesel 

Engines," Southwest Research Institute Final Report to the American Biofuels Association, 

December 1993 

Clark N. N. et al., "Class 8 Truck Emission Testing: Effects of Test Cycles and Data on 

Biodiesel Operation," ASAE, 1999, 42(5), 1211-1219 

Clark, N.N., C.M. Atkinson, G.J. Thompson, R.D. Nine, "Transient Emissions Comparisons of 

Alternative Compression Ignition Fuels," SAE paper no. 1999-01-1117 

Durbin T. D. et al., "Effects of Biodiesel, Biodiesel Blends, and a Synthetic Diesel on 

Emissions from Light Heavy-Duty Diesel Vehicles," Environ. Sci. Technol., 2000, 34, 349-355 

Durbin, T.D., et al., "Evaluation of the Effects of Biodiesel and Biodiesel Blends on Exhaust 

Emission Rates and Reactivity - 2", Center for Environmental Research and 

Technology; College of Engineering; University of California, Riverside, August 2001 

Durbin, T.D., J.M. Norbeck, “Effects of Biodiesel Blends and Arco EC-Diesel on Emissions 

from Light Heavy-Duty Diesel Vehicles,” Environ. Sci. Technol., 2002, 36, 1686-1691 

Durbin, T.D., J.R. Collins, J.M. Norbeck, M.R. Smith, "Evaluation of the Effects of Alternative 

Diesel Fuel Formulations on Exhaust Emissions Rates and Reactivity," Final Report from the 

Center for Environmental Research and Technology, University of California, April 1999 

Environment Canada, "Emissions Characterization of a Caterpillar 3126E Equipped with a 

Prototype SCRT System with Ultra Low Sulfur Diesel and a Biodiesel Blend," ERMD Report 

#2005-32, 2005 

Fosseen, D., "DDC 6V-71N Emission Testing on Diesel and Biodiesel Blend," Fosseen 

Manufacturing and Development, Ltd., report no. NSDB4F15, July 14, 1994 

Fosseen, D., "DDC 6V-92TA MU1 Coach Upgrade Emission Optimization on 20%/80% 

Soy/Diesel Blend," Fosseen Manufacturing & Development, Ltd., report no. 260-2 and 24 1-1, 

September 30, 1994 

762
 
Frank B.P. et al., "A Study of the Effects of Fuel Type and Emission Control Systems on 

Regulated Gaseous Emissions from Heavy-Duty Diesel Engines," SAE paper no. 2004-01-1085 

Goetz, W., "Evaluation of a Tallow/Diesel Blend in a DDC 6V-92TA Engine," Ortech 

International report no. 93-E14-37, July 21, 1993 

Goetz, W., "Evaluation of Methyl Soyate/Diesel Blend in a DDC 6V-92TA Engine: 

Optimization of NOx Emissions," Ortech International, Report No. 93-E14-36, July 20, 1993 

Graboski, M.S., J.D. Ross, R.L. McCormick, "Transient Emissions from No. 2 Diesel and 

Biodiesel Blends in a DDC Series 60 Engine," SAE paper no. 961166 

Graboski, M.S., R.L. McCormick, T.L. Alleman, A.M. Herring, "The Effect of Biodiesel 

Composition on Engine Emissions from a DDC Series 60 Diesel Engine," Colorado School of 

Mines, Final Report to National Renewable Energy Laboratory, June 8, 2000 

Hansen, K.F., M.G. Jensen, "Chemical and Biological Characteristics of Exhaust Emissions from 

a DI Diesel Engine Fuelled with Rapeseed Oil Methyl Ester (RME)," SAE paper no. 971689 

Holden, Bruce et al., Final Report: "Effect of Biodiesel on Diesel Engine Nitrogen Oxide and 

Other Regulated Emissions," Naval Facilities Engineering Command (NAVFAC) Technical 

Report TR-2275-ENV, May 2006 

Howes, P., G. Rideout, "Evaluation of Biodiesel in an Urban Transit Bus Powered by a 1988 

DDECII6V92 TA Engine," National Biodiesel Board, MSED Report # 96-26743-1, June 1995 

Howes, P., G. Rideout, "Evaluation of Biodiesel in an Urban Transit Bus Powered by a 1981 

DDCC8V71 Engine," National Biodiesel Board, MSED Report # 95-26743-2 

Liotta, F.J., D.M. Montalvo, "The Effect of Oxygenated Fuels on Emissions from a Modern 

Heavy-Duty Diesel Engine," SAE paper no. 932734 

Lyons D. W., "Biodiesel Fuel Comparison Final Data Report for Washington Metropolitan Area 

Transit Authority," West Virginia University, August 2002 

Manicom, B., C. Green, W. Goetz, "Methyl Soyate Evaluation of Various Diesel Blends in a 

DDC 6V-92 TA Engine," Ortech International, April 21, 1993 

Marshall, W., L.G. Schumacher, S. Howell, "Engine Exhaust Emissions Evaluation of a 

Cummins L10E When Fueled With a Biodiesel Blend," University of Missouri 

McCormick R.L. et al., "Fuel Additive and Blending Approaches to Reducing NOx Emissions 

from Biodiesel," SAE paper no. 2002-01-1658 

McCormick R.L. et al., "Regulated Emissions from Biodiesel Tested in Heavy-Duty Engines 

Meeting 2004 Emission Standards," SAE paper no. 2005-01-2200 

763 
McCormick, R.L. et al., "Effects of Biodiesel Blends on Vehicle Emissions, FY 2006 Annual 

Operating Plan Milestone 10.4," October 2006 

McCormick, R.L., J.D. Ross, M.S. Graboski, "Effect of Several Oxygenates on Regulated 

Emissions from Heavy-Duty Diesel Engines," Environ. Sci. Technol., 1997, 31, 1144-1150 

McCormick, R.L., J.R. Alvarez, M.S. Graboski, "NOx Solutions for Biodiesel," Colorado School 

of Mines, August 31, 2001 

McDonald, J.F., D.L. Purcell, B.T. McClure, D.B. Kittelson, "Emissions Characteristics of Soy 

Methyl Ester Fuels in an IDI Compression Ignition Engine," SAE paper no. 950400 

McGill, R., Storey, J., Wagner, R., Irick, D., Aakko, P., Westerholm, M., Nylund, N., Lappi, M., 

“Emission Performance of Selected Biodiesel Fuels,” SAE paper no. 2003-01-1866 

National Institute for Petroleum and Energy Research, "Effects of Methyl Esters of Tallow and 

Grease on Exhaust Emissions and Performance of a Cummins L10 Engine," September 16, 1993 

National Resources Canada, "National Resources Canada/Fiba Canning - Biodiesel 

Freightliners," National Resources Canada draft report, October 24, 2006 

ORYXE Energy International, Inc., Biodiesel Emissions Test Summary, ORYXE presentation, 

2006 

Peterson C. L., et al., "The Effect of Biodiesel Feedstock on Regulated Emissions in Chassis 

Dynamometer Tests of a Pickup Truck," ASAE, 2000, 43 (6), 1371-1381 

Peterson, C., D. Reece, J. Thompson, S. Beck, C. Chase, "Development of Biodiesel for Use in 

High Speed Diesel Engines," University of Idaho, presentation at Sixth National Bioenergy 

Conference, Oct. 2-6, 1994 

Peterson, C.L., "Truck-In-The-Park Biodiesel Demonstration with Yellowstone National Park," 

University of Idaho, August 1999 

Peterson, C.L., D.L. Reece, "Emissions Testing with Blends of Esters of Rapeseed Oil Fuel With 

and Without a Catalytic Converter," SAE paper no. 961114 

Peterson, C.L., D.L. Reece, "Emissions Tests with an On-Road Vehicle Fueled with Methyl and 

Ethyl Esters of Rapeseed Oil," ASAE paper no. 946532 

Rantanen, L., S. Mikkonen, L. Nylund, P. Kociba, M. Lappi, N. Nylund, "Effect of Fuel on the 

Regulated, Unregulated and Mutagenic Emissions of DI Diesel Engines," SAE paper no. 932686 

Schumacher, L., N.N. Clark, D.W. Lyons, W. Marshall, “Diesel Engine Exhaust Emissions 

Evaluation of Biodiesel Blends Using a Cummins L10E Engine,” ASAE, 44(6), 1461-1464 

764
 
Schumacher, L., S.C. Borgelt, W.G. Hires, W. Wetherell, A. Nevils, "100,000 Miles of Fueling 

5.9L Cummins Engines with 100% biodiesel," SAE paper no. 962233 

Schumacher, L.G., S.C. Borgelt, W.G. Hires, D. Fosseen, W. Goetz, "Fueling Diesel Engines 

with Blends of Methyl Ester Soybean Oil and Diesel Fuel," University of Missouri. See 

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Southwest Research Institute, Final Report for Montana Department of Environmental Quality, 

November 1996 

Sharp, C.A., "Transient Emissions Testing of Biodiesel and Other Additives in a DDC Series 60 

Engine," Southwest Research Institute, Final Report to the National Biodiesel Board, December 

1994 

Sharp, C.A., "Transient Emissions Testing of Biodiesel in a DDC 6V-92TA DDEC Engine," 

Southwest Research Institute, Final Report to the National Biodiesel Board, October 1994 

Sharp, C.A., S.A. Howell, J. Jobe, "The Effect of Biodiesel Fuels on transient Emissions from 

Modern Diesel Engines, Part I Regulated Emissions and Performance," SAE paper no. 2000-01­

1967 

Sirman, M.B., E.C. Owens, K.A. Whitney, "Emissions Comparison of Alternative Fuels in an 

Advanced Automotive Diesel Engine," Southwest Research Institute, AD A353968/PAA, 

November 1998 

Smith, J.A., D.L. Endicott, R.R. Graze, "Biodiesel Engine Performance and Emissions Testing," 

Caterpillar Technical Center, May 1998 

Souligny M. et al., "Heavy-Duty Engine Performance and Comparative Emission Measurements 

for Different Biodiesel Blends Used in the Montreal Project," SAE paper no. 2004-01-1861 

Spataru, A., C. Romig, "Emissions and Engine Performance from Blends of Soya and Canola 

Methyl Ester with ARB #2 Diesel in a DDC 6V92TA MUI Engine," SAE paper no. 952388 

Starr, M.E., "Influence on Transient Emissions at Various Injection Timings, Using Cetane 

Improvers, Bio-Diesel, and Low Aromatic Fuels," SAE paper no. 972904 

Stotler, R.W., D.M. Human, "Transient Emission Evaluation of Biodiesel Fuel Blend in a 1987 

Cummins L10 and DDC 6V-92-TA," Engineering Test Services, report no. ETS-95-128, Nov. 

30, 1995 

Ullman, T.L., C.T. Hare, T.M. Baines, "Heavy-Duty Diesel Emissions as a Function of Alternate 

Fuels," SAE paper no. 830377 

765 
Wang, W.G., D.W. Lyons, N.N. Clark, M. Gautam, "Emissions from Nine Heavy Trucks Fueled 

by Diesel and Biodiesel Blend without Engine Modification," Environ. Sci. Technol., 2000, 34, 

933-939 

Studies not included because data collected on single cylinder/experimental engine 

Murayama, T., Y. Oh, A. Kido, T. Chikahisa, N. Miyamoto, K. Itow, "Effects of Super Heating 

of Heavy Fuels on Combustion and Performance in DI Diesel Engines," SAE paper no. 860306 

Murayama, T., Y. Oh, N. Miyamoto, T. Chikahisa, N. Takagi, K. Itow, "Low Carbon Flower 

Buildup, Low Smoke, and Efficient Diesel Operation with Vegetable Oils by Conversion to 

Mono-Esters and Blending with Diesel Oil or Alcohols," SAE paper no. 841161 

Shaheed, A., E. Swain, "Performance and Exhaust Emission Evaluation of a Small Diesel Engine 

Fuelled with Coconut Oil Methyl Esters," SAE paper no. 981156 

Suda, K.J., "Vegetable Oil or Diesel Fuel - A Flexible Option," SAE paper no. 840004 

Ziejewski, M., H.J. Goettler, "Comparative Analysis of the Exhaust Emissions for Vegetable Oil 

Based Alternative Fuels," SAE paper no. 920195 

Studies not included because data not readily available 

Alfuso. S., M. Auriemma, G. Police, M.V. Prati, "The Effect of Methyl-Ester of Rapeseed Oil on 

Combustion and Emissions of DI Diesel Engines," SAE paper no. 932801 

Hemmerlain, N., V. Korte, H. Richter, G. Schröder, "Performance, Exhaust Emissions and 

Durability of Modern Diesel Engines Running on Rapeseed Oil," SAE paper no. 910848 

Humke, A.L., N.J. Barsic, "Performance and Emissions Characteristics of a Naturally Aspirated 

Diesel Engine with Vegetable Oil Fuels - (Part 2)," SAE paper no. 810955 

Knothe, G., C.A. Sharp, T.W Ryan, “Exhaust Emissions of Biodiesel, Petrodiesel, Neat Methly 

Esters, and Alkanes in a New Technology Engine,” Energy and Fuels, 2006, 20, 403-408 

Lapuerta, M., Armas, O., Ballesteros, R., Fernandez, J., "Diesel Emissions from Biofuels 

Derived from Spanish Potential Vegetable Oils," Fuel, 2005, 84(6), 773-780 

Last, R.J., M. Krüger, M. Dürnholz, "Emissions and Performance Characteristics of a 4-Stroke, 

Direct Injected Diesel Engine Fueled with Blend of Biodiesel and Low Sulfur Diesel Fuel," SAE 

paper no. 950054 

Ma, W., L.I. Leviticus, F.G. Ullman, "On-Line Measurement of Formaldehyde in Tailpipe 

Emissions by Tunable Diode Laser Spectroscopy," SAE paper no. 941702 

766
 
Martin, B., P. Aakko, D. Beckman, N. D. Giacomo, F. Giavazzi, "Influence of Future Fuel 

Formulations on Diesel Engine Emissions - A Joint European Study," SAE paper no. 972966 

McDonald, J.F., "Evaluation of a Yellow Grease Methyl Ester and Petroleum Diesel Fuel 

Blend," University of Minnesota Final Report to the Agricultural Utilization Research Institute, 

August 11, 1997 

Montagne, X., "Introduction of Rapeseed Methyl Ester in Diesel Fuel - The French National 

Program," SAE paper no. 962065 

Reece, D.L., C.L. Peterson, "Biodiesel Testing in Two On-Road Pickups," SAE paper no. 

952757 

Staat, F., P. Gateau, "The Effects of Rapeseed Oil Methyl Ester on Diesel Engine Performance, 

Exhaust Emissions and Long-Term Behavior - A Summary of Three Years of Experimentation," 

SAE paper no. 950053 

Studies not included because test cycle nonstandard/unrepresentative 

Adelman, A.J., "Emission Evaluation Test Report for a Comparative Analysis of Emissions 

Among Petroleum Diesel and Biodiesel Blends fired in a Large Diesel Engine," AirNova, Inc., 

January 1998 

Akasaka, Y., T. Suzuki, Y. Sakurai, "Exhaust Emissions of a DI Diesel Engine Fueled with 

Blends of Biodiesel and Low Sulfur Diesel Fuel," SAE paper no. 972998 

Bagley, S.T., L.D. Gratz, J.H. Johnson, J.F. McDonald, "Effects of an Oxidation Catalytic 

Converter and a Biodiesel Fuel on the Chemical, Biological, and Particulate Size Characteristics 

of Emissions from an IDI Diesel Engine," Michigan Technological University, December 1995 

Chang, D.Y., J.H. Van Gerpen, "Determination of Particulate and Unburned Hydrocarbon 

Emissions from Diesel Engines Fueled with Biodiesel," SAE paper no. 982527 

Chang, D.Y.Z., J.H. Van Gerpen, "Fuel Properties and Engine Performance for Biodiesel 

Prepared from Modified Feedstocks," SAE paper no. 971684 

Choi, C.Y., G.R. Bower, R.D. Reitz, "Effects of Biodiesel Blended Fuels and Multiple Injections 

on D.I. Diesel Engines," SAE paper no. 970218 

Czerwinski, J., "Performance of HD-DI-Diesel Engine with Addition of Ethanol and Rapeseed 

Oil," SAE paper no. 940545 

Desantes, J.M., J. Arrègle, S. Ruiz, A. Delage, "Characterization of the Injection-Combustion 

Process in a D.I. Diesel Engine Running with Rape Oil Methyl Ester," SAE paper no. 1999-01­

767 

1497 
Fort, E.F., P.N. Blumberg, H.E. Staph, J.J. Staudt, "Evaluation of Cottonseed Oil as Diesel Fuel," 

SAE paper no. 820317 

Jacobus, M.J., S.M. Geyer, S.S. Lestz, W.D. Taylor, T.H. Risby, "Single-Cylinder Diesel Engine 

Study of Four Vegetable Oils," SAE paper no. 831743 

Masjuki, H., M.Z. Abdulmuin, H.S. Sii, "Investigations on Pre-Heated Palm Oil Methyl Esters in 

the Diesel Engine," IMechE 1996, Part A: Journal of Power and Energy 

Needham, J.R., D.M. Doyle, "The Combustion and Ignition Quality of Alternative Fuels in Light 

Duty Diesels," SAE paper no. 852101 

Schmidt, K., J. Van Gerpen, "The Effect of Biodiesel Fuel Composition on Diesel Combustion 

and Emissions," SAE paper no. 961086 

Scholl, K.W., S.C. Sorenson, "Combustion of Soybean Oil Methyl Ester in a Direct Injection 

Diesel Engine," SAE paper no. 930934 

Schramm, J., I. Foldager, N. Olsen, L. Gratz, "Emissions from a Diesel Vehicle Operated on 

Alternative Fuels in Copenhagen," SAE paper no. 1999-01-3603 

Schröder, O., J. Krahl, A. Munack, J. Krahl, J. Bünger, "Environmental and Health Effects 

Caused By the Use of Biodiesel," SAE paper no. 1999-01-3561 

Senatore, A., M. Cardone, V. Rocco, M.V. Prati, "A Comparative Analysis of Combustion 

Process in D.I. Diesel Engine Fueled with Biodiesel and Diesel Fuel," SAE paper no. 2000-01­

0691 

Uchida, M., Y. Akasaka, "A Comparison of Emissions from Clean Diesel Fuels," SAE paper no. 

1999-01-1121 

Zhang, Y., J.H. Van Gerpen, "Combustion Analysis of Esters of Soybean Oil in a Diesel 

Engine," SAE paper no. 960765 

Studies not included because they lack new emissions data for regulated pollutants 

Culshaw, F.A., "The Potential of 'Biodiesel' from Oilseed Rape," IMechE 1993, Part A: Journal 

of Power and Energy 

Durbin, T.D., J.R. Collins, H. Galdamez, J.M. Norbeck, M.R. Smith, R.D. Wilson, T. 

Younglove, "Evaluation of the Effects of Biodiesel Fuel on Emissions from Heavy-Duty NonRoad Engines," University of California Final Report submitted to South Coast Air Quality 

Management District, May 2000 

Peterson, C.L., D.L. Auld, "Technical Overview of Vegetable Oil as a Transportation Fuel," 

University of Idaho, 1991 

768
 
 

 

Sharp, C.A., S.A. Howell, J. Jobe, "The Effect of Biodiesel Fuels on Transient Emissions from 

Modern Diesel Engines, Part II Unregulated Emissions and Chemical Characterization," SAE 

paper no. 2000-01-1968 

Exclusion of duplicate datasets 

Colorado Institute for Fuels and High Altitude Engine Research, "Emissions from Biodiesel 

Blends and Neat Biodiesel from a 1991 Model Series 60 Engine Operating at High Altitude," 

Final Report to National Renewable Energy Laboratory, September 1994 

Note: CO2 values were not duplicative. 

McCormick, R.L., M.S. Graboski, T.L. Alleman, A.M. Herring, "Impact of Biodiesel Source 

Material and Chemical Structure on Emissions of Criteria Pollutants from a Heavy-Duty 

Engine," Environ. Sci. Technol., 2001, 35, 1742-1747 

Peterson, C.L., D.L. Reece, "Emissions Testing with Blends of Esters of Rapeseed Oil Fuel With 

and Without a Catalytic Converter," SAE paper no. 961114 

Note: Only Table 6 data is duplicative. 

Taberski, J.S., C.L. Peterson, "Dynamometer Emissions test Comparisons on a 5.9L Direct 

Injected Diesel Powered Pickup," BioEnergy '98: Expanding BioEnergy Partnerships 

Taberski, J.S., C.L. Peterson, J. Thompson, H. Haines, "Using Biodiesel in Yellowstone National 

Park - Final Report of the Truck in the Park Project," SAE paper no. 1999-01-2798 

Studies not included for other reasons 

Durbin T. D. et al., "Evaluation of the Effects of Biodiesel Fuel on Emissions from Heavy-Duty 

Non-Road Vehicles", Final Report for the SCAQMD under contract No. 99132 by the University 

of California, Riverside, May 2000 

Reason: Non-road vehicles not considered here. 

Frank B.P. et al., "A Study of the Effects of Fuel Type and Emission Control Systems on 

Regulated Gaseous Emissions from Heavy-Duty Diesel Engines," SAE paper no. 2004-01-1085 

Reason: Effect of oxycat & CRDPF greater than effect of B20. 

Guerra S. A. et al., "Comparison Study of NOx and CO2 Emissions from an Off-Road Diesel 

Compactor Running on Regular Diesel, Biodiesel and Ultra-Low Sulfur Diesel," University of 

Kansas draft report, March 17, 2006 

Reason: Non-road equipment not considered here. 

769 
Watts, W.F., M. Spears, J Johnson, "Evaluation of Biodiesel Fuel and Oxidation Catalyst in an 

Underground Metal Mine," University of Minnesota, September 24, 1998 

Reason: Emission measurements were made in the field with portable emission 

 measurement devices 

Yoshimoto, Y., M. Onodera, H. Tamaki, "Reduction of NOx, Smoke, and BSFC in a Diesel 

Engine Fueled by Biodiesel Emulsion with Used Frying Oil," SAE paper no. 1999-01-3598 

Reason: Biodiesel blend included water in an emulsion 

770
 
 

Endnotes 

1

 See the following documents: Iowa State University Center for Agricultural Research and 

Development, “Emerging Biofuels: Outlook of Effects on U.S. Grain, Oilseed, and Livestock 

Markets,” May 2007 (a revised version is available from July 2007); USDA Agricultural 

Projections to 2016, Report OCE-2007-1, February 2007 (a newer version was released in Feb 

2008 with Projections to 2017); NCGA, “How Much Ethanol Can Come From Corn?” 2006; 

USDA, “An Analysis of the Effects of an Expansion in Biofuel Demand on U.S. Agriculture,” 

May 2007.

2

 Western Governors’ Association. “Transportation Fuels for the Future, Biofuels: Part I,” 

January 8, 2008.

3

 U.S. Government Accountability Office. “DOE Lacks a Strategic Approach to Coordinate 

Increasing Production with Infrastructure Development and Vehicle Needs,” June 2007. 

4

 USDA/NASS. “Corn: Yield by year, US,” 

http://www.nass.usda.gov/Charts_and_Maps/Field_Crops/cornyld.asp, August 12, 2008. 

5

 USDA Agricultural Projections to 2016, Report OCE-2007-1, February 2007, page 39. 

6

 USDA, National Agricultural Statistics Service, Crop Production and Grain Stocks; USDA, 

World Agricultural Outlook Board, World Supply and Demand Estimates; and U.S. Department 

of Commerce, Bureau of the Census.

7

 USDA Agricultural Projections to 2016, Report OCE-2007-1, February 2007, page 22. 

8

 Shapouri, H., Gallagher, P., “USDA’s 2002 Ethanol Cost-of-Production Survey,” July 2005, 

p.11.

9

 USDA, “The Economic Feasibility of Ethanol Production from Sugar in the United States,” 

July 2006.

10 Personal communication with Nathalie Hoffman, Managing Member of California Renewable 

Energies, LLC, August 27, 2008. 

11 Christiansen, Ryan, “Analysis: Sugarcane Ethanol Has 95% Less Emissions,” Ethanol 

Producer Magazine, March 2009. 

12 Voegele, Erin, “Sugarcane Economics,” Ethanol Producer Magazine, March 2009. 

13 F.O. Licht, “World Ethanol Markets: The Outlook to 2015,” 2006, page 45. 

14 “Sugarcane Industry in Brazil: Ethanol, Sugar, Bioelectricity” brochure from UNICA 

15 FAO Statistics, “Sugarcane selected as Commodity,” 

http://www.fao.org/es/ess/top/commodity.html?lang=en&item=156&year=2005, August 12, 

2008. 

16 Agra FNP. “Sugar and Ethanol in Brazil: A Study of the Brazilian Sugar Cane, Sugar and 

Ethanol Industries,” 2007.

17 “Sugarcane Industry in Brazil: Ethanol, Sugar, Bioelectricity” brochure from UNICA 

18 Scaramucci, Jose & Cunha, Marcelo, “Bioethanol as Basis for Regional Development in 

Brazil: An Input-Output Model with Mixed Technologies.” 

19 CGEE, ABDI, Unicamp, and NIPE, “Scaling Up the Ethanol Program in Brazil,” n.d. cited in 

Rothkopf, Garten, “A Blueprint for Green Energy in America,” 2006. 

20 USDA, “The Economic Feasibility of Ethanol Production from Sugar in the United States,” 

July 2006.

21 Kline, K. et. al., “Biofuel Feedstock Assessment for Selected Countries,” Oak Ridge National 

Laboratory, February 2008. 

771 
 

 

 

22 Elbehri, Aziz. USDA, ERS, “An Evaluation of the Economics of Biomass Feedstocks: A 

Synthesis of the Literature,” Prepared for the Biomass Research and Development Board, 2007.

23 Milbrandt, A., “Geographic Perspective on the Current Biomass Resource Availability in the 

United States,” NREL Report No. TP-560-39181, 2005.

24 Gallagher, P. et. al., “Supply and Social Cost Estimates for Biomass from Crop Residues in the 

United States,” Environmental and Resource Economics 24: 335-358, 2003. 25 Walsh, Marie, “U.S. Cellulosic Biomass Feedstock Supplies and Distribution,” Unpublished 

Manuscript, January 10, 2008.

26 Graham, R.L. et. al., “Current and Potential U.S. Corn Stover Supplies,” American Society of 

Agronomy 99:1-11, 2007.

27 W. W. Wilhelm, USDA-ARS, Univ. of Nebraska, Lincoln, NE 68583-0934, J. M. F. Johnson, 

USDA-ARS, Morris, MN 56267-1065, J. L. Hatfield, 108 Natl. Soil Tilth Lab., Ames, IA 50011­

3120, W. B. Voorhees, USDA-ARS (retired), Morris, MN 56267-1065, and D. R. Linden, 

USDA-ARS (retired), St. Paul, MN 55108-0000, Crop and Soil Productivity Response to Corn 

Residue Removal A Literature Review; FORUM, © American Society of Agronomy, Madison, 

WI 53711 USA, Published in Agron. J. 96:1-17 (2004) 

28 Predicting Soil Erosion by Water. A Guide to Conservation Planning with the Revised 

Universal Soil Loss Equation (RUSLE). United States Department of Agriculture, Agricultural 

Research Service, Agricultural Handbook Number 703, 1997. 

29 Richard G. Nelson, Enersol Resources, Manhattan, KS 66502, USA, Resource Assessment 

and Removal Analysis for Corn Stover and Wheat Straw in the Eastern and Midwestern United 

States—Rainfall and Wind-induced Soil Erosion Methodology, Biomass and Bioenergy 22 

(2002) 349 – 363, Published by Elsevier Science Ltd 

30 Linda Mann, Virginia Tolbert, Janet Cushman, Environmental Sciences Division, Oak Ridge 

National Laboratory, Oak Ridge, TN 37831-6038, Potential Environmental Effects of Corn 

Stover Removal With Emphasis on Soil Organic Matter and Erosion, Agriculture, Ecosystems 

and Environment 89: 149-166, ISSN 0167-8809 Elsevier Science, Amsterdam. June 2002. 

31 http://www.nrcs.usda.gov/technical/Standards/nhcp.html 

32 Richard G. Nelson, Enersol Resources, Manhattan, KS 66502, USA, Resource Assessment 

and Removal Analysis for Corn Stover and Wheat Straw in the Eastern and Midwestern United 

States—Rainfall and Wind-induced Soil Erosion Methodology, Biomass and Bioenergy 22 

(2002) 349 – 363, Published by Elsevier Science Ltd. 

33 W.W. Wilhelm, USDA-ARS; J.M.F. Johnson, USDA-ARS; D.L. Karlen, USDA-ARS; D.T. 

Lightle, National Soil Survey; Corn Stover to Sustain Soil Organic Carbon Further Constrains 

Biomass Supply, Published in Agron. J. 99:1665–1667 (2007); American Society of Agronomy, 

Madison, WI 53711. 

34 Susan S. Andrews, Ph.D., Leader, Soil Quality National Technology Development Team 

USDA-Natural Resource Conservation Service Crop, White Paper: Residue Removal for 

Biomass Energy Production: Effects on Soils and Recommendations, Updated February 22, 2006

35 Graham, R.L. et. al., “Current and Potential U.S. Corn Stover Supplies,” American Society of 

Agronomy 99:1-11, 2007.

36 Perlack, Robert D.; Biomass as Feedstocks for a Bioenergy and Bioproducts Industry: The 

Technical Feasibility of a Billion Ton Annual Supply; Sponsored by the U.S. Department of 

Energy and the U.S. Department of Agriculture; April 2005.

37 Ibid. 

772
 
 

38 Walsh, M.E. (2007) Sungrant Bioweb. Forest Resources. 

http://bioweb.sungrant.org/Technical/Biomass+Resources/Forest+Resources/Default.htm

39 Ibid. 

40 QUANTIFYING THE FLOW: TAKING INVENTORYOF WOODY RESIDUALS, David 

McKeever, Research Forester, USDA Forest Service's Forest Products Laboratory, Madison, 

Wisconsin. Published in Biocycle, July 2003, pp. 31-35. 

41 Perlack, R.D., Wright, L.L., Turhollow, A.F, Graham, R.L., Environmental Sciences Division, 

Oak Ridge National Laboratory; Stokes, B.J., Forest Service, USDA.; Erbach, D.C., Agricultural 

Research Service, USDA, “Biomass as Feedstock for a Bioenergy & Bioproducts Industry: The 

Technical Feasibility of a Billion-Ton Annual Supply (A Joint Study Sponsored by DOE and 

USDA, Prepared by Oak Ridge National Laboratory),” 2005. 

42 Ibid. 

43 Kerstetter, J. and Lyons, J., (2001) Logging and Agricultural Residue Supply Curves for the 

Pacific Northwest. Washington State University Energy Program for U.S. DOE. 

44 Rummer, B.; Len, D.; and O’Brien, O. (2004). Forest Residues Bundling Project-New 

Technology for Residue Removal. USDA Forest Service, Southern Research Station 

45 Ibid. 

46 Rawlings, C., et. al. (2004). A Study of How to Decrease the Costs of Collecting, Processing 

and Transporting Slash. USDA Forest Service. 

47 Dickerson, K., et. al. (revised November 2007). Biomass and Biofuels in Maine: Estimating 

Supplies for Expanding the Forest Products Industry. Margaret Chase Smith Policy Center.

48 Puttock, G.D. (1995). Estimating cost for integrated harvesting and related forest management 

activities. Biomass and Bioenergy 8(2), 73-79.

49 Perlack, R.D., Wright, L.L., Turhollow, A.F, Graham, R.L., Environmental Sciences Division, 

Oak Ridge National Laboratory; Stokes, B.J., Forest Service, USDA.; Erbach, D.C., Agricultural 

Research Service, USDA, “Biomass as Feedstock for a Bioenergy & Bioproducts Industry: The 

Technical Feasibility of a Billion-Ton Annual Supply (A Joint Study Sponsored by DOE and 

USDA, Prepared by Oak Ridge National Laboratory),” 2005. 

50 Dickerson, K., et. al. (revised November 2007). Biomass and Biofuels in Maine: Estimating 

Supplies for Expanding the Forest Products Industry. Margaret Chase Smith Policy Center.

51 Ibid. 

52 Timko, B., 2003. USDA, Forest Service, personal communication as noted in the “Billion-ton 

Study” by Perlack, R.D., et. al.

53 F. Bohlin and A. Roos, Wood fuel supply as a function of forest owner preferences and 

management styles, Biomass & Bioenergy 22 (2002), pp. 237–249.

54 Jonsell, M. 2007. Effects on Biodiversity of Forest Fuel Extraction, Governed by Processes 

Working on a Large Scale. Biomass and Bioenergy, Issue 31 pg. 726-732. 

55 Kozlowski, T.T., 1999. Soil Compaction and Growth of Woody Plants. Scandinavian Journal 

of Forest Research, Volume 14, Number 6. Taylor and Francis Ltd. 

56 Rummer, B.; Len, D.; and O’Brien, O. (2004). Forest Residues Bundling Project-New 

Technology for Residue Removal. USDA Forest Service, Southern Research Station 

57 Energy content of hardwood; www.eere.energy.gov/biomass/progs/search3.cgi?8828; 

Biomass Feedstock Composition and Property Database; Energy Efficiency and Renewable 

Energy, U.S. Department of Energy. 

773 
 

 

58 Perlack, Robert D.; Biomass as Feedstocks for a Bioenergy and Bioproducts Industry: The 

Technical Feasibility of a Billion Ton Annual Supply; Sponsored by the U.S. Department of 

Energy and the U.S. Department of Agriculture; April 2005. 

59 Walsh, Marie E., U.S. Cellulosic Biomass Feedstock Supplies and Distribution; January 10, 

2008. 

60 Data provided by e-mail by Perlack, Robert D., May 2008. 

61 EPA. “Municipal Solid Waste Generation, Recycling, and Disposal in the United States: Facts 

and Figures for 2006,” November 2007. 

62 USEPA. “Methodology for Estimating Municipal Solid Waste Recycling Benefits,” November 

2007; See 2006 MSW Characterization Tables. 

63 Biocycle, “The State of Garbage in America,” Vol. 47, No. 4, 2006, page 26. 

64 Midwest Assistance Program, Inc. “The 2006-2007 Missouri Municipal Solid Waste 

Composition Study,” October, 2007. 

65 R. W. Beck, “Georgia Statewide Characterization Study,” June 2005. 

66 Engineering Solutions and Design, Inc., “State of Ohio Waste Characterization Study,” April 

2004. 

67 NYC Department of Sanitation, “2004-2005 NYC Waste Characterization Study.” 

68 R.W. Beck, “Statewide MSW Composition Study: A Study of Discards in the State of 

Minnesota,” 2000.

69 R.W. Beck, “Statewide Waste Composition Study: Pennsylvania State-wide Waste 

Composition,” April 2003. 

70 DSM Environmental Services, Inc, “Vermont Waste Composition Study,” June 2002. 

71 R.W. Beck, “1992 Washington State Waste Characterization Study.” 

72 R.W. Beck, “Wisconsin Statewide Waste Characterization Study,” May 2003. 

73 Department of Environmental Quality, “Oregon 2002 Waste Composition Study,” 2002. 

74 Williams, Robert and California Biomass Collaborative, “Biofuels from Municipal WastesBackground Discussion Paper,” March 28, 2007.

75 Ibid. 

76 Walsh, Marie, “U.S. Cellulosic Biomass Feedstock Supplies and Distribution,” Unpublished 

Manuscript, January 10, 2008.

77 NEOS Corporation. (1994). Urban tree residues: Results of the first national inventory. (Final 

Report). International Society of Arboriculture Research Trust. Allegheny Power Service 

Corporation and National Arborist Foundation. As cited in Walsh, Marie. (2008) U.S. Cellulosic 

Biomass Feedstock Supplies and Distribution. Unpublished Manuscript. 

78 USEPA, Construction and Demolition (C&D) Materials. 

http://www.epa.gov/osw/nonhaz/industrial/cd/basic.htm Accessed August 10, 2008. 

79 Fehrs, J., “Secondary Mill Residues and Urban Wood Waste Quantities in the United StatesFinal Report,” Northeast Regional Biomass Program Washington, D.C., December 1999. 

80 Wiltsee, G., “Urban Wood Waste Resource Assessment,” Appel Consultant, Inc. Valencia, 

CA. November, 1998. 

81 U.S Department of Energy. “Breaking the Biological Barriers to Cellulosic Ethanol: A Joint 

Research Agenda.” (2006). 

82 Kumar, A., & Sokhansanj, S., “Switchgrass (Panicum vigratum, L.) delivery to a biorefinergy 

using integrated biomass supply analysis and logistics (IBSAL) model.” Bioresource 

Technology, (2006). 

774
 
 

 

 

 

 

 

83 McLaughlin, S.B. & Adams Kszos, L., “Development of switchgrass (Panicum virgatum) as a 

bioenergy feedstock in the United States,” Biomass and Bioenergy, 28: 515-535, 2005.

84 Kumar, op. cit.

85 McLaughlin, op. cit.

86 Lewandowski, I., Clifton-Brown, J.C., Scurlock, J.M.O., & Huisman, W., “Miscanthus: 

European experience with a novel energy crop,” Biomass and Bioenergy, 19: 209-227, 2000.

87 Pyter, R., Voigt, T., Heaton, H., Dohleman, F., & Long, S. Growing giant miscanthus in 

Illinois. University of Illinois. (2006).

88 Ibid.
 89 Ibid.
 90 Lewandowski, op. cit.

91 Pyter, op. cit.

92 Pyter, op. cit.

93 Lewandowski, op. cit.

94 Pyter, op. cit.

95 U.S Department of Energy. “Breaking the Biological Barriers to Cellulosic Ethanol: A Joint 

Research Agenda,” 2006. 

96 Ibid. 

97 Ibid. 

98 Campbell, J.E. at al., ”The Global Potential of Bioenergy on aAbandoned Agriculture Lands,” 

Environ. Sci. Technology, 2008.

99 Ibid.
 100 Adapted from additional information received from J. Elliot Campbell. “The Global Potential 

of Bioenergy on Abandoned Agriculture Lands,” Environ. Sci. Technology, 2008.

101 USDA, Farm Services Agency, “Conservation Reserve Program Summary and Enrollment 

Statistics,” FY 2007. 

102 USDA, Farm Services Agency, “Conservation Reserve Program Statistics: Monthly Summary 

July 2008.”

103 Pyter, op. cit. 104 Based on plant capacities reported by the National Biodiesel Board, and data reported by F.O. 

Licht. 

105 Mueller, Steffen. An analysis of the projected energy use of future dry mill corn ethanol 

plants (2010-2030). October 10, 2007. Available at 

http://www.chpcentermw.org/pdfs/2007CornEethanolEnergySys.pdf 

106 “Essential Rendering”, published by the National Renderer’s Association, edited by David 

Meeker. 2006. Available at http://nationalrenderers.org/assets/essential_rendering_book.pdf 

107 “Statewide Feasibility Study for a Potential New York State Biodiesel Industry”, prepared by 

LECG, LLC. Report number 04-02, April 2004. Available at 

http://www.nyserda.org/publications/biodieselreport.pdf 

108 A copy of this letter is available in the docket. 

109 Jongschaap, R.E.E, W.J. Corre, P.S Bindraban, and W.A. Brandenburg, “Claims and Facts on 

Jatropha curcas L,” Plant Research International, Vers. Report 158, Oct. 2007. 

110 Euler, Hartlieb, and David Gorriz, “Case Study "Jatropha Curcas"” Rep. No. Global 

Facilitation Unit for Underutilized Species, Frankfurt, 2004. 

775 
 

 

 

111 Kumar, Sujeet., "Jatropha harmful for kids, soil and aquatic life: scientist," India eNews, May 

2008. 

112 Jongschaap, op. sit. 

113 Ibid. 

114 Fairless, Daemon. "The little shrub that could - maybe." Nature 449 (2007): 652-55. 

115 Francis, G., R. Edinger, and K. Becker. "A concept for simultaneous wasteland reclamation, 

fuel production, and socio-economic development in degraded areas in India: need, potential and 

perspectives of Jatropha plantations." Natural Resources Forum 29 (2005): 12-24. As sited in 

Jongschaap, R.E.E, W.J. Corre, P.S Bindraban, and W.A. Brandenburg, “Claims and Facts on 

Jatropha curcas L,” Plant Research International, Vers. Report 158, Oct. 2007. 

116 Woltjer, Lyanne. Size does matter. Expertise Centrum voor Duurzame Ontwikkeling 

(ECDO). Dec. 2006. 

117 Jongschaap, op. sit.

118 Li Guo, T. "The photosynthesis and water use efficiency of eight garden tree species." Forest 

Research 15 (2002): 291-96. As sited in Jongschaap, R.E.E, W.J. Corre, P.S Bindraban, and 

W.A. Brandenburg, “Claims and Facts on Jatropha curcas L,” Plant Research International, 

Vers. Report 158, Oct. 2007. 

119 Jongschaap, op. sit.

120 Fairless, op. sit.

121 Jongschaap, op. sit. 

122 Ghosh, A., J.S. Patolia, D.R. Chaudharry, J. Chikara, S.N. Rao D. Kumar, G.N. Boricha, and 

A. Zala. Response of Jatropha curcas under different spacing to Jatropha de-oiled cake. 

Discipline of Phytosalinity, Central Salt and Marine Chemicals Research Institute. 2007. 

123 Jongschaap, op. sit. 

124 Ibid. 

125 Chaudharry, D.R., J.S. Patolia, A. Ghosh, J. Chikara, G.N. Boricha, and A. Zala. Changes in 

soil characteristics and foliage nutrient content in Jatropha curcas plantations in relation to stand 

density in Indian wasteland. Expert seminar on Jatropha curcas L. Agronomy and Genetics. Mar. 

2007. As sited in Jongschaap, R.E.E, W.J. Corre, P.S Bindraban, and W.A. Brandenburg, 

“Claims and Facts on Jatropha curcas L,” Plant Research International, Vers. Report 158, Oct. 

2007. 

126 Jongschaap, op. sit. 

127 Ibid. 

128 Francis, op. sit. 

129 Jongschaap, op. sit.

130 Ibid.
 131 Kumar, op. sit.

132 Jongschaap, op. sit.

133 Sharma, N., and A. Sarraf. Plantation management: activities/labour costs. Expert seminar on 

Jatropha curcas L. Agronomy and Genetics. Mar. 2007. As sited in Jongschaap, R.E.E, W.J. 

776
 
 

 

 

Corre, P.S Bindraban, and W.A. Brandenburg, “Claims and Facts on Jatropha curcas L,” Plant 

Research International, Vers. Report 158, Oct. 2007. 

134 Jongschaap, op. sit.

135 Fairless, op. sit.

136 Francis, op. sit. 

137 Jongschaap, op. sit.

138 Euler, op. sit.
 

139 Woltjer, Lyanne, “Size does matter,” Expertise Centrum voor Duurzame Ontwikkeling 

(ECDO), December 2006. 

140 Jongschaap, op. sit.

141 Euler, op sit.
 

142 Jongschaap, op. sit.

143 Francis, op. sit.
 

144 Ibid. 

145 Pant, K.S., V. Khosla, D. Kumar, and S. Gairola, "Seed oil content variation in Jatropha 

curcas Linn. in different altitudinal ranges and site conditions in H.P. India," Lyonia 11 (2006): 

31-34. 

146 Pant, op. sit. 

147 Jongschaap, op. sit.

148 Ibid.
 149 Woltjer, op. sit. 

150 Achten, W., E. Mathijs, L. Verchot, V.P. Singh, and B. Muys, “Bio-diesel from Jatropha: the 

life-cycle perspective,” Expert seminar on Jatropha curcas L. Agronomy and Genetics. March 

2007. As sited in Jongschaap, R.E.E, W.J. Corre, P.S Bindraban, and W.A. Brandenburg, 

“Claims and Facts on Jatropha curcas L,” Plant Research International, Vers. Report 158, Oct. 

2007. 

151 Muys, B., W. Achten, E. Mathijs, V.P. Singh, and L. Verchot, “Life cycle inventory of 

biodiesel production from Jatropha,” Expert seminar on Jatropha curcas L. Agronomy and 

Genetics. March 2007. As sited in Jongschaap, R.E.E, W.J. Corre, P.S Bindraban, and W.A. 

Brandenburg, “Claims and Facts on Jatropha curcas L,” Plant Research International, Vers. 

Report 158, Oct. 2007. 

152 Jongschaap, op. sit.

153 Fairless, op. sit. 

154.Francis, op. sit. 

155 USDA, "PLANTS Profile for Jatropha curcas L." USDA Natural Resources Conservation 

Service. http://plants.usda.gov/java/profile?symbol=jacu2, November 3, 2008. 

156 Jongschaap, op. sit. 

777 
 

157 Oregon Climate Service, “State Annual Precip Maps,” http://www.ocs.oregonstate.edu., 

November 3, 2008. 

158 Carney, Dan. "Second-generation biodiesel." Automotive Engineering, May 2008: 20-22. 

159 Francis, op. sit.

160 Euler, op. sit.

161 Sheehan, John, Terri Dunahay, John Benemann, and Paul Roessler, “A Look Back at the U.S. 

Department of Energy’s Aquatic Species Program—Biodiesel from Algae,” National Renewable 

Energy Laboratory. Office of Fuels Development. Golden, Colorado, 1998. 

162 Ibid. 

163 Wagner, Leonard, “Biodiesel from Algae Oil,” Mora Associates, July 2007. 

164 National Renewable Energy Laboratory, "Chevron and NREL to Collaborate on Research to 

Produce Transportation Fuels using Algae." Press release. Oct. 31 2007. 

165 Chisti, Yusuf, "Biodiesel from Microalgae." Biotechnology Advances 25, 294-306, 2007. 

166 Schenider, David, "Grow Your Own?" American Scientist, Sept.-Oct. 2006. 

167 Campbell, Matthew N., "Biodiesel: Algae as a Renewable Source for Liquid Fuel." Guelph 

Engineering Journal, 1, 2-7, 2008. 

168 Chisti, op. sit.

169 Pienkos, Philip T., "The Potential for Biofuels from Algae," Algae Biomass Summit. San 

Francisco, CA. Nov. 15, 2007. 

170 Campbell, op. sit. 

171 Pienkos, op. sit. 

172 Campbell, op. sit.
 

173 Sheehan, op. sit. 

174 Pienkos, op. sit. 

175 Campbell, op. sit. 

176 Putt, Ron. “Algae as a Biodiesel Feedstock,” Nov. 20, 2007. 

177 Sheehan, op. sit.

178 "Algae Bloom Again." Nature, 447, 520-21 2007. 

179 Deshayes, Pierre-Henry, "As planet swelters, are algae unlikely saviour?" AFP, July 10, 2008.

180 Sheehan, op. sit.

181 Bullock, Cary, "Algae Corrals Carbon Dioxide," EnergyBiz Magazine, 68-70, Mar.-Apr. 

2007. 

182 Chisti, op. sit.

183 Sheehan, op. sit. 

184 Chisti, op. sit. 

185 Schenider, op. sit.
 

186 Campbell, op. sit. 

778
 
 

 

187 Pienkos, op. sit. 

188 Putt, op. sit. 

189 Chisti, op. sit.

190 Campbell, op. sit. 

191 Chisti, op. sit.

192 Ibid. 

193 Campbell, op. sit. 

194 Pienkos, op. sit. 

195 Chisti, Yusuf. op. sit.

196 Wagner, op. sit. 

197 AlgaeLink, “Commercial Cultivation Plants,” http://www.algaelink.com, November 3, 2008. 

198 Sapphire Energy, “Algae-Based Fuel Projected to Become Commercial-Ready in Three 

Years” http://www.sapphireenergy.com/press_release/11, April 16, 2009.

199 Thurmond, Will, “Algae 2020: Biofuels Markets and Commericalization Outlook Webinar”, 

Emerging Markets Online, March 10, 2009. 

200 Ibid. 

201 "Low Cost Algae Production System Introduced." Energy-Arizona. http://www.energyarizona.org., Aug. 28, 2007.

202 Chisti, op. sit.

203 "Low Cost Algae Production System Introduced." Energy-Arizona. 28 Aug. 2007. 

<http://www.energy-arizona.org>. 

204 Chisti, op. sit.

205 Pienkos, op. sit. 

206 “PV Solar Radiation,” Digital image. National Renewable Energy Laboratory. May 2004. 

207 Bullock, op. sit. 

208 Chisti, op. sit.

209 Schenider, op. sit. 

210 Campbell, op. sit. 

211 Pienkos, op. sit. 

212 Wagner, op. sit.

213 Chisti, op. sit.

214 Pienkos, op. sit. 

215 F.O. Licht’s World Ethanol and Biofuels Report. Vol 6, No 11, p.203. Feb 15, 2008.

216 Ibid. 

217 DTN Ethanol Center, ”EU Biodiesel Feedstock Challenge,” October 11, 2007, 

http://www.dtnethanolcenter.com/index.cfm?show=10&mid=66&pid=27 

218 World Biofuels: FAPRI 2008 Agricultural Outlook. 

http://www.fapri.org/outlook2008/text/14Biofuels.pdf, November 3, 2008. 

219 Biofuels Barometer. Geographic Information System: EurObserv'ER 

http://www.eufores.org/index.php?id=29, November 3, 2008. 

779 
 

220 EUROPA Press Release, “Stricter fuel standards to combat climate change and reduce air 

pollution,” Jan. 31, 2007.

221 EU Press Release, “2782nd Council Meeting on Transport, Telecommunications, and Energy, 

February 15th, 2007, Brussels, Council of the European Union,” 

http://www.consilium.europa.eu/Newsroom. 

222 Ministry of Mines and Energy, “The Brazilian Experience with Biofuels,” Presentation by 

Ricardo de Gusmao Dornelles, June 1, 2007. 

223 EPE, “Plano National de Energia 2030.” Presentation from Mauricio Tolmasquim, 2007. 

224 Asian Palm Oil for Euro Biodiesel, 2005 as quoted in Ohga K. & Tatsuji K., “Biofuels 

Policies in Asia: Trade effects on World Agricultural and Biofuels Trade,” Presentation to 

USDA Agricultural Outlook Forum, March 2, 2007. 

225 Ohga K. & Tatsuji K., “Biofuels Policies in Asia: Trade effects on World Agricultural and 

Biofuels Trade,” Presentation to USDA Agricultural Outlook Forum, March 2, 2007. 

226 USDA FAS, “Gain Report. Indonesia Bio-Fuels Biofuels Annual 2007,” June 13, 2007. 

227 USDA FAS, “Palm oil continues to dominate global consumption in 2006/2007,” 

http://www.fas.usda.gov/oilseeds/circular/2006/06-06/Junecov.pdf 

228 Dato’ Dr. Mohd. Basri Wahid, “Malaysian Palm Oil Board. Presentation: Technological 

Progress and Commercialization of Biodiesel in Malaysia.” 

229 USDA FAS, “Gain Report. India Bio-fuels Annual 2007,” June 1, 2007. 

230 Fairless, op. sit.

231 Wright, M. and Brown, R. Comparative Economics of Biorefineries Based on the 

Biochemical and Thermochemical Platforms. Biofuels, Bioprod. Bioref. 1:49-56 (2007)

232 Kline, K. et. al. Biofuel Feedstock Assessment for Selected Countries. Oak Ridge National 

Laboratory. February 2008.

233 National Renewable Energy Laboratory estimate based on biomass portion available at $45­

$55/dry ton.. Using POLYSYS Policy Analysis System, Agricultural Policy Analysis Center, 

University of Tennessee. http://www.agpolicy.org/polysys.html. Accessed May 2008. 

234 Milbrandt, A. (2005). “Geographic Perspective on the Current Biomass Resource Availability 

in the United States.” 70 pp.; NREL Report No. TP-560-39181 

235 D. Montross, Associate Professor, Scott A. Shearer, Professor, Timothy S. Stombaugh, 

Associate Extension Professor, Stephen F. Higgins, Research Specialist, and Samuel G. McNeill, 

Associate Extension Professor, Department of Biosystems and Agricultural Engineering, 

University of Kentucky, Lexington, Kentucky; and Shahab Sokhansanj, Professor, Oak Ridge 

National Laboratory, Environmental Sciences Division, Oak Ridge, Tennessee, Corn Stover 

Availability and Collection Efficiency Using Typical Hay Equipment, This article is published 

with the approval of the Director of the Kentucky Agricultural Experiment Station and 

designated Paper No. 04-05-066. Transactions of the ASABE, Vol. 50(3): 705−711 – 2007 

American Society of Agricultural and Biological Engineers, ISSN 0001−2351. 

236 S. Sokhansanj1, A. Turhollow, and R. Perlack, Oak Ridge National Laboratory, Tennessee, 

USA 37830, Stochastic Modeling of Costs of Corn Stover Costs Delivered to an Intermediate 

Storage Facility, Paper Number: 024190, Presented at: 2002 ASAE Annual International 

Meeting / CIGR XVth World Congress, Sponsored by ASAE and CIGR, Hyatt Regency 

Chicago, Chicago, Illinois, USA, July 28-July 31, 2002 

237 Christopher T. Wright, Peter A. Pryfogle, Nathan A. Stevens, J. Richard Hess, Corey W. 

Radtke, Idaho National Laboratory, Idaho Falls, ID, USA, Value of Distributed Preprocessing of 

780
 
 

 

Biomass Feedstocks to a Bioenergy Industry, Paper No: 066151, 2006 ASABE Annual 

International Meeting, Oregon Convention Center, Portland, Oregon, 9 - 12 July 2006 

238 Kevin J. Shinners, Professor of Agricultural Engineering, Ben N. Binversie, Graduate 

Research Assistant, Department of Biological Systems Engineering, University of Wisconsin, 

Madison, WI, Philippe Savoie, Research Scientist, Agriculture and Agri-Food Canada, Quebec, 

Canada; Harvest and Storage Of Wet and Dry Corn Stover As A Biomass Feedstock, Paper 

Number: 036088, 2003 ASAE Annual International Meeting 

Riviera Hotel and Convention Center, Las Vegas, Nevada, USA, 27- 30 July 2003 

239 ICM website, Ethanol Production Process, 

http://www.icminc.com/ethanol/production_process (Supplemented with information provided 

by EPA’s Region 7).

240 Renewable Fuels Association website, How Ethanol is Made: The Ethanol Production 

Process –Wet Milling, http://www.ethanolrfa.org/resource/made. 

241 POET website, Technology - BPXTM, http://www.poetenergy.com/learn/bpx.asp. 

242 Kirkbride McElroy, Anduin , “Poet, ISU partner for BPX research,” Ethanol Producer 

Magazine, http://www.ethanol-producer.com/article.jsp?article_id=3770, March 2008. 

243 Renewable Fuels Association, Annual Energy Outlook 2006 

(http://www.ethanolrfa.org/objects/pdf/outlook/outlook_2006.pdf) 244 U.S. Environmental Protection Agency, Combined Heat & Power Partnership website, Basic 

Information, http://www.epa.gov/chp/basic/index.html.

245 Smeets, Edward, et. al. “Sustainability of Brazilian bio-ethanol”. August 2006 

246 Saeman, J.F., Kinetics of Wood Saccharification: Hydrolysis of Cellulose and Decomposition 

of Sugars in dilute Acid at High Temperature, Industrial and Engineering Chemistry, 37(1): 43–
 

52 (1945). 

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247 Harris, E.E., Beglinger, E., Hajny, G.J., and Sherrard, E.C., , Industrial and Engineering 

Chemistry, 37(1): 12–23 (1945) 

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1]

248 DOE National Laboratories. “30x30 A Scenario for Supplying 30% of 2004 Motor Gasoline 

with Ethanol by 2030: A Production Scenario for Cellulosic Ethanol from Corn Stover,” June 23, 

2006. 

249 LaMonica, Martin. “Investor Vinod Khosla: Advanced biofuels are closer than you think”. 

Accessed at: http://www.news.com/8301-11128_3-9811702-54.html 

250 DOE. “Biomass Program: ABC’s of Biofuels”. Accessed at: 

http://www1.eere.energy.gov/biomass/abcs_biofuels.html#content 

251 Starch Hydrolysis; http://www.bio-link.org/pdf/starch.pdf 

252 Glossary of Biomass Terms, National Renewable Energy Laboratory, Golden, CO. 

http://www.nrel.gov/biomass/glossary.html

253 Glossary of Biomass Terms, National Renewable Energy Laboratory, Golden, CO. 

http://www.nrel.gov/biomass/glossary.html

254 Condensation and Hydrolysis; http://www.biotopics.co.uk/as/disaccharideformation.html 

781 
 

255 BlueFire Ethanol. “Review of Competing Processes,” May 2006. Accessed at: 

http://www.bluefireethanol.com/images/Technology_Comparison_051206.ppt#295,1, 31 Musick 

Irvine, California 92618. 

256 Stephanopoulos, Gregory, et. al., “Challenges in Engineering Microbes for Biofuels 

Production,” Science, 315, 801, February 9, 2007.

257 Dipardo, Joseph, “Outlook for Biomass Ethanol Production and Demand,” Energy 

Information Administration, 2002. 

258 Aden, Andy, Ethanol Process Design and Economics Utilizing Co-current Dilute Acid 

Prehydrolysis and Enzymatic Hydrolysis for Corn Stover, Contract DE-AC36-99-GO10337, 

National Renewable Energy Laboratory, June 2002. 

259 Kim S, Holtzapple MT., “Effect of Structural Features on Enzyme Digestibility of Corn 

Stover,” Bioresource Technology, 97: 583-591, 2006. As sited in Gray, Kevin, et. al., 

“Bioethanol,” Current Opinion in Chemical Biology, 10:141-146, 2006.

260 A. Aden, M. Ruth, K. Ibsen, J. Jechura, K. Neeves, J. Sheehan, and B. Wallace 

National Renewable Energy Laboratory (NREL); L. Montague, A. Slayton, and J. Lukas Harris 

Group, Seattle, Washington, Ethanol Process Design and Economics Utilizing Co-Current Dilute 

Acid Prehydrolysis and Enzymatic Hydrolysis for Corn Stover; June 2002;NREL is a U.S. 

Department of Energy Laboratory Operated by Midwest Research Institute • Battelle • Bechtel; 

Contract No. DE-AC36-99-GO10337 

261 Graf, Angela, et. al., “Oregon Cellulose-Ethanol Study: An evaluation of the potential for 

ethanol production in Oregon using cellulose-based feedstocks,” Bryan & Bryan Inc and Oregon 

Office of Energy, 2000.

262 Tim Eggeman, Neoterics International, Lakewood, CO 80228, USA, Richard T. Elander, 

National Renewable Energy Laboratory, Golden, CO 80401, USA, Process and economic 

analysis of pretreatment technologies, Bioresource Technology 96 (2005) 2019–2025

263 Gray, K., et. al., “Bioethanol,” Current Opinion in Chemical Biology, 10:141-146, 2006.

264 Graf, op. sit.

265 DOE, “From Biomass to Biofuels: A Roadmap to the Energy Future.” based on a workshop 

held in Rockville, MD, on December 7-9, 2005. As sited in Stephanopoulos, Gregory, et. al., 

“Challenges in Engineering Microbes for Biofuels Production,” Science, 315, 801, February 9, 

2007. 

266 Presentations of K.C. McFarland (Novozymes) and G. Anderl (Genencor International) at the 

World Congress on Industrial Biotechnology and Bioprocessing, Orlando, FL, July 2006. As 

sited in Stephanopoulos, Gregory, et. al., “Challenges in Engineering Microbes for Biofuels 

Production,” Science, 315, 801, February 9, 2007.

267 Genencor Launches First Ever Commercial Enzyme Product for Cellulosic Ethanol, 

Rochester, NY, World-Wire, October 22, 2007 Copyright © 2007,. All rights reserved. WorldWire is a resource provided by Environment News Service. http://worldwire.com/news/0710220001.html

268 Purdue yeast makes ethanol from agricultural waste more effectively, Purdue News, June 28, 

2004 

http://www.purdue.edu/UNS/html4ever/2004/040628.Ho.ethanol.html 

269 Stephanopoulos, op. sit.

270 US. DOE. Technologies: Processing and Conversion. Accessed at: 

http://www1.eere.energy.gov/biomass/processing_conversion.html on October 28, 2008 

782
 
 

271 EERE, DOE, Thermochemical Conversion, & Biochemical Conversion, Biomass Program 

Thermochemical R&D . 

http://www1.eere.energy.gov/biomass/thermochemical_conversion.html
 

http://www1.eere.energy.gov/biomass/biochemical_conversion.html

272 Lin Wei, Graduate Research Assistant, Lester O. Pordesimo, Assistant Professor 

Willam D. Batchelor, Professor, Department of Agricultural and Biological Engineering, 

Mississippi State University, MS 39762, USA, Ethanol Production from Wood: Comparison of 

Hydrolysis Fermentation and Gasification Biosynthesis, Paper Number: 076036, Written for 

presentation at the 2007 ASABE Annual International Meeting. Minneapolis Convention Center, 

Minneapolis, MN, 17 - 20 June 2007

273 J. Phillips, “Different Types of Gasifiers and Their Integration with Gas Turbines,” 

EPRI/Advanced Coal Generation, 

http://www.netl.doe.gov/technologies/coalpower/turbines/refshelf/handbook/1.2.1.pdf, October 

30, 2008.

274 Ciferno, Jared P., Benchmarking Biomass Gasification Technologies for Fuels, Chemicals 

and Hydrogen Production, National Energy Technology Laboratory, Department of Energy, June 

2002. 

275 S. Phillips, A. Aden, J. Jechura, and D. Dayton, National Renewable Energy Laboratory, 

Golden, Colorado 80401-3393, T. Eggeman, Neoterics International, Inc., Thermochemical 

Ethanol via Indirect Gasification and Mixed Alcohol Synthesis of Lignocellulosic Biomass,
 

Technical Report, NREL/TP-510-41168, April 2007 

276 BRI Energy Bioengineering Resources for Renewable Energy. “The Co-Production of 

Ethanol and Electricity From Carbon-based Wastes,” A Report from BRI Energy, Inc. Regarding 

a New Technology That Addresses Multiple Energy and Waste Disposal Solutions, March 2006.

277 DOE EERE. “Biomass Program: Thermochemical Conversion of Corn Stover,” April 2006. 

Accessed at: http://www1.eere.energy.gov/biomass/pdfs/thermochemical_stover.pdf. 

278 S. Phillips, A. Aden, J. Jechura, and D. Dayton, National Renewable Energy Laboratory, 

Golden, Colorado 80401-3393, T. Eggeman, Neoterics International, Inc., Thermochemical 

Ethanol via Indirect Gasification and Mixed Alcohol Synthesis of Lignocellulosic Biomass,
 

Technical Report, NREL/TP-510-41168, April 2007 

279 DOE EERE Biomass Program. “Thermochemical Conversion Processes: Pyrolysis” 

http://www1.eere.energy.gov/biomass/thermochemical_processes.html, November 6, 2008. 

280 Zeman, Nicholas, “Thermochemical Versus Biochemical,” Biomass Magazine, June 2007.

281 Information derived from staff-level communication with National Biodiesel Board 

personnel.

282 “Tyson ConocoPhillips Venture in Jeopardy.” The Morning News, article dated 9/26/08. 

http://www.nwaonline.net/articles/2008/09/26/business/092708fuelcredits.txt 

283 October 6, 2008 article on Trading Markets website, “Groundbreaking Initiated for Unique 

Renewable Fuels Plant in Louisiana.” Accessed October 6, 2008. 

http://www.tradingmarkets.com/.site/news/Stock%20News/1923604/ 

284 “Tyson's Fats to Fuel Plant on Schedule.” The Morning News, article dated 10/6/08. 

http://www.nwaonline.net/articles/2008/10/06/business/100708tysonfuelplant.txt 

285 Neste Oil website, accessed 10/10/2008. 

http://www.nesteoil.com/default.asp?path=1,41,539,7516,7522 

783 
 

 

 

 

286 Renewable Fuels Association website, Historical U.S. Fuel Ethanol Production, 

http://www.ethanolrfa.org/industry/statistics/#A. 

287 Ibid 

288 Ethanol Producer Magazine website, Ethanol Plant Lists (Producing, Not Producing, Under 

Construction, Expansions), http://www.ethanolproducer.com/plant-list.jsp, Modified on April 14, 

2008. 

289 Renewable Fuels Association (RFA) website, Ethanol Biorefinery Locations, 

http://www.ethanolrfa.org/industry/locations, Updated on April 2, 2008.

290 Ibid. 

291 Ethanol Producer Magazine website, Ethanol Plant Lists (Producing, Not Producing, Under 

Construction, Expansions), http://www.ethanolproducer.com/plant-list.jsp, Modified on April 14, 

2008. 

292 Renewable Fuels Association (RFA) website, Ethanol Biorefinery Locations, 

http://www.ethanolrfa.org/industry/locations, Updated on April 2, 2008.

293 Ministry of Agriculture in Brazil (MAPA), http://www.agricultura.gov.br/ Accessed: April 3, 

2009 

294 F.O. Licht’s, “World Ethanol Markets: The Outlook to 2015,” pg. S-22 to S-23, 2006. 

295 F.O. Licht’s, “World Ethanol and Biofuels Report,” Vol. 5, No. 22, July 23, 2007. 

296 Agra FNP, “Sugar and Ethanol in Brazil: A Study of the Brazilian Sugar Cane, Sugar and 

Ethanol Industries,” 2007.

297 Ministry of Mines and Energy, “The Brazilian Experience with Biofuels,” Presentation by 

Ricardo de Gusmao Dornelles, June 1, 2007. 

298 Agra FNP, op. sit.

299 ANFAVEA (Associação Nacional dos Fabricantes de Veículos Automotores 

Assessoria de Planejamento Econômico e Estatístico Indústria Automobilística Brasileira - 

Empresas Associadas). Internal Sales in Brazil 2008. 

http://www.anfavea.com.br/tabelas2008.html, April 9, 2009.

300 Ministerio da Agricultura, Pecularia E Abastecimento (MAPA), “Brazilian Ethanol 

Production,” 

http://www.agricultura.gov.br/pls/portal/docs/PAGE/MAPA/ESTATISTICAS/PRODUCAO/06­

PROD.%20BR%20%C1LCOOL.PDF, April 9, 2009.

301 Ewing, Elizabeth, “Pipeline Projects on Hold.” Ethanol Producer Magazine, July 2008.

302 Rothkopf, Garten, “A Blueprint for Green Energy in the Americas,” 2006. 

303 Ibid. 

304 World Biofuels: FAPRI 2007 Agricultural Outlook; OECD-FAO Agricultural Outlook 2007­

2016, 2007 (note: this was interpreted from a graph); Bioenergia: Liquid Biofuels, “18 Billion 

Liters a Year!” March 2007; Rothkopf, op. sit. (note: years 2007-2019 were interpreted from a 

graph); EPE, “Plano National de Energia 2030,” Presentation from Mauricio Tolmasquim, 2007 

(note: years were interpreted from a graph); UNICA, “Sugarcane Industry in Brazil: Ethanol, 

Sugar, Bioelectricity” brochure, 2008.

305 Agra FNP, op. sit.

306 Carpenter, Claudia, “Sugar Gains Capped by Brazil Ethanol Expansion, Czarnikow Says,” 

Bloomberg, June 19, 2008.

307 F.O. Licht GmbH, “89 New Ethanol Facilities to Come Online in 2007-11 – BNDES,” F.O. 

Licht’s World Ethanol & Biofuels Report, Vol. 5, No. 22, July 23, 2007. 

784
 
 

 

 

308 AFP, “Brazil says biofuel production not to blame for food crisis,” June 1, 2008. 

309 Business News Americas, “Odebrecht to invest US$2.6 bn to Lead Ethanol Sector – Brazil,” 

June 28, 2007.

310 The Wall Street Journal, “ADM Plans Entry Into Sugar-Cane Ethanol in Brazil,” June 22, 

2007. 

311 Agra FNP, op. sit.

312 Petrobras Magazine No. 122. “Ethanol: From Brazil to the World,” August 13, 2007. 

313 Ibid. 

314 World Energy: Global News Summary. Published June 13, 2008, http://www.worldenergy.net 

315 Ewing, op. sit.

316 Rothkopf, op. sit.

317 Ibid.
 318 F.O. Licht GmbH. “Ethanol Blend Rose to 25% on July 1, 2007,” F.O. Licht’s World Ethanol 

& Biofuels Report, Vol. 5, No. 21, July 9, 2007.

319 Petrobras Magazine No. 122, op. sit.

320 Agra FNP, op. sit.

321 F.O. Licht GmbH. “Sobering Times for Biofuels in Seville,” F.O. Licht’s World Ethanol & 

Biofuels Report, Vol. 5, No. 20, June 19, 2007. (note: only 2006, 2015 & 2025 values were 

reported, other values are interpolated); World Biofuels: FAPRI 2007 Agricultural Outlook; 

EPE, op. sit. (note: years were interpreted from a graph); UNICA, “Sugarcane Industry in Brazil: 

Ethanol, Sugar, Bioelectricity” brochure, 2008.

322 Ewing, op. sit.

323 Walter, A. et. al., “Perspectives on Fuel Ethanol Consumption and Trade,” Biomass and 

Bioenergy, 32, 730-748, 2008.

324 AFP., “EU Deputies Seek to Limit Use of Biofuels,” September 11, 2008. 

325 Energy Information Administration (EIA), “Reference Case Projections by End-Use Sector 

and Region Data Table F6,” International Energy Outlook 2007,
 

http://www.eia.doe.gov/oiaf/archive/ieo07/ieonuclear.html

326 BP, “BP Statistical Review of World Energy 2007 (revised with 2008 statistics) Historical 

Data,” http://www.bp.com/statisticalreview. 

327 Walter, A., op. sit.

328 Ayoub PM. Biofuels for Shell-biomass based blending components for transport fuels 

(gasoline and diesel). In: World biofuels symposium-China, Beijing, 2006. As sited in Walter, 

op. sit.

329 Ribeiro, F., “The New European Challenge for Brazilian Ethanol Exports,” Frost & Sullivan 

Market Insight, February 7, 2008.

330 European Bioethanol Fuel Association (eBio), “The EU market: Production and 

Consumption,” http://www.ebio.org/EUmarket.php, April 9, 2009. 

331 European Bioethanol Fuel Association (eBio), “Production Capacity Installed” and 

“Production Capacity Under Construction,” http://www.ebio.org/statistics.php?id=5 and 

http://www.ebio.org/statistics.php?id=6, April 9, 2009. 

332 F.O. Licht GmbH. “Sobering Times for Biofuels in Seville,” F.O. Licht’s World Ethanol & 

Biofuels Report, Vol. 5, No. 20, June 19, 2007.

333 Fukuda, Hisao, et. al.,“Japan Bio-fuels Production Report,” USDA, FAS, May 26, 2006. 

http://www.fas.usda.gov/gainfiles/200605/146197881.pdf 

785 
 

 

 

334 Rothkopf, op. sit.

335 Fukuda, op. sit.

336 Ibid. 

337 Rothkopf, op. sit.

338 Jolly, Lindsay, “World Fuel Ethanol Outlook: Can ethanol be traded globally in a large 

proportion?,” International Sugar Organization, Presentation to 9th World Beet and Cane 

Growers Conference, 9-12 July 2007.

339 Rothkopf, op. sit.

340 Ibid. 

341 Ferreira, Lenilson, “Brazil Priming Ethanol Initiative to Supply Fuel-Thirsty Japan,” The 

Japan Times, August 22, 2007. http://search.japantimes.co.jp/print/nb20070822a3.html
 342 Ewing, op. sit.

343 Fukuda, op. sit.

344 Rothkopf, op. sit.

345 Ibid.
 346 F.O. Licht GmbH. “2006/07 Fuel Ethanol Consumption Seen at Merely 250 Mln Litres – 

USDA Attaché,” F.O. Licht’s World Ethanol & Biofuels Report, Vol. 5, No. 20, June 19, 2007.

347 Nayak, D., “Weak Crude, Cane Shortage Hit India Ethanol Expansion” Wall Street Journal, 

April, 1, 2009.

348 Regaldo, Antonio, et. al., “Ethanol Giants Struggle to Crack Brazil Market,” Wall Street 

Journal, September 10, 2007. 

349 Ibid.
 350Renewable Fuels Association (RFA), “2007 World Fuel Ethanol Production, ” 

http://www.ethanolrfa.org/industry/statistics/#E, November 10, 2008.

351 Ohga K. & Tatsuji K. Biofuels Policies in Asia: Trade effects on World Agricultural and 

Biofuels Trade. Presentation to USDA Agricultural Outlook Forum, March 2, 2007. 

352 Interfax China, “Biofuel Increasing China’s Corn Imports,” December 1, 2006. 

353 Ohga, op. sit.

354 F.O. Licht GmbH, “New Ethanol Plants Will Rely on Non-Grain Feedstocks,” F.O. Licht’s 

World Ethanol & Biofuels Report, Vol. 5, No. 22, July 23, 2007.

355 Rothkopf, op. sit.

356 AFX News Limited, Forbes, “China to Freeze Approvals for Corn Processing Projects for 3 

Years,” September 21, 2007. 

http://www.forbes.com/markets/feeds/afx/2007/09/21/afx4142281.html

357 F.O. Licht GmbH, “New Ethanol Plants Will Rely on Non-Grain Feedstocks,” F.O. Licht’s 

World Ethanol & Biofuels Report, Vol. 5, No. 22, July 23, 2007.

358 Rothkopf, op. sit.

359 Ohga, op. sit. Note: Metric Tons are assumed to be of ethanol and values are converted to 

ethanol volumes based on the density of ethanol and other conversion factors. 

360 Rothkopf, op. sit.

361 Ibid. 

362 Ibid. 

363 F.O. Licht GmbH, “New Ethanol Plants Will Rely on Non-Grain Feedstocks,” F.O. Licht’s 

World Ethanol & Biofuels Report, Vol. 5, No. 22, July 23, 2007.

364 Rothkopf, op. sit. 

786
 
 

 

365 EIA, “U.S. Oxygenates: Fuel Ethanol Imports,” Last updated on October 10, 2008. 

http://tonto.eia.doe.gov/dnav/pet/pet_move_impcus_a2_nus_EPOOXE_im0_mbbl_m.htm

366 Joseph, Ken, “Argentina Bio-Fuels Argentine Bio-Fuels Report 2007,” USDA, FAS, May 21, 

2007. http://www.fas.usda.gov/gainfiles/200706/146291490.pdf 

367 Deborah O’Connell, et. al., “Biofuels in Australia - Issues and Prospects. A Report for the 

Rural Industries Research and Development Corporation,” CSIRO Australian Government Rural 

Industries Research and Development Corporation, May 2007. 

368 Roberts, Greg, “Rees scraps biofuel mandates,” The Australian: Online Newspaper of the 

Year, September 20, 2008. http://www.theaustralian.news.com.au/story/0,25197,24373888­

11949,00.html

369 Sobolik, Jessica, “Canadian Government Passes Renewable Fuels Standard,” Ethanol 

Producer Magazine, August 2008.

370 Pinzon, L., “Colombia Bio-fuels Annual 2007,” USDA, FAS, June 1, 2007. 

http://www.fas.usda.gov/gainfiles/200706/146291386.pdf 

371 Chavez, L., et. al., “Mexico Bio-fuels Annual Report 2007,” USDA, FAS, June 12, 2007. 

http://www.fas.usda.gov/gainfiles/200706/146291366.pdf 

372 F.O. Licht’s, “World Ethanol Markets: The Outlook to 2015,” pg. S-18 to S-20, 2006. 

373 Office of the United States Trade Representative (USTR), “Caribbean Basin Initiative,” 

November 12, 2008. 

http://www.ustr.gov/Trade_Development/Preference_Programs/CBI/Section_Index.html

374 Bryan, Tom, “Entering Tariff-Free,” Ethanol Producer Magazine, January 2004. 

375 Office of the United States Trade Representative (USTR), “Ethanol Provisions in the 

CAFTA-DR,” July 2007.

376 Bryan, op. sit.

377 Rapoza, Kenneth, “UPDATE: Tax Loophole Helps US Import Ethanol ‘Duty Free’- ED&F,” 

INO News, Dow Jones Newswires, March 2008. http://news.ino.com/
 378 Peter Rhode, “Senate Finance May Take Up Drawback Loophole As Part of Energy Bill,” 

EnergyWashington Week, April 18, 2007. As sited in Yacobucci, Brent, “Ethanol Imports and 

the Caribbean Basin Initiative,” CRS Report for Congress, Order Code RS21930, Updated 

March 18, 2008.

379 Perkins, Jerry, “BRAZIL: Loophole Hurt U.S. Ethanol Prices,” DesMoinesRegister.com, 

October 18, 2007.

380 Public Law Version 6124 of the Farm Bill. 2008. 

http://www.usda.gov/documents/Bill_6124.pdf. 

381 Lundell, Drake, “Brazilian Ethanol Export Surge to End; U.S. Customs Loophole Closed Oct. 

1,” Ethanol and Biodiesel News, Issue 45, November 4, 2008. 

382 MacDonald, T., et. al., “Ethanol Supply Outlook for California,” California Energy 

Commission, October 2003. http://www.ethanolrfa.org/objects/documents/100/castaffreport.pdf 

383 Petrojam Limited, “Official Opening of Petrojam Ethanol Limited,” November 12, 2008. 

http://www.pcj.com/petrojam/whats_new.htm

384 Petrojam Limited, “About Us,” November 12, 2008. 

http://www.petrojambunkering.com/petrojam_aboutb.htm

385 F.O. Licht GmbH, “Company News- JBG Commences Fuel Ethanol Production,” F.O. 

Licht’s World Ethanol & Biofuels Report, Vol. 5, No. 22, July 23, 2007.

386 Email Correspondence with Jeffrey Tuite, ED&F Man, September 6, 2007. 

787 
 

 

387 Yacobucci, Brent, “Ethanol Imports and the Caribbean Basin Initiative,” CRS Report for 

Congress, Order Code RS21930, Updated March 18, 2008.

388 Email Correspondence with Jeffrey Tuite, ED&F Man, September 6, 2007. 

389 Ethanol Producer Magazine, “Ethanol Dehydration Facility to be Built in Trinidad,” 

December 2006. 

390 Etter, Lauren, and Millman, Joel, “Ethanol Tariff Loophole Sparks a Boom in Caribbean 

Islands Build Plants To Process Brazil’s Fuel; Farm Belt Cries Foul,” Wall Street Journal, March 

9, 2007.

391 Homer, Louis, “Another Energy Sector Stimulus,” PetroleumWorld.com. November 22, 

2006. http://www.petroleumworldtrinidad.com/storytrini06112606.htm

392 Etter, op. sit.

393 Browne, J., “Angostura Launches US$11m Ethanol Plant,” The Trinidad Guardian. August 6, 

2004. http://www.guardian.co.tt/archives/2004-08-06/business1.html 

394 Email Correspondence with Jeffrey Tuite, ED&F Man, September 6, 2007. 

395 Ramjeet, Oscar, “Barbados to Build $72 Million Ethanol Dehydration Plant,” Caribbean Net 

News, August 22, 2008.

396 Jamaica Gleaner News, “US$36m Ethanol Plant for Barbados,” August 23, 2008. 

http://www.jamaica-gleaner.com/gleaner/20080823/business/business1.html 

397 Email Correspondence with Jeffrey Tuite, ED&F Man, September 6, 2007. 

398 Bryan, op. sit.

399 Etter, op. sit.

400 Ibid.
 401 Email Correspondence with Jeffrey Tuite, ED&F Man, September, 7, 2007. 

402 Etter, op. sit.

403 International Trade Commission 2005-2007 historical ethanol import data as reported by the 

Renewable Fuels Association, http://www.ethanolrfa.org/industry/statistics/

404 Communication from Douglas Newman, International Trade Commission to Doris Wu, EPA, 

May 20, 2008.

405 Energy Information Administration historical gasoline and ethanol import data: 

http://www.eia.doe.gov/oil_gas/petroleum/data_publications/company_level_imports/cli_historic
 

al.html 

406 U.S. Department of Energy, “DOE Selects Six Cellulosic Ethanol Plants for Up to $385 

Million in Federal Funding” (Press Release & Attachments), 

http://www.energy.gov/print/4827.htm, February 28, 2007. 

407 U.S. Department of Energy, “DOE Announces up to $200 Million in Funding for 

Biorefineries” (Press Release), http://www.energy.gov/print/5031.htm, May 1, 2007.

408 U.S. Department of Energy, “U.S. Department of Energy Selects First Round of Small-Scale 

Biorefinery Projects for up to $114 Million in Federal Funding” (Press Release & Attachments), 

http://www.energy.gov/print/5903.htm, January 29, 2008. 

409 U.S. Department of Energy, “DOE Selects 3 Small-Scale Biorefinery Projects for up to $86 

Million of Federal Funding in Maine, Tennessee and Kentucky” (Press Release & Attachments), 

http://www.energy.gov/print/6164.htm, April 18, 2008. 

410 U.S. Department of Energy, “DOE to Provide up to $40 Million in Funding for Small-Scale 

Biorefinery Projects in Wisconsin and Louisiana” (Press Release & Attachments), 

http://www.energy.gov/print/6413.htm, July 14, 2008.
 

788
 
 

411 U.S. Department of Energy, “DOE Announces Final Rule for Loan Guarantee Program” 

(Press Release), http://www.energy.gov/print/5568.htm, October 4, 2007.
 412 U.S. Department of Energy, “DOE Selects Five Ethanol Conversion Projects for $23 Million 

in Federal Funding” (Press Release), http://www.energy.gov/print/4896.htm, March 27, 2007.
 413 U.S. Department of Energy, “Energy and Agriculture Depts. Provide $8.3 Million in Funding 

for Biofuels Research” (Press Release), http://www.energy.gov/print/5115.htm, June 7, 2007.
 414 U.S. Department of Energy, “Energy Department Selects Three Bioenergy Research Centers 

for $375 Million in Federal Funding” (Press Release & Attachments), 

http://www.energy.gov/print/5172.htm, June 26, 2007.
 415 U.S. Department of Energy, “Department of Energy to Invest up to $7.7 Million for Four 

Biofuels Projects” (Press Release), http://www.energy.gov/print/5757.htm, December 4, 2007. 

416 U.S. Department of Energy, “U.S. Department of Energy to Invest up to $33.8 Million to 

Further Development of Commercially Viable Renewable Fuels” (Press Release), 

http://www.energy.gov/print/6015.htm, February 26, 2008. 

417 U.S. Department of Energy, “USDA, DOE to Invest up to $18.4 Million for Biomass 

Research, Development and Demonstration Projects” (Press Release), 

http://www.energy.gov/print/6035.htm, March 4, 2008. 

418 U.S. Department of Energy, Energy Efficiency and Renewable Energy website, Ethanol 

Incentives & Laws, http://www.eere.energy.gov/afdc/ethanol/incentives_laws.html, State Data 

Downloaded in July 2008. 

419Midwest Governors Association, “Energy Security and Climate Stewardship Platform for the 

Midwest 2007,” http://www.midwesterngovernors.org/resolutions/Platform.pdf, Published 

November 2007. 

420 110th Congress of the United States of America, Second Session, The Food, Conservation, 

and Energy Act of 2008, House Rule 6124, http://www.usda.gov/documents/Bill_6124.pdf, 

Introduced on January 3, 2008 and Enacted on June 18, 2008.

421Archer Daniels Midland, “Joint ADM and Purdue University Cellulosic Ethanol Project 

Selected for Funding by U.S. Department of Energy” (Press Release), 

http://www.admworld.com/naen/pressroom/newspopup.asp?id=454&name=Joint_Cellulosic_Et
 

hanol_Project, April 16, 2007.

422 Archer Daniels Midland, “ADM, Deere, Monsanto to Collaborate on Corn Stover Research” 

(Press Release), http://www.admworld.com/naen/pressroom/newspopup.asp?id=517, August 26, 

2008. 

423 POET, “Iowa finalizes cellulosic partnership with POET” (Press Release), 

http://www.renewableenergyworld.com/rea/partner/poet-7042/news/article/2009/02/iowafinalizes-cellulosic-partnership-with-poet 

424 Elbehri, Aziz. USDA, ERS. “An Evaluation of the Economics of Biomass Feedstocks: A 

Synthesis of the Literature. Prepared for the Biomass Research and Development Board,” 2007; 

Since 2007, a final report has been released. Biomass Research and Development Board., “The 

Economics of Biomass Feedstocks in the United States: A Review of the Literature,” October 

2008. 

425 Graham, R.L., “Current and Potential U.S. Corn Stover Supplies,” American Society of 

Agronomy 99:1-11, 2007.

426 Wilhelm, W.W. et. al., “Corn Stover to Sustain Soil Organic Carbon Further Constrains 

Biomass Supply,” Agron. J. 99:1665-1667, 2007.
 

789 
 

427 NASS database. http://www.nass.usda.gov/ 

428 Smith, W. Brad et. al., ”Forest Resources of the United States, 2002 General Technical 

Report NC-241,” St. Paul, MN: U.S. Dept. of Agriculture, Forest Service, North Central 

Research Station, 2004.

429 USDA-Forest Service. “Timber Products Output Mapmaker Version 1.0.” 2004. 

430 NASS database. http://www.nass.usda.gov/ 

431 USDA, WGA, Bioenergy Strategic Assessment project findings upcoming as noted in report 

WGA. Transportation Fuels for the Future Biofuels: Part I. 2008. 

432 Industry data for 2008 taken from National Biodiesel Board fact sheets at 

http://www.biodiesel.org/buyingbiodiesel/producers_marketers/Producers%20Map-Existing.pdf 

and http://www.biodiesel.org/pdf_files/fuelfactsheets/Production_graph_slide.pdf (both 

accessed April 27, 2009). 

433 “Tyson ConocoPhillips Venture in Jeopardy.” The Morning News, article dated 9/26/08. 

http://www.nwaonline.net/articles/2008/09/26/business/092708fuelcredits.txt 

Press release and project timeline on Syntroleum website, updated January 13, 2009 

(http://www.syntroleum.com/dynamic_fuels_plant09.aspx), accessed April 27, 2009. 

http://www.tradingmarkets.com/.site/news/Stock%20News/1923604/ 

435 “Tyson's Fats to Fuel Plant on Schedule.” The Morning News, article dated 10/6/08. 

http://www.nwaonline.net/articles/2008/10/06/business/100708tysonfuelplant.txt 

436 Syntroleum Investor Presentation, March 2008. Accessed October 6, 2008. 

http://www.syntroleum.com/pdf/InvestorPresentation.pdf 

437 “Ethanol Transportation Backgrounder, Expansion of U.S. Corn-based Ethanol from the 

Agricultural Transportation Perspective”, USDA, September 2007, 

http://www.ams.usda.gov/tmd/TSB/EthanolTransportationBackgrounder09-17-07.pdf 

438 Association of Oil Pipelines: http://aopl.org/go/searchresults/888/?q=ethanol&sd=&ed=. 

“Hazardous Liquid Pipelines Transporting Ethanol, Ethanol Blends, and Other Biofuels”, Notice 

of policy statement and request for comment, Pipeline and Hazardous Materials Safety 

Administration, Department of Transportation, August 10, 2007, 72 FR 45002. 

439 Article on the initiation of Kinder Morgan ethanol pipeline service between Tampa and 

Orlando Florida: http://www.ethanolproducer.com/article.jsp?article_id=5163 

440 Magellan and Poet joint assessment of dedicated ethanol pipeline: 

http://www.magellanlp.com/news/2009/20090316_5.htm 

441 “Ethanol Transportation Backgrounder”, U.S. Department of Agriculture , September 2007, 

http://www.ams.usda.gov/AMSv1.0/getfile?dDocName=STELPRDC5063605&acct=atpub 

442 “Analysis of Fuel Ethanol Transportation Activity and Potential Distribution Constraints”, 

prepared for EPA by Oak Ridge National Laboratory, March 2009. 

443 “Ethanol Transportation Backgrounder”, U.S. Department of Agriculture , September 2007, 

http://www.ams.usda.gov/AMSv1.0/getfile?dDocName=STELPRDC5063605&acct=atpub 

790
 
 

444 “The Importance of Adequate Rail Investment”, Association of American Railroads, 

http://www.aar.org/GetFile.asp?File_ID=150 

445 American Association of State Highway and Transportation Officials (AASHTO) FreightRail Bottom-Line Report, 2003. 

446 Association of American Railroads (AAR), National Rail Freight Infrastructure Capacity and 

Investment Study, September 2007. 

447 “Barge Transportation in the United States”. Timothy Casey, Presentation at the MARE 

Forum USA, 2006, 

http://www.mareforum.com/ENERGY_TRANSPORTATION_USA_2006_PRESENTATIONS_ 

files/CASEY.pdf 

448 Energy Information Administration (EIA) historical company level ethanol and gasoline 

import data: 

http://www.eia.doe.gov/oil_gas/petroleum/data_publications/company_level_imports/cli_historic 

al.html 

449 “The U.S. Truck Driver Shortage: Analysis and Forecasts”, Prepared by Global Insights for 

the American Trucking Association, May 2005. 

http://www.truckline.com/NR/rdonlyres/E2E789CF-F308-463F-8831­

0F7E283A0218/0/ATADriverShortageStudy05.pdf 

450 “Renewable Fuel Standard Challenges Faced by Terminals”, Andrea Grant, Independent Fuel 

Terminal Operators Association, May, 13, 2008, presentation at the 2008 Society of Automotive 

Engineers Government-Industry Meeting. 

451 “Infrastructure Requirements for an Expanded Fuel Ethanol Industry”, Downstream 

Alternative Incorporated, January 15, 2002.

452 A discussion of the estimated number of terminals that carry diesel fuel is contained in 

Chapter V of the Regulatory Impact Analysis to the final highway diesel fuel rule 

http://www.epa.gov/otaq/highway-diesel/regs/ria-v.pdf, EPA Docket A-99-06. 

453 “Renewable Fuel Standard Challenges Faced by Terminals”, Andrea Grant, Independent Fuel 

Terminal Operators Association, May, 13, 2008, presentation at the 2008 Society of Automotive 

Engineers Government-Industry Meeting. 

454 “Renewable Fuel Standard Challenges Faced by Terminals”, Andrea Grant, Independent Fuel 

Terminal Operators Association, May, 13, 2008, presentation at the 2008 Society of Automotive 

Engineers Government-Industry Meeting. 

455 “Summary Data on Diesel Fuel Retailers”, Memorandum to the Docket, Jeffery Herzog, U.S. 

EPA, March 23, 2000, EPA Docket A-99-06, Docket Item II-B-07. 

791 
 

 

 

456 2007 National Association of Convenience Stores State of the Industry survey data 

www.nacsonline.com as reported in the National Petroleum News MarketFacts 2007, October 

2007. 

457 “Diesel Throughput Volume by Percentage of Diesel Fuel Retailers”, Memorandum to the 

Docket, Jeffery Herzog, U.S. EPA, May 05, 2000, EPA Docket A-99-06, Docket Item II-B-14. 

458 The National Ethanol Vehicle Coalition estimate of E85 refueling facilities is located at 

http://www.e85refueling.com/ estimates http://www.e85refueling.com/ 

459 The “NEAR85” estimate of E85 retail facilities is located at http://www.neare85.com/ 

460 National Petroleum News, MarketFacts 2007, Volume 99, Number 10, October 2007, 

www.npnweb.com 

461 A discussion of Underwriter Laboratories (UL) requirements for E85 retail dispenser 

equipment entitled “Power-Operated Dispensing Devices for Gasoline/Ethanol Blends other than 

Gasohol (E10)” can be found at http://ulstandardsinfonet.ul.com/outscope/0087A.html 

462 U.S. Environmental Protection Agency, Regulatory Impact Analysis: Renewable Fuel 

Standard, EPA420 R-04-004, http://www.epa.gov/otaq/renewablefuels/420r07004chap2.pdf, 

April 2007 (Chapter 2, Table 2.2-6). 

463 U.S. Environmental Protection Agency, Regulation of Fuels and Fuel Additives: Renewable 

Fuel Standard Program, Final Rule, 72 FR 23900, http://www.epa.gov/otaq/renewablefuels/rfsfinalrule.pdf, May 1, 2007.

464 U.S. Department of Energy, Energy Information Administration, Monthly Energy Review, 

http://tonto.eia.doe.gov/FTPROOT/multifuel/mer/00350809.pdf, September 2008 (Table 10.2b). 

465 ibid
 466 110th Congress of the United States of America, Second Session, The Food, Conservation, and 

Energy Act of 2008, House Rule 6124, http://www.usda.gov/documents/Bill_6124.pdf, 

Introduced on January 3, 2008 and Enacted on June 18, 2008.

467 Kauffman, Tim, “Miles to go for Alternative Fuel,” Federal Times, June 23, 2008 (pp. 11, 

14).

468 DOE Energy Efficiency and Renewable Energy August 2008 estimate (worksheet available at 

www.eere.energy.gov/afdc/data/index.html) 

469 U.S. Department of Energy, Energy Information Administration, Annual Energy Outlook 

2007, Reference Case Tables, http://www.eia.doe.gov/oiaf/archive/aeo07/pdf/yearbyyear.pdf, 

February 2007 (Table 17).

470 U.S. Department of Energy, Energy Information Administration, Annual Energy Outlook 

2007, Reference Case Tables, http://www.eia.doe.gov/oiaf/archive/aeo07/pdf/yearbyyear.pdf, 

February 2007 (Table 2). 

471 U.S. Department of Energy, Energy Information Administration, Annual Energy Outlook 

2008, Reference Case Tables, http://www.eia.doe.gov/oiaf/aeo/excel/yearbyyear.xls, June 2008 

(Table 2). 

472 Ibid 

473 National Ethanol Vehicle Coalition, 2008 Purchasing Guide for Flexible Fuel Vehicles. 

474 Ibid 

792
 
 

 

 

 

475 U.S. Department of Energy, Energy Efficiency and Renewable Energy, Transportation 

Energy Book: Edition 26, Prepared by Oak Ridge National Laboratory, ORNL-6978, 2007 

(Table 2.5). 

476 National Ethanol Vehicle Coalition, 2008 Purchasing Guide for Flexible Fuel Vehicles. 

477 110th Congress of the United States of America, Second Session, The Open Fuel Standard Act 

of 2008, Senate Bill 3303, http://thomas.loc.gov/cgi-bin/query/z?c110:S.3303, Introduced on July 

22, 2008.

478 110th Congress of the United States of America, Second Session, The Open Fuel Standard Act 

of 2008, House Rule 6559, http://thomas.loc.gov/cgi-bin/bdquery/z?d110:H.R.6559, Introduced 

on July 22, 2008. 

479 U.S. Department of Energy, Energy Efficiency and Renewable Energy website, Ethanol 

Incentives & Laws, http://www.eere.energy.gov/afdc/ethanol/incentives_laws.html, State Data 

Downloaded in July 2008. 

480 NEVC FYI Newsletter: Volume 15, Issue 5: March 9, 2009. 

481 National Petroleum News, Market Facts 2007, 2007 NPN Station Count (a), October 2007 

(page 92).

482 National Ethanol Vehicle Coalition, , FYI Newsletter: Volume 13, Issue 10, 

http://www.e85fuel.com/news/072307fyi.htm, July 23, 2007 483 U.S. Department of Energy, Energy Efficiency and Renewable Energy website, Ethanol 

Incentives & Laws, http://www.eere.energy.gov/afdc/ethanol/incentives_laws.html, State Data 

Downloaded in July 2008. 

484 Midwest Governors Association, “Energy Security and Climate Stewardship Platform for the 

Midwest 2007,” http://www.midwesterngovernors.org/resolutions/Platform.pdf, Published 

November 2007. 

485 110th Congress of the United States of America, Second Session, TheE85 and Biodiesel 

Access Act of 2008, House Rule 6734, http://www.e85fuel.com/legislation/hr_6734.doc, 

Introduced on July 31, 2008.

486 National Ethanol Vehicle Coalition, 2008 Purchasing Guide for Flexible Fuel Vehicles. 487 Based on average E85 and regular unleaded gasoline prices reported at http://www.fuelgaugereport.com/ on 

April 23, 2009. 

488 U.S. Department of Energy, Energy Information Administration, Petroleum Marketing 

Annual 2006, http://tonto.eia.doe.gov/FTPROOT/petroleum/048706.pdf, August 2007 (Table 

31).

489 American Petroleum Institute, Gasoline Tax Report, 

http://www.api.org/statistics/fueltaxes/upload/October_2006_gasoline_and_diesel_summary_pag
 

es.pdf, October 2006.

490 Brownstone, D., Small, K.A., Valuing Time and Reliability: Assessing the Evidence from
 

Road Pricing Demonstrations, Transportation Research Part A 39, 2005 (pages 293-279). 

491 Greene, David, Survey Evidence on the Importance of Fuel Availability to Choice of
 

Alternative Fuels and Vehicles, Prepared by Oak Ridge National Laboratory, 

http://ntl.bts.gov/lib/000/700/723/survey.pdf, November 11, 1997. 

492 Based on May 2008 meeting with SIGMA/NACS.
 493 National Petroleum News, Market Facts 2007, Branded Retail Outlets by Rank 2006, October 

2007 (page 93).
 494 Based on May 2008 meeting with SIGMA/NACS.
 

793 
 

 

 

 

 

 

495 U.S. Department of Energy, Energy Information Administration, Petroleum Marketing Annual 

2006, http://tonto.eia.doe.gov/FTPROOT/petroleum/048706.pdf, August 2007 (Table 48).

496 U.S. Department of Energy, Energy Information Administration, Petroleum Marketing 

Annual 2006, http://tonto.eia.doe.gov/FTPROOT/petroleum/048706.pdf, August 2007 (Tables 

31, 34 & 48).

497 U.S. Environmental Protection Agency, Draft Regulatory Impact Analysis: Control of 

Hazardous Air Pollutants from Mobile Sources, EPA420 D-06-004, 

http://www.epa.gov/otaq/regs/toxics/chapter9.pdf, February 2006 (Chapter 9).

498 American Petroleum Institute, Gasoline Tax Report, 

http://www.api.org/statistics/fueltaxes/upload/January_2008_gasoline_and_diesel_summary_pag 

es-2.pdf, January 2008.

499 Department of Energy, Alternative Fuels & Advanced Vehicles Data Center, Biodiesel 

Incentives and Laws. Accessed July 2008. 

http://www.afdc.energy.gov/afdc/fuels/biodiesel_laws.html

500 Energy Information Administration, 2005 Prime Supplier Sales Volumes for No. 2 Diesel. 

Accessed 10/7/2008. 

http://tonto.eia.doe.gov/dnav/pet/pet_cons_prim_a_EPD2D_P00_Mgalpd_a.htm

501 Energy Information Administration, Fuel Oil and Kerosene Sales 2006, Table 16. 2005 data 

column used. 

http://www.eia.doe.gov/pub/oil_gas/petroleum/data_publications/fuel_oil_and_kerosene_sales/c 

urrent/pdf/table16.pdf

502 Clean Air Act Section 211(o)(1) 503 2006 IPCC Guidelines for National Greenhouse Gas Inventories. 2006. Agriculture, Forestry and Other Land 

Uses. Volume 4. http://www.ipcc-nggip.iges.or.jp/public/2006gl/vol4.html

504 Curran MA, Mann M, Norris G, 2001, Report on the International Workshop on Electricity Data for Life Cycle 

Inventories, US Environmental Protection Agency, Cincinnati, USA 

505 Ekvall T, Weidema BP, 2004, System boundaries and input data in consequential life cycle inventory analysis. 

International Journal of Life Cycle Assessment, 9, 161-171 

506 Kloverpris et al., 2008, Conference and Workshop on Modeling Global Land Use Implications in the 

Environmental Assessment of Biofuels, International Journal of Life Cycle Assessment, 13(3) 178-183

507 Kloverpris, Wenzel and Nielsen, 2008, Life Cycle Inventory Modelling of Land Use Induced by Crop 

Consumption, International Journal of Life Cycle Assessment, 13(1): 13-21 

508 Ekvall and Weidema 2004 

509 Schmidt, 2008, System delimitation in agricultural consequential LCA, International Journal of Life Cycle 

Assessment, 13: 350-364 

510 Delucchi, M. 2005. Incorporating the Effect of Price Chanes on CO2-Equivalent Emissions from Alternative Fuel 

Lifecycles: Scoping the Issues. Working Paper UCD—ITS—RR—05—19. 

http://pubs.its.ucdavis.edu/publication_detail.php?id=62

511 Fargione, J., J. Hill, D. Tilman, S. Polasky, and P. Hawthorne. 2008. Land clearing and the biofuel carbon debt. 

Science 319 :1235–1238. 

512 Searchinger, T., R. Heimlich, R.A. Houghton, F. Dong, A. Elobeid, J. Fabiosa, S. Tokgoz, D. Hayes, and T.-H. 

Yu. 2008. Use of U.S. croplands for biofuels increases greenhouse gases through emissions from land-use change. 

Science 319 :1238–1240. 

513 http://www.epa.gov/sequestration/greenhouse_gas.html 514 Crutzen, P. J., Mosier, A. R., Smith, K. A., and Winiwarter, W.: N2O release from agro-biofuel production 

negates global warming reduction by replacing fossil fuels, Atmos. Chem. Phys., 8, 389-395, 2008. 

515 McCann, T., and Magee, P., Crude Oil Greenhouse Gas Life Cycle Analysis Helps Assign Values For CO2 

Emissions Trading . Oil and Gas Journal. Vol. 97, no. 8, pp. 38-44. Feb 1999. 

794
 
 

 

 

 

 

 

 

516 USGS (November 2006), “Natural Assessment of Oil and Gas Fact Sheet: Natural Bitumen Resources of the 

United States,” Fact Sheet 2006-3133; USGS (August 2003), “Heavy Oil and Natural Bitumen – Strategic 

Petroleum Resources,” Fact Sheet 70-03. 

517 EIA Form 814. 518 International Energy Agency (March 14, 2006), Oil Market Report: A Monthly Oil Market and Stocks 

Assessment, www.oilmarketreport.org. pp. 18.

519 Energy Information Administration, “Country Analysis Briefs,” Venezuela Oil. 

http://www.eia.doe.gov/emeu/cabs/Venezuela/Oil.html (last viewed 6/18/2008). 520 Canadian Association of Petroleum Producers (May 2008), Statistical Handbook for Canada’s Upstream
 

Petroleum Industry.

521 National Petroleum Council (2007), "Working Document of the NPC Global Oil & Gas Study" July 18, 2007,
 

Topic Paper #22 Heavy Oil; California Annual Reports of the State Oil & Gas Supervisor, 2006, 

http://www.conservation.ca.gov/dog/pubs_stats/annual_reports/Pages/annual_reports.aspx (last viewed 6/18/2008). 522 Energy Information Administration, 2005 data. 

http://tonto.eia.doe.gov/dnav/pet/pet_move_impcus_a2_nus_epc0_im0_mbbl_a.htm (last viewed 6/18/2008) 523 “N2O release from agro-biofuel production negates global warming reduction by replacing fossil fuels” P.J.
 

Crutzen, A.R. Mosier, K.A. Smith, and W. Winiwarter, Atmospheric Chemistry and Physics, 8, 389–395, 2008. 

524 U.S. Environmental Protection Agency. 2005. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–
 

2003. EPA 430-R-05-003. Available at http://www.epa.gov/climatechange/emissions/downloads06/05CR.pdf. 525 U.S. Environmental Protection Agency. 2005. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–
 

2003. EPA 430-R-05-003. Available at http://www.epa.gov/climatechange/emissions/downloads06/05CR.pdf. 526 U.S. Environmental Protection Agency. 2005. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–
 

2003. EPA 430-R-05-003. Available at http://www.epa.gov/climatechange/emissions/downloads06/05CR.pdf. 527 www.fao.org/ag/agl/fertistat/
 528 http://wds.iea.org/wds/default.aspx
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Emissions from Lime and Urea Applications

530 International Rice Research Institute. www.iri.org. Last accessed: October 15, 2008. 531 Ethanol Expansion in the United States How Will the Agricultural Sector Adjust? Paul C. Westcott, USDA ERS 

FDS-07D-01 May 2007. 

532 Technical Report, An Analysis of EPA Biofuel Scenarios with the CARD International Models, CARD Staff, 

October 2008. 

533 Salil Arora, May Wu, and Michael Wang, "Update of Distillers Grains Displacement Ratios for Corn Ethanol 

Life-Cycle Analysis," September 2008. See http://www.transportation.anl.gov/pdfs/AF/527.pdf
 534 The 2005 Food and Agriculture Organization (FAO) Global Forest Resources Assessment (FRA) is available at 

http://www.fao.org/forestry/fra2005/en/

535 https://www.gtap.agecon.purdue.edu
 536 See Hertel, Thomas, Steven Rose, Richard Tol (eds.), (in press). Economic Analysis of Land Use in Global
 

Climate Change Policy, Routledge Publishing. 537 USDA/FAO soil carbon map of the world is available for download at 

ftp://www.daac.ornl.gov/data/global_soil/IsricWiseGrids/State 538 Luyassert, S et al., 2008. Old-growth forests as global carbon sinks. Nature 455: 213-215. 

Link: http://www.nature.com/nature/journal/v455/n7210/abs/nature07276.html 

539 The digital soil carbon map of the world is available at 

ftp://www.daac.ornl.gov/data/global_soil/IsricWiseGrids/State 540 International Energy Outlook 2007, Report #:DOE/EIA-0484(2007), Release Date: May 2007, Tables G1 and 

G3. 

541 U.S. EPA 2008, Inventory of U.S. Greenhouse Gas Emissions and Sinks (EPA 430-R-08-005), Tables 3-23 

and3-24 http://www.epa.gov/climatechange/emissions/usinventoryreport.html 542 U.S. EPA 2008, Inventory of U.S. Greenhouse Gas Emissions and Sinks (EPA 430-R-08-005), Table ES-1 

http://www.epa.gov/climatechange/emissions/usinventoryreport.html

543 Overview Presentation to CRC on EPACT Testing (September 2008) 

544 U. S. EPA. 2007. Final Regulatory Impact Analysis: Control of Hazardous Air Pollutants from Mobile Sources; 

EPA420-R-07-002; Office of Transportation and Air Quality, Ann Arbor, MI. http://www.epa.gov/otaq/toxics.htm
 

795 
 

 

 

 

 

 

 

 

 

 

 

 

 

545 Reddy, Sam R. 2007. “A Model for Estimating Vapor Pressures of Commingled Ethanol Fuels.” SAE 2007-01­

4006. 

546 U. S. EPA. 2007. Regulatory Impact Analysis: Renewable Fuel Standard Program; EPA420-R-07-004; Office 

of Transportation and Air Quality, Ann Arbor, MI. http://www.epa.gov/otaq/renewablefuels/index.htm
 547 Overview Presentation to CRC on EPACT Testing (September 2008) 548 Haskew, Harold M., Thomas F. Liberty and Dennis McClement, “Fuel Permeation from Automotive Systems,” 

Final Report, for the Coordinating Research Council and the California Air Resources Board, CRC Project E-65, 

September 2004. Available in Docket EPA-HQ-OAR-2005-0161. 

549Southwest Research Institute. 2007. Flex Fuel Vehicles (FFVs) VOC/PM Cold Temperature Characterization
 

When Operating on Ethanol (E10, E70, E85). Prepared for U. S. Environmental Protection Agency. Available in 

Docket EPA-HQ-OAR-2005-0161. 

550 Environment Canada. 2007. Comparison of Emissions from Conventional and Flexible Fuel Vehicles 

Operating on Gasoline and E85 Fuels. ERM Report No. 05-039, Emissions Research Division. Available in Docket
 

EPA-HQ-OAR-2005-0161. 

551 EPA Certification and Fuel Economy Information System. http://www.epa.gov/otaq/cfeis.htm
 552 Southwest Research Institute. 2007. Flex Fuel Vehicles (FFVs) VOC/PM Cold Temperature Characterization
 

When Operating on Ethanol (E10, E70, E85). Prepared for U. S. Environmental Protection Agency. Available in 

Docket EPA-HQ-OAR-2005-0161. 

553 Graham, L. A.; Belisle, S. L. and C. Baas. 2008. Emissions from light duty gasoline vehicles operating on low 

blend ethanol gasoline and E85. Atmos. Environ. 42: 4498-4516. 

554 Environment Canada. 2007. Comparison of Emissions from Conventional and Flexible Fuel Vehicles Operating 

on Gasoline and E85 Fuels. ERM Report No. 05-039, Emissions Research Division. Available in Docket EPA-HQOAR-2005-0161. 

555 Auto/Oil Air Quality Improvement Research Program. 1996. Phase I and II Test Data. Prepared by Systems 

Applications International, Inc. 

556 U.S. EPA, 2007. Modeling of Ethanol Blend Effects on Nonroad Fuel Hose and Tank Permeation. 

Memorandum from Craig Harvey, U. S. EPA, March 26, 2007. 

557 U.S. EPA, 2008. Biodiesel Effects on Heavy-Duty Highway Engines and Vehicles; Office of Transportation and
 

Air Quality, Ann Arbor, MI. 

558 U.S. EPA 2002 A Comprehensive Analysis of Biodiesel Impacts on Exhaust Emissions: Draft Technical Report
 

(EPA420-P-02-001)

559 U.S. EPA, 2008. Development of MOVES Rates for HC, CO and NOx Exhaust Emissions from Light-duty
 

Vehicles for use in the RFS2 NRPM, Memorandum from James Warila, U. S. EPA, November 2008.

560 U.S. EPA. 2008. Kansas City Characterization Study: Final Report (EPA420-R-08-009) 

http://www.epa.gov/otaq/emission-factors-research/420r08009.pdf

561 U.S. EPA. 2008. Analysis of Particulate Matter Emissions from Light-Duty Vehicles in Kansas City (EPA420­

R-08-010) http://www.epa.gov/otaq/emission-factors-research/420r08010.pdf 562 U.S. EPA, 2008. Modeling Evaporative Emissions in MOVES for the RFS2 NPRM. Memorandum from 

Prashanth Gururaja, U.S. EPA, November 2008. 

563 U.S. EPA. 2002. Technical Description of the Toxics Module for MOBILE6.2 and Guidance on Its Use for 

Emission Inventory Preparation. (EPA420-R-02-029) http://www.epa.gov/otaq/models/mobile6/r02029.pdf 564 U.S. EPA, 2008. Using MOVES to Generate Inventories for the RFS2 NPRM, Memorandum from Amanda 

Valente and Megan Beardsley, November 2008. 

565 See http://www.epa.gov/ttn/chief/emch/index.html. 566 Final Rule: Control of Emissions of Air Pollution from Locomotives and Marine Compression-Ignition Engines 

Less Than 30 Liters per Cylinder (published May 6, 2008 and republished June 30, 2008). For details, see 

http://www.epa.gov/OMS/locomotv.htm#2008final 

567 Details about NMIM are available at http://www.epa.gov/otaq/nmim.htm. 568 Information about the 2005 NEI may be found at http://www.epa.gov/ttn/chief/net/2005inventory.html. 

569 Details concerning the Final Rule: Control of Emissions of Air Pollution from New Nonroad Spark-Ignition 

Engines, Equipment, and Vessels may be found at http://www.epa.gov/otaq/equip-ld.htm#. 

570 Sze, C., Whinihan, J., Olson, B., Schenk, C., Sobotowski, R. Impact of Test Cycle and Biodiesel Concentration 

of Emissions, SAE report 2007-01-4040 (2007). 

796
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

571 U. S. EPA. 2007. Final Regulatory Impact Analysis: Control of Hazardous Air Pollutants from Mobile Sources; 

EPA420-R-07-002; Office of Transportation and Air Quality, Ann Arbor, MI. http://www.epa.gov/otaq/toxics.htm
 572 Landman, L. C. (2007) Estimating Emissions Associated with Portable Fuel Containers (PFCs). U. S. EPA, 

Assessment and Standards Division, National Vehicle and Fuel Emissions Laboratory, Ann Arbor, MI, Report No.
 

EPA420-R-07-001. http://www.epa.gov/otaq/toxics.htm
 573 U. S. EPA. 2007. Regulatory Impact Analysis: Renewable Fuel Standard Program; EPA420-R-07-004; Office 

of Transportation and Air Quality, Ann Arbor, MI. http://www.epa.gov/otaq/renewablefuels/index.htm
 574 U. S. EPA. 1993. Final Regulatory Impact Analysis for Reformulated Gasoline. December 13, 1993. 

http://www.epa.gov/otaq/regs/fuels/rfg/

575 Haskew, H. M.; Liberty, T. F.; McClement, D. 2004. Fuel Permeation from Automotive Systems. Prepared for 

the Coordinating Research Council by Harold Haskew and Associates and Automotive Testing Laboratories, Inc. 

September 2004. CRC Project No. E-65. http://www.crcao.com. This document is available in Docket EPA-HQOAR-2005-0036. 

576 Hester, Charles. 2006. Review of Data on HAP Content in Gasoline. Memorandum from MACTEC to Steve 

Shedd, U. S. EPA, March 23, 2006. This document is available in Docket EPA-HQ-OAR-2003-0053. 577 U. S. EPA. 2006. Determination that Gasoline Distribution Stage 1 Area Source (GD AS) Category Does Not
 

Need to Be Regulated Under Section 112(c)6. Memoradum from Stephen Shedd to Kent Hustvedt, May 9, 2006.
 

This document is available in Docket EPA-HQ-OAR-2005-0036. 

578 U. S. EPA. SPECIATE Version 4.0. http://www.epa.gov/ttn/chief/software/speciate/index.html
 579 Haskew, H. M., Liberty, T. F., McClement, D. 2004. Fuel Permeation from Automotive Systems. Report No. 

CRC E-65, Prepared for California Air Resources Board and Coordinating Research Council. http://www.crcao.org/
 580 United States Department of Agriculture, Amber Waves, February 2004, page 9, U.S. Increasingly Imports
 

Nitrogen and Potash Fertilizer. http://www.ers.usda.gov/amberwaves/February04/
 581 Wen Huang, United States Department of Agriculture, Economic Research Service, personal communication to
 

Craig Harvey, US EPA, November 9, 2007.

582 40 CFR Part 63 National Emission Standards for Hazardous Air Pollutants for Source Categories: Gasoline 

Distribution Bulk Terminals, Bulk Plants, Pipeline Facilities, and Gasoline Dispensing Facilities; Proposed Rule, 

Thursday, November 9, 2006, 66064-66092. 

583 E. H. Pechan. Documentation For The Final 2002 Nonpoint Sector (Feb 06 Version) National Emission
 

Inventory For Criteria And Hazardous Air Pollutants, Appendix A, pp. A-89 to A-105. Prepared for Emissions 

Inventory and Analysis Group (C339-02) Air Quality Assessment Division Office of Air Quality Planning and
 

Standards U.S. Environmental Protection Agency Research Triangle Park, NC 27711, Report No. 

05.10.001/9014.401 Jul-06. Available at
 

ftp://ftp.epa.gov/EmisInventory/2002finalnei/documentation/nonpoint/2002nei_final_nonpoint_documentation0206
 

version.pdf. 

584 Energy Information Administration. 2007. Product Supplied, Petroleum Supply Reporting System. 

http://tonto.eia.doe.gov/dnav/pet/pet_cons_psup_dc_nus_mbbl_a.htm

585 EPA. 1994. Final Regulatory Impact Analysis: Refueling Emission Regulations for Light Duty Vehicles and
 

Trucks and Heavy Duty Vehicles. Office of Mobile Sources, Ann Arbor, MI. Available at
 

http://www.epa.gov/otaq/orvr.htm.

586 U. S. EPA. 2001. Final Rule: Control of Air Pollution From New Motor Vehicles: Heavy-Duty Engine and 

Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements, January 18, 2001. 

587 U. S. EPA. 2008. Final Rule: Control of Emissions of Air Pollution from Locomotives and Marine 

Compression-Ignition Engines Less than 30 Liters per Cylinder, Regulatory Impact Analysis, June 30, 2008. 

http://www.epa.gov/otaq/locomotv.htm

588 U.S. EPA. 2008. RFS2 Modified version of GREET1.7 Upstream Emissions Spreadsheet, October 31, 2008. 

589 Emission Inventories for Ocean-Going Vessels Using Category 3 Propulsion Engines In or Near the United
 

States, Draft Technical Support Document, EPA420-D-07-007, December 2007. This is available in Docket OAR2007-0121at http://www.regulations.gov/ . 

590 U. S. EPA. 2006. National-Scale Air Toxics Assessment for 1999. http://www.epa.gov/ttn/atw/nata1999. 591 U. S. EPA. 2007. Approach for Developing 2002 and Future Emission Summaries. Memorandum from
 

Madeleine Strum to Docket, November 26, 2007. This document is available in Docket EPA-HQ-OAR-2007-0491. 

592 Federal Register. 2007. National Emission Standards for Hazardous Air Pollutants From Petroleum Refineries. 

72(170): 50715-50742. http://www.epa.gov/EPA-AIR/2007/September/Day-04/a17009.htm. 

797 
 

 

 

 

 

 

 

 

 

 

 

 

 

593 Energy Information Administration. 2007. Product Supplied, Petroleum Supply Reporting System. 

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594 Brady, D. and Pratt, G. C. 2007. Volatile Organic Compound Emissions from Dry Mill Fuel Ethanol 

Production. J. Air & Waste Manage. Assoc. 57: 1091-1102. 

595 Prevention of Significant Deterioration Construction Permit Application. Prepared for Verasun Fort Dodge, 

LLC, Fort Dodge Iowa, by Barr, Minneapolis, MN, December, 2007. 

596 See Chapter 1.5 of the Draft Regulatory Impact Assessment of this rulemaking. 

597U. S. EPA. 2007. Control of Hazardous Air Pollutants from Mobile Sources; Final Rule. Federal Register, 72: 

8428-8570.
 598 U. S. EPA. 2007. Regulation of Fuels and Fuel Additives: Renewable Fuel Standard Program; Final Rule. 

Federal Register, 72: 23900-24014. 

599 U. S. EPA. 2007. Final Regulatory Impact Analysis: Control of Hazardous Air Pollutants from Mobile Sources; 

EPA420-R-07-002; Office of Transportation and Air Quality, Ann Arbor, MI. http://www.epa.gov/otaq/toxics.htm
 600 Energy Information Adminstration. 1999. Petroleum Marketing Annual. Report No. DOE/EIA-0487(99).
 

http://www.eia.doe.gov/pub/oil_gas/petroleum/data_publications/petroleum_marketing_annual/historical/1999/pma 

_1999.html 

601 Energy Information Administration. 2007. Annual Energy Outlook 2007 with Projections to 2030. U.S. 

Department of Energy, Report # DOE/EIA-0383. http://www.eia.doe.gov/oiaf/aeo/index.html 602 U. S. EPA. SPECIATE Version 4.0. http://www.epa.gov/ttn/chief/software/speciate/index.html 603 603 Auto/Oil Air Quality Improvement Research Program. 1996. Phase I and II Test Data. Prepared by Systems 

Applications International, Inc. 

604 Diesel Locomotives, Marine Distillate, Residual Boiler -- E. H. Pechan. 2005. Documentation For Aircraft, 

Commercial Marine Vessel, Locomotive, And Other Nonroad Components Of The National Emissions Inventory, 

Volume I - Methodology. 

Prepared for U. S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research 

Triangle Park, NC. http://www.epa.gov/ttn/chief/net/2002inventory.html 

605 HDD Trucks -- R. Cook, E. Glover. 2002. Technical Description of the Toxics Module for MOBILE6.2 and 

Guidance on Its Use for Emission Inventory Preparation. U. S. Environmental Protection Agency, Office of 

Transportation and Air Quality. Report No. EPA420-R-02-011. http://www.epa.gov/otaq/m6.htm 606 Natural Gas Turbines -- U. S. EPA. 2000. AP-42, 5th Edition, Volume 1. Chapter 3: Stationary Internal 

Combustion Sources. http://www.epa.gov/ttn/chief/ap42/ch03/index.html 607 Control of Hazardous Air Pollutants From Mobile Sources (72 FR 8428; February 26, 2007). 608 U.S. Environmental Protection Agency, Byun, D.W., Ching, J.K.S., Eds (1999) Science algorithms of EPA 

Models-3 Community Multiscale Air Quality (CMAQ modeling system, EPA/600/R-99/030, Office of Research and 

Development).

609 Byun, D.W., Schere, K.L. (2006) Review of the Governing Equations, Computational Algorithms, and Other 

Components of the Models-3 Community Multiscale Air Quality (CMAQ) Modeling System, J. Applied Mechanics 

Reviews 59 (2): 51-77. 

610 Dennis, R.L., Byun, D.W., Novak, J.H., Galluppi, K.J., Coats, C.J., Vouk, M.A. (1996) The next generation of 

integrated air quality modeling: EPA’s Models-3, Atmos Environ 30:1925-1938. 

611 US EPA (2007) Regulatory Impact Analysis of the Proposed Revisions to the National Ambient Air Quality 

Standards for Ground-Level Ozone. EPA document number 442/R-07-008, July 2007. 

612 Aiyyer, A, Cohan, D., Russell, A., Stockwell, W., Tanrikulu, S., Vizuete, W., Wilczak, J. (2007) Final Report: 

Third Peer Review of the CMAQ Model. p. 23.

613 Grell, G., J. Dudhia, D. Stauffer (1994) A Description of the Fifth-Generation Penn State/NCAR Mesoscale 

Model (MM5), NCAR/TN-398+STR., 138 pp, National Center for Atmospheric Research, Boulder CO.

614 final LocoMarine AQM TSD 615 U.S. Environmental Protection Agency, Byun, D.W., Ching, J.K.S., Eds (1999) Science algorithms of EPA 

Models-3 Community Multiscale Air Quality (CMAQ modeling system, EPA/600/R-99/030, Office of Research and 

Development). Please also see: http://www.cmascenter.org/ 616 Yantosca, B. (2004) GEOS-CHEMv7-01-02 User’s Guide, Atmospheric Chemistry Modeling Group, Harvard 

University, Cambridge, MA, October 15, 2004. 

617 Finlayson-Pitts BJ, Pitts JN Jr. (1986) Atmospheric Chemistry: Fundamentals and Experimental Techniques, 

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618 Atkinson R, Arey J (2003) Atmospheric Degradation of Volatile Organic Compounds. Chem Rev 103: 4605­

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619 Atkinson, R., Baulch, D.L., Cox, R.A., Crowley, J.N., Hampson, R.F. Jr., Hynes, R.G., Jenkin, M.E., Kerr, J.A., 

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Subcommittee on Gas Kinetic Data Evaluation for Atmospheric Chemistry. July 2005 web version. 

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Urban Particulate Air Pollution. J Air Waste Mgmt 55: 399-410. 

645 Zheng M, GR Cass, JJ Schauer, ES Edgerton (2002) Source Apportionment of PM2.5 in the Southeastern United 

States Using Solvent-Extractable Organic Compounds as Tracers. Environ Sci Technol 36: 2631-2371. 646 EPA (2002) National Air Quality and Emission Trends Report, 2001. EPA 454/K-02-001, September 2002. 

http://www.epa.gov/air/airtrends/aqtrnd01/summary.pdf 647 Schauer JJ, GR Cass (2000) Source Apportionment of Wintertime Gas-Phase and Particle-Phase Air Pollutants 

Using Organic Compounds as Tracers, Environ Sci Technol 34(9): 1821-1832. http://pubs.acs.org/cgibin/article.cgi/esthag/2000/34/i09/pdf/es981312t.pdf

648 Kleeman MJ, GR Cass (1999) Identifying the Effect of Individual Emission Sources on Particulate Air Quality 

Within a Photochemical Aerosol Processes Trajectory Model. Atmos Environ 33: 4597-4613. 

649 Watson J, Fujita E, Chow J, Zielinska B, Richards L, Neff W, Dietrich D (1998) Northern Front Range Air 

Quality Study Final Report: Volume 1. June 30, 1998. For Colorado State University, Cooperative Institute for 

Research in the Atmosphere, by Desert Research Institute, Reno, NV. This document is available in EPA Docket 

EPA-HQ-OAR-2005-0161. 

650 Schauer JJ, WF Rogge, LM Hildemann, MA Mazurek, GR Cass, B Simoneit (1996) Source Apportionment of 

Airborne Particulate Matter Using Organic Compounds as Tracers. Atmos Environ 30: 3837-3855. 

651 Lewandowski M, M Jaoui , JH Offenberg , TE Kleindienst, EO Edney, RJ Sheesley, JJ Schauer (2008) Primary 

and secondary contributions to ambient PM in the midwestern United States, Environ Sci Technol 42(9):3303-3309. 

http://pubs.acs.org/cgi-bin/article.cgi/esthag/2008/42/i09/html/es0720412.html 

652 Kleindienst TE, M Jaoui, M Lewandowski, JH Offenberg, EO Edney (2007) Estimates of the contributions of 

biogenic and anthropogenic hydrocarbons to secondary organic aerosol at a southeastern U.S. location, Atmos 

Environ 41(37):8288-8300. 

653 Offenberg JH, CW Lewis, M Lewandowski, M Jaoui, TE Kleindienst, EO Edney (2007) Contributions of 

Toluene and �-pinene to SOA Formed in an Irradiated Toluene/�-pinene,NOx/Air Mixture: Comparison of Results 

Using 14C Content and SOA Organic Tracer Methods, Environ Sci Technol 41: 3972-3976. 654 Byun DW, Schere, KL (2006) Review of the Governing Equations, Computational Algorithms, and Other 

Components of the Models-3 Community Multiscale Air Quality (CMAQ) Modeling System, J Applied Mechanics 

Reviews 59: 51-76. 

655 Pandis, S.N., Harley, R.A., Cass, G.R., Seinfeld, J.H. (1992) Secondary organic aerosol formation and transport. 

Atmos Environ 13, 2269–2282. 

656 H Takekawa, H Minoura, S Yamazaki (2003) Temperature dependence of secondary organic aerosol formation 

by photo-oxidation of hydrocarbons. Atmos Environ 37: 3413–3424. 

800
 
 

 

 

 

 

 

 

 

 

657 M J. Kleeman, Q Ying, Jin Lu, M J. Mysliwiec, R J. Griffin, Jianjun Chen, Simon Clegg (2007) Source 

apportionment of secondary organic aerosol during a severe photochemical smog episode. Atmos Environ 41: 576– 

591. 

658 Robinson, A. L.; Donahue, N. M.; Shrivastava, M.; Weitkamp, E. A.; Sage, A. M.; 

Grieshop, A. P.; Lane, T. E.; Pierce, J. R.; Pandis, S. N. (2007) Rethinking organic aerosol: 

Semivolatile emissions and photochemical aging. Science 315: 1259-1262. 

659 U. S. EPA (2002) National Air Quality and Emissions Trends Report, 2001. EPA 454/K-02-001, September 

2002. http://www.epa.gov/air/airtrends/aqtrnd01/summary.pdf 660 U. S. EPA (2006) National-Scale Air Toxics Assessment for 1999. http://www.epa.gov/ttn/atw/nata1999 661 U. S. EPA (2007) Regulatory Impact Analysis for the Control of Hazardous Air Pollutants from Mobile Sources 

Rule, Chapter 3, Air Quality and Resulting Health and Welfare Effects of Air Pollution from Mobile Sources. 72 FR 

8428, February 26, 2007. http://www.epa.gov/otaq/regs/toxics/420r07002.pdf 662 TE Kleindienst (2008) Hypothetical SOA Production from Ethanol Photooxidation. Memo to the Docket EPAHQ-OAR-2005-0161. 

663 BJ Turpin, JJ Huntzicker, SM Larson, GR Cass (1991) Los Angeles Summer Midday Particulate Carbon: 

Primary and Secondary Aerosol. Environ Sci Technol 25: 1788-1793. 

664 BJ Turpin, JJ Huntzicker (1995) Identification of Secondary Organic Aerosol Episodes and Quantitation of 

Primary and Secondary Organic Aerosol Concentrations During SCAQS. 

Atmos Environ 29(23): 3527-3544. 

665 Bae M-S, Schauer JJ, Turner JR (2006) Estimation of the Monthly Average Ratios of Organic Mass to Organic 

Carbon for Fine Particulate Matter at an Urban Site, Aerosol Sci Technol 40(12): 1123-1139. 

http://dx.doi.org/10.1080/02786820601004085. 666 Kleindienst TE, M Jaoui, M Lewandowski, JH Offenberg, EO Edney (2007) Estimates of the contributions of 

biogenic and anthropogenic hydrocarbons to secondary organic aerosol at a southeastern U.S. location. Atmos 

Environ 41(37):8288-8300. 

667 Offenberg JH, CW Lewis, M Lewandowski, M Jaoui, TE Kleindienst, EO Edney (2007) Contributions of 

Toluene and �-pinene to SOA Formed in an Irradiated Toluene/�-pinene,NOx/Air Mixture: Comparison of Results 

Using 14C Content and SOA Organic Tracer Methods, Environ Sci Technol 41: 3972-3976. 668 Claeys M, R Szmigielski, I Kourtchev, P Van der Veken, R Vermeylen, W Maenhaut, M Jaoui, TE Kleindienst, 

M Lewandowski, JH Offenberg, EO Edney (2007) Hydroxydicarboxylic acids: Markers for secondary organic 

aerosol from the photooxidation of �-pinene. Environ Sci Technol 41(5): 1628-1634.

669 Edney EO, TE Kleindienst, M Jaoui, M Lewandowski, JH Offenberg, W Wang, M Claeys (2005) Formation of 

2-methyl tetrols and 2-methylglyceric acid in secondary organic aerosol from laboratory irradiated 

isoprene/NOX/SO2/air mixtures and their detection in ambient PM2.5 samples collected in the Eastern United States. 

Atmos Environ 39: 5281-5289. 

670 Jaoui M, TE Kleindienst, M Lewandowski, JH Offenberg, EO Edney (2005) Identification and quantification of 

aerosol polar oxygenated compounds bearing carboxylic or hydroxyl groups. 2. Organic tracer compounds from 

monoterpenes. Environ Sci Technol 39: 5661-5673. 

671 Kleindienst TE, TS Conver, CD McIver, EO Edney (2004) Determination of secondary organic aerosol products 

from the photooxidation of toluene and their implications in ambient PM2.5. J Atmos Chem 47: 70-100. 672 Kleindienst TE, TS Conver, CD McIver, EO Edney (2004) Determination of secondary organic aerosol products 

from the photooxidation of toluene and their implication in ambient PM2.5, J Atmos Chem 47: 70-100. 673 Izumi L, T Fukuyama (1990) Photochemical aerosol formation from aromatic hydrocarbons in the presence of 

NOx, Atmos Environ 24A: 1433. 674 Martin-Reviego M, K Wirtz (2005) Is benzene a precursor for secondary organic aerosol? Environ Sci Technol 

39: 1045-1054. 675 Lewandowski M, M Jaoui , JH Offenberg , TE Kleindienst, EO Edney, RJ Sheesley, JJ Schauer (2008) Primary 

and secondary contributions to ambient PM in the midwestern United States, Environ Sci Technol 42(9):3303-3309. 

http://pubs.acs.org/cgi-bin/article.cgi/esthag/2008/42/i09/html/es0720412.html. 676 Kleindienst TE, M Jaoui, M Lewandowski, JH Offenberg, EO Edney (2007) Estimates of the contributions of
 

biogenic and anthropogenic hydrocarbons to secondary organic aerosol at a southeastern U.S. location. Atmos 

Environ 41(37):8288-8300. 

677 Henze DK, JH Seinfeld (2006) Global secondary organic aerosol from isoprene oxidation. Geophys Res Lett 33: 

L09812. doi:10.1029/2006GL025976. 

801 
 

 

 

 

678 Jaoui M, M Lewandowski, TE Kleindienst, JH Offenberg, EO Edney (2007) β -Caryophyllinic acid: An
 

atmospheric tracer for β-caryophyllene secondary organic aerosol. Geophys Res Lett 34: L05816. 

doi:10.1029/2006GL028827. 

679 Griffin RJ, DR Cocker III, RC Flagan, JH Seinfeld (1999) Organic aerosol formation from oxidation of biogenic 

hydrocarbons, J Geophys Res 104: 3555-3567. 

680 Ng NL, JH Kroll, AWH Chan, PS Chabra, RC Flagan, JH Seinfeld (2007) Secondary organic aerosol formation
 

from m-xylene, toluene, and benzene. Atmos Chem Phys 7: 3909-3922. 

681 U.S. EPA (2004) Air Quality Criteria for Particulate Matter (Oct 2004), Volume I Document No. EPA600/P-99/002aF and Volume II Document No. EPA600/P-99/002bF. 

This document is available in Docket EPA-HQ-OAR-2005-0161. 

682 U.S. EPA (2005) Review of the National Ambient Air Quality Standard for Particulate Matter: Policy Assessment of Scientific and Technical Information, OAQPS Staff 

Paper. EPA-452/R-05-005. This document is available in Docket EPA-HQ-OAR-2005-0161.
 683 U.S. EPA 2006. Provisional Assessment of Recent Studies on Health Effects of Particulate Matter Exposure. EPA/600/R-06/063. This document is available 

in Docket EPA-HQ-OAR-2005-0161.

684 Laden F; Neas LM; Dockery DW; et al. 2000. “Association of fine particulate matter from different sources with daily mortality in six U.S. cities.” Environ Health 

Perspectives 108(10):941-947. 

685 Schwartz J; Laden F; Zanobetti A. 2002. “The concentration-response relation between PM(2.5) and daily deaths.” Environ Health Perspect 110(10): 1025-1029. 

686 Janssen NA; Schwartz J; Zanobetti A.; et al. 2002. “Air conditioning and source-specific particles as modifiers of the effect of PM10 on hospital admissions for heart and lung 

disease.” Environ Health Perspect 110(1):43-49. 

687 Dockery, DW; Pope, CA, III; Xu, X; et al. 1993. “An association between air pollution and mortality in six U.S. cities.” N Engl J Med 329:1753-1759. 

688 Pope, CA, III; Burnett, RT; Thun, MJ; Calle, EE; et al. 2002. “Lung cancer, cardiopulmonary mortality, and long-term exposure to fine particulate air pollution.” J Am Med 

Assoc 287: 1132-1141.
 

689 Krewski, D; Burnett, RT; Goldberg, M S; et al. 2000. “Reanalysis of the Harvard Six Cities study and the American Cancer Society study of particulate air pollution and 

mortality. A special report of the Institute's Particle Epidemiology Reanalysis Project.” Cambridge, MA: Health Effects Institute. 

690 Jerrett, M; Burnett, RT; Ma, R; et al. 2005. “Spatial Analysis of Air Pollution and Mortality in Los Angeles.” Epidemiology. 16(6):727-736. 

691 Künzli, N.; Jerrett, M.; Mack, W.J.; et al.(2004) Ambient air pollution and atherosclerosis in Los Angeles. Environ Health Perspect doi:10.1289/ehp.7523 [Available at 

http://dx.doi.org/]. 

692 Riediker, M.; Cascio, W.E.; Griggs, T.R.; et al. 2004. "Particulate matter exposure in cars is associated with 

cardiovascular effects in healthy young men." Am J Respir Crit Care Med 169: 934-940.
 693 Maynard, D.; Coull, B.A.; Gryparis, A.; Schwartz, J. (2007) Mortality risk associated with short-term exposure to
 

traffic particles and sulfates. Environmental Health Perspectives 115: 751-755. 

694 Ryan, P.H.; LeMasters, G.K.; Biswas, P.; Levin, L.; Hu, S.; Lindsey, M.; Bernstein, D.I.; Lockey, J.; Villareal, 

M.; Khurana Hershey, G.K.; Grinshpun, S.A. (2007) A comparison of proximity and land use regression traffic 

exposure models and wheezing in infants. Environ Health Perspect 115: 278-84. 

695 Morgenstern, V.; Zutavern, A.; Cyrys, J.; Brockow, I.; Gehring, U.; Koletzko, S.; Bauer, C.P.; Reinhart, D; 

Wichmann, H-E.; Heinrich, J. (2007) Respiratory health and individual estimated expousure to traffic-related air 

pollutant in a cohort of young children. Occupational and Environmental Medicine 64: 8-16. 

696 Franco Suglia, S.; Gryparis, A.; Wright, R.O.; Schwartz, J.; Wright, R.J. (2007) Association of black carbon with
 

cognition among children in a prospective birth cohort study. American Journal of Epidemiology 167: 280-286.
 697 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document 

is contained in Docket EPA-HQ-OAR-2005-0161. 

698 U.S. EPA, Review of the National Ambient Air Quality Standards for Ozone: Policy Assessment of Scientific and Technical Information, OAQPS Staff Paper, Washington, 

DC, EPA-452/R-07-003, January 2007. This document is available in Docket EPA-HQ-OAR-2005-0161.
 699 National Research Council (NRC), 2008. Estimating Mortality Risk Reduction and Economic Benefits from
 

Controlling Ozone Air Pollution. The National Academies Press: Washington, D.C.

700 Bates, D.V.; Baker-Anderson, M.; Sizto, R. (1990) Asthma attack periodicity: a study of hospital emergency visits in Vancouver. Environ. Res. 51: 51-70. 

701 Thurston, G.D.; Ito, K.; Kinney, P.L.; Lippmann, M. (1992) A multi-year study of air pollution and respiratory hospital admissions in three New York State metropolitan 

areas: results for 1988 and 1989 summers. J. Exposure Anal. Environ. Epidemiol. 2:429-450. 

702 Thurston, G.D.; Ito, K.; Hayes, C.G.; Bates, D.V.; Lippmann, M. (1994) Respiratory hospital admissions and summertime haze air pollution in Toronto, Ontario: 

consideration of the role of acid aerosols. Environ. Res. 65: 271-290. 

703 Lipfert, F.W.; Hammerstrom, T. (1992) Temporal patterns in air pollution and hospital admissions. Environ. Res. 59: 374-399. 

704 Burnett, R.T.; Dales, R.E.; Raizenne, M.E.; Krewski, D.; Summers, P.W.; Roberts, G.R.; Raad-Young, M.; Dann,T.; Brook, J. (1994) Effects of low ambient levels of ozone 

and sulfates on the frequency of respiratory admissions to Ontario hospitals. Environ. Res. 65: 172-194. 

705 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document 

is contained in Docket EPA-HQ-OAR-2005-0161. 

802
 
 

 

 

 

706 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document 

is contained in Docket EPA-HQ-OAR-2005-0161.

707 Devlin, R. B.; McDonnell, W. F.; Mann, R.; Becker, S.; House, D. E.; Schreinemachers, D.; Koren, H. S. (1991) Exposure of humans to ambient levels of ozone for 6.6 hours 

causes cellullar and biochemical changes in the lung. Am. J. Respir. Cell Mol. Biol. 4: 72-81. 

708 Koren, H. S.; Devlin, R. B.; Becker, S.; Perez, R.; McDonnell, W. F. (1991) Time-dependent changes of markers associated with inflammation in the lungs of humans 

exposed to ambient levels of ozone. Toxicol. Pathol. 19: 406-411. 

709 Koren, H. S.; Devlin, R. B.; Graham, D. E.; Mann, R.; McGee, M. P.; Horstman, D. H.; Kozumbo, W. J.; Becker, S.; House, D. E.; McDonnell, W. F.; Bromberg, P. A. 

(1989a) Ozone-induced inflammation in the lower airways of human subjects. Am. Rev. Respir. Dis. 139: 407-415. 

710 Schelegle, E.S.; Siefkin, A.D.; McDonald, R.J. (1991) Time course of ozone-induced neutrophilia in normal humans. Am. Rev. Respir. Dis. 143:1353-1358. 

711 U.S. EPA (1996). Air Quality Criteria for Ozone and Related Photochemical Oxidants, EPA600-P-93-004aF; (See page 7-171). This document is contained 

in Docket EPA-HQ-OAR-2005-0161. 

712 Hodgkin, J.E.; Abbey, D.E.; Euler, G.L.; Magie, A.R. (1984) COPD prevalence in nonsmokers in high and low photochemical air pollution areas. Chest 86: 830-838. 

713 Euler, G.L.; Abbey, D.E.; Hodgkin, J.E.; Magie, A.R. (1988) Chronic obstructive pulmonary disease symptom effects of long-term cumulative exposure to ambient levels of
 

total oxidants and nitrogen dioxide in California Seventh-day Adventist residents. Arch. Environ. Health 43: 279-285. 

714 Abbey, D.E.; Petersen, F.; Mills, P.K.; Beeson, W.L. (1993) Long-term ambient concentrations of total suspended particulates, ozone, and sulfur dioxide and respiratory
 

symptoms in a nonsmoking population. Arch. Environ. Health 48: 33-46. 

715 U.S. EPA, Review of the National Ambient Air Quality Standards for Ozone: Policy Assessment of Scientific and Technical Information, OAQPS Staff Paper, Washington, 

DC, EPA-452/R-07-003, January 2007. This document is available in Docket EPA-HQ-OAR-2005-0161.
 716 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document 

is contained in Docket EPA-HQ-OAR-2005-0161. 

717 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document 

is contained in Docket EPA-HQ-OAR-2005-0161.

718 Avol, E. L.; Trim, S. C.; Little, D. E.; Spier, C. E.; Smith, M. N.; Peng, R.-C.; Linn, W. S.; Hackney, J. D.; Gross, K. B.; D'Arcy, J. B.; Gibbons, D.; Higgins, I. T. T. (1990)
 

Ozone exposure and lung function in children attending a southern California summer camp. Presented at: 83rd annual meeting and exhibition of the Air & Waste Management 

Association; June; Pittsburgh, PA. Pittsburgh, PA: Air & Waste Management Association; paper no. 90-150.3. 

719 Higgins, I. T. T.; D'Arcy, J. B.; Gibbons, D. I.; Avol, E. L.; Gross, K. B. (1990) Effect of exposures to ambient ozone on ventilatory lung function in children. Am. Rev. 

Respir. Dis. 141: 1136-1146. 

720 Raizenne, M. E.; Burnett, R. T.; Stern, B.; Franklin, C. A.; Spengler, J. D. (1989) Acute lung function responses to ambient acid aerosol exposures in children. Environ. Health 

Perspect. 79: 179-185.
 

721 Raizenne, M.; Stern, B.; Burnett, R.; Spengler, J. (1987) Acute respiratory function and transported air pollutants: observational studies. Presented at: 80th annual meeting of
 

the Air Pollution Control Association; June; New York, NY. Pittsburgh, PA: Air Pollution Control Association; paper no. 87-32.6. 

722 Spektor, D. M.; Lippmann, M. (1991) Health effects of ambient ozone on healthy children at a summer camp. In: Berglund, R. L.; Lawson, D. R.; McKee, D. J., eds. 

Tropospheric ozone and the environment: papers from an international conference; March 1990; Los Angeles, CA. Pittsburgh, PA: Air & Waste Management Association; pp. 83­

89. (A&WMA transaction series no. TR-19).
 

723 Spektor, D. M.; Thurston, G. D.; Mao, J.; He, D.; Hayes, C.; Lippmann, M. (1991) Effects of single- and multiday ozone exposures on respiratory function in active normal 

children. Environ. Res. 55: 107-122. 

724 Spektor, D. M.; Lippman, M.; Lioy, P. J.; Thurston, G. D.; Citak, K.; James, D. J.; Bock, N.; Speizer, F. E.; Hayes, C. (1988a) Effects of ambient ozone on respiratory
 

function in active, normal children. Am. Rev. Respir. Dis. 137: 313-320. 

725 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document 

is contained in Docket EPA-HQ-OAR-2005-0161. 

726 Hazucha, M. J.; Folinsbee, L. J.; Seal, E., Jr. (1992) Effects of steady-state and variable ozone concentration profiles on pulmonary function. Am. Rev. Respir. Dis. 146: 1487­

1493. 

727 Horstman, D.H.; Ball, B.A.; Folinsbee, L.J.; Brown, J.; Gerrity, T. (1995) Comparison of pulmonary responses of asthmatic and nonasthmatic subjects performing light 

exercise while exposed to a low level of ozone. Toxicol. Ind. Health.
 

728 Horstman, D.H.; Folinsbee, L.J.; Ives, P.J.; Abdul-Salaam, S.; McDonnell, W.F. (1990) Ozone concentration and pulmonary response relationships for 6.6-hour exposures 

with five hours of moderate exercise to 0.08, 0.10, and 0.12 ppm. Am. Rev. Respir. Dis. 142: 1158-1163. 

729 U.S. EPA (2000). Air Quality Criteria for Carbon Monoxide. EPA600-P-99-001F. June 1, 2000. U.S. 

Environmental Protection Agency, Office of Research and Development, National Center for Environmental
 

Assessment, Washington, D.C. This document is available online at http://www.epa.gov/ncea/pdfs/coaqcd.pdf. A 

copy of this document is available in Docket EPA-HQ-OAR-2005-0161. 

730 U.S. EPA (2000). Air Quality Criteria for Carbon Monoxide. EPA600-P-99-001F. June 1, 2000. U.S. 

Environmental Protection Agency, Office of Research and Development, National Center for Environmental
 

Assessment, Washington, D.C. This document is available online at http://www.epa.gov/ncea/pdfs/coaqcd.pdf. A 

copy of this document is available in Docket EPA-HQ-OAR-2005-0161. 

731 Coburn, R.F. (1979) Mechanisms of carbon monoxide toxicity. Prev. Med. 8:310-322. 

803 
 

 

 

 

 

 

 

 

 

732 Helfaer, M.A., and Traystman, R.J. (1996) Cerebrovascular effects of carbon monoxide. In: Carbon Monoxide 

(Penney, D.G., ed). Boca Raton, CRC Press, 69-86.
 733 Benignus, V.A. (1994) Behavioral effects of carbon monoxide: meta analyses and extrapolations. J. Appl. 

Physiol. 76:1310-1316. 

734 U.S. EPA (2000). Air Quality Criteria for Carbon Monoxide. EPA600-P-99-001F. June 1, 2000. U.S. 

Environmental Protection Agency, Office of Research and Development, National Center for Environmental
 

Assessment, Washington, D.C. This document is available online at http://www.epa.gov/ncea/pdfs/coaqcd.pdf. A 

copy of this document is available in Docket EPA-HQ-OAR-2005-0161. 

735 U.S. EPA (2000). Air Quality Criteria for Carbon Monoxide. EPA600-P-99-001F. June 1, 2000. U.S. 

Environmental Protection Agency, Office of Research and Development, National Center for Environmental
 

Assessment, Washington, D.C. This document is available online at http://www.epa.gov/ncea/pdfs/coaqcd.pdf. A 

copy of this document is available in Docket EPA-HQ-OAR-2005-0161. 

736 U.S. EPA (2000). Air Quality Criteria for Carbon Monoxide. EPA600-P-99-001F. June 1, 2000. U.S. 

Environmental Protection Agency, Office of Research and Development, National Center for Environmental
 

Assessment, Washington, D.C. This document is available online at http://www.epa.gov/ncea/pdfs/coaqcd.pdf. A 

copy of this document is available in Docket EPA-HQ-OAR-2005-0161. 

737 U.S. EPA (2000). Air Quality Criteria for Carbon Monoxide. EPA600-P-99-001F. June 1, 2000. U.S. 

Environmental Protection Agency, Office of Research and Development, National Center for Environmental
 

Assessment, Washington, D.C. This document is available online at http://www.epa.gov/ncea/pdfs/coaqcd.pdf. A 

copy of this document is available in Docket EPA-HQ-OAR-2005-0161. 

738 National Research Council, 1993. Protecting Visibility in National Parks and Wilderness Areas. National Academy of Sciences Committee on Haze in National Parks and 

Wilderness Areas. National Academy Press, Washington, DC. This book is available electronically at http://www.nap.edu/books/0309048443/html/ and is available in Docket 

EPA-HQ-OAR-2005-0161. 

739 U.S. EPA , National Ambient Air Quality Standards for Particulate Matter; Proposed Rule; January 17, 2006, Vol71 p 2676. This document is available in 

Docket EPA-HQ-OAR-2005-0161. This information is available electronically at:

 http://epa.gov/fedrgstr/EPA-AIR/2006/January/Day-17/a177.pdf 

740 U.S. EPA (2004) Air Quality Criteria for Particulate Matter (Oct 2004), Volume I Document No. EPA600/P-99/002aF and Volume II Document No. EPA600/P-99/002bF. 

This document is available in Docket EPA-HQ-OAR-2005-0161. 

741 U.S. EPA (2005) Review of the National Ambient Air Quality Standard for Particulate Matter: Policy Assessment of Scientific and Technical Information, OAQPS Staff 

Paper. EPA-452/R-05-005. This document is available in Docket EPA-HQ-OAR-2005-0161. 742 U.S. EPA, 2008. Integrated Science Assessment for Oxides of Nitrogen and Sulfur- Ecological Criteria (Final). U.S. EPA, Washington D.C., EPA/600/R-08/082F. 

743 Environmental Protection Agency (2003). Response Of Surface Water Chemistry to the Clean Air Act 

Amendments of 1990. National Health and Environmental Effects Research Laboratory, Office of Research and 

Development, U.S. Environmental Protection Agency. Research Triangle Park, NC. EPA 620/R–03/001. 744 Fenn, M.E. and Blubaugh, T.J. (2005) Winter Deposition of Nitrogen and Sulfur in the Eastern Columbia River 

Gorge National Scenic Area, USDA Forest Service. 745 Galloway, J. N.; Cowling, E. B. (2002). Reactive nitrogen and the world: 200 years of change. Ambio 31: 64–71. 

746 Bricker, Suzanne B., et al., National Estuarine Eutrophication Assessment, Effects of Nutrient Enrichment in the Nation’s Estuaries, National Ocean Service, National Oceanic 

and Atmospheric Administration, September, 1999. 

747 Winner, W.E., and C.J. Atkinson. 1986. “Absorption of air pollution by plants, and consequences for growth.” Trends in Ecology and Evolution 1:15-18. 

748 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document 

is contained in Docket EPA-HQ-OAR-2005-0161. 

749 Tingey, D.T., and Taylor, G.E. 1982. “Variation in plant response to ozone: a conceptual model of physiological events.” In: Effects of Gaseous Air Pollution in Agriculture 

and Horticulture (Unsworth, M.H., Omrod, D.P., eds.) London, UK: Butterworth Scientific, pp.113-138. 

750 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document 

is contained in Docket EPA-HQ-OAR-2005-0161.

751 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document 

is contained in Docket EPA-HQ-OAR-2005-0161. 

752 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document 

is contained in Docket EPA-HQ-OAR-2005-0161. 

753 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document 

is contained in Docket EPA-HQ-OAR-2005-0161. 

754 Ollinger, S.V., J.D. Aber and P.B. Reich. 1997. “Simulating ozone effects on forest productivity: interactions between leaf canopy and stand level processes.” Ecological 

Applications 7:1237-1251. 

804
 
 

 

 

 

 

 

755 Winner, W.E., 1994. “Mechanistic analysis of plant responses to air pollution.” Ecological Applications, 4(4):651-661. 

756 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document
 

is contained in Docket EPA-HQ-OAR-2005-0161. 

757 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document 

is contained in Docket EPA-HQ-OAR-2005-0161.

758 Fox, S., and R. A. Mickler, eds. 1996. Impact of Air Pollutants on Southern Pine Forests. Springer-Verlag, NY, Ecol. Studies, Vol. 118, 513 pp. 

759 De Steiguer, J., J. Pye, C. Love. 1990. “Air Pollution Damage to U.S. Forests.” Journal of Forestry, Vol 88 (8) pp. 17-22.
 

760 Pye, J.M. 1988. “Impact of ozone on the growth and yield of trees: A review.” Journal of Environmental Quality 17 pp.347-360. 

761 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document
 

is contained in Docket EPA-HQ-OAR-2005-0161.

762 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document 

is contained in Docket EPA-HQ-OAR-2005-0161. 

763 McBride, J.R., P.R. Miller, and R.D. Laven. 1985. “Effects of oxidant air pollutants on forest succession in the mixed conifer forest type of southern California.” In: Air 

Pollutants Effects On Forest Ecosystems, Symposium Proceedings, St. P, 1985, p. 157-167. 

764 Miller, P.R., O.C. Taylor, R.G. Wilhour. 1982. Oxidant air pollution effects on a western coniferous forest ecosystem. Corvallis, OR: U.S. Environmental Protection Agency, 

Environmental Research Laboratory (EPA600-D-82-276). 

765 U.S. EPA. Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. EPA, Washington, DC, EPA/600/R-05/004aF-cF, 2006. This document
 

is contained in Docket EPA-HQ-OAR-2005-0161. 

766 Kopp, R. J.; Vaughn, W. J.; Hazilla, M.; Carson, R. 1985. “Implications of environmental policy for U.S. agriculture: the case of ambient ozone standards.” J. Environ. 

Manage. 20:321-331. 

767 Adams, R. M.; Hamilton, S. A.; McCarl, B. A. 1986. “The benefits of pollution control: the case of ozone and U.S. agriculture.” Am. J. Agric. Econ. 34: 3-19. 

768 Adams, R. M.; Glyer, J. D.; Johnson, S. L.; McCarl, B. A. 1989. “A reassessment of the economic effects of ozone on U.S. agriculture.” JAPCA 39:960-968.
 

769 Abt Associates, Inc. 1995. Urban ornamental plants: sensitivity to ozone and potential economic losses. U.S. EPA, Office of Air Quality Planning and Standards, Research
 

Triangle Park. Under contract to RADIAN Corporation, contract no. 68-D3-0033, WA no. 6. pp. 9-10. 

770 U. S. EPA. 1999 National-Scale Air Toxics Assessment. http://www.epa.gov/ttn/atw/nata1999/risksum.html
 771 U.S. EPA (2007) Control of Hazardous Air Pollutants from Mobile Sources. 72 FR 8428; February 26, 2007. 772 U.S. EPA (2003) Integrated Risk Information System File of Acrolein. National Center for Environmental 

Assessment, Office of Research and Development, Washington, D.C. 2003. This material is available electronically 

at http://www.epa.gov/iris/subst/0364.htm.

773 U.S. EPA (2006) National-Scale Air Toxics Assessment for 1999. This material is available electronically at 

http://www.epa.gov/ttn/atw/nata1999/risksum.html. 

774 U.S. EPA (2006) National-Scale Air Toxics Assessment for 1999. http://www.epa.gov/ttn/atw/nata1999. 775 U.S. EPA 2000. Integrated Risk Information System File for Benzene. This material is available electronically at:

 http://www.epa.gov/iris/subst/0276.htm . . 776 International Agency for Research on Cancer, IARC monographs on the evaluation of carcinogenic risk of chemicals to humans, Volume 29, Some industrial chemicals and 

dyestuffs, International Agency for Research on Cancer, World Health Organization, Lyon, France, p. 345-389, 1982. 

777 Irons, R.D.; Stillman, W.S.; Colagiovanni, D.B.; Henry, V.A. (1992) Synergistic action of the benzene metabolite hydroquinone on myelopoietic stimulating activity of
 

granulocyte/macrophage colony-stimulating factor in vitro, Proc. Natl. Acad. Sci. 89:3691-3695. 

778 International Agency for Research on Cancer (IARC)

. 1987. Monographs on the evaluation of carcinogenic risk of chemicals to humans, Volume 29, Supplement
 

7, Some industrial chemicals and dyestuffs, World Health Organization, Lyon, France.
 

779 U.S. Department of Health and Human Services National Toxicology Program 11th Report on Carcinogens 

available at: http://ntp.niehs.nih.gov/go/16183. 

780 Aksoy, M. (1989). Hematotoxicity and carcinogenicity of benzene. Environ. Health Perspect. 82: 193-197. 

781 Goldstein, B.D. (1988). Benzene toxicity. Occupational medicine. State of the Art Reviews. 3: 541-554. 

782 Rothman, N., G.L. Li, M. Dosemeci, W.E. Bechtold, G.E. Marti, Y.Z. Wang, M. Linet, L.Q. Xi, W. Lu, M.T. Smith, N. Titenko-Holland, L.P. Zhang, W. Blot, S.N. Yin, and
 

R.B. Hayes (1996) Hematotoxicity among Chinese workers heavily exposed to benzene. Am. J. Ind. Med. 29: 236-246. 

783 U.S. EPA 2002 Toxicological Review of Benzene (Noncancer Effects). Environmental Protection Agency, 

Integrated Risk Information System (IRIS), Research and Development, National Center for Environmental 

Assessment, Washington DC. This material is available electronically at http://www.epa.gov/iris/subst/0276.htm. 784 Qu, O.; Shore, R.; Li, G.; Jin, X.; Chen, C.L.; Cohen, B.; Melikian, A.; Eastmond, D.; Rappaport, S.; Li, H.; Rupa, D.; Suramaya, R.; Songnian, W.; Huifant, Y.; Meng, M.; 

Winnik, M.; Kwok, E.; Li, Y.; Mu, R.; Xu, B.; Zhang, X.; Li, K. (2003). HEI Report 115, Validation & Evaluation of Biomarkers in Workers Exposed to Benzene in China. 

785 Qu, Q., R. Shore, G. Li, X. Jin, L.C. Chen, B. Cohen, et al. (2002). Hematological changes among Chinese workers with a broad range of benzene exposures. Am. J. Industr. 

Med. 42: 275-285. 

786 Lan, Qing, Zhang, L., Li, G., Vermeulen, R., et al. (2004). Hematotoxically in Workers Exposed to Low Levels of Benzene. Science 306: 1774-1776. 

787 Turtletaub, K.W. and Mani, C. (2003). Benzene metabolism in rodents at doses relevant to human exposure from Urban Air. Research Reports Health Effect Inst. Report 

No.113. 

805 
 

 

 

 

 

788 U.S. EPA. 2002. Health Assessment of 1,3-Butadiene. Office of Research and Development, National Center for Environmental Assessment, Washington Office, 

Washington, DC. Report No. EPA600-P-98-001F. This document is available electronically at http://www.epa.gov/iris/supdocs/butasup.pdf.

789 U.S. EPA. 2002 “Full IRIS Summary for 1,3-butadiene (CASRN 106-99-0)” Environmental Protection Agency, 

Integrated Risk Information System (IRIS), Research and Development, National Center for Environmental
 

Assessment, Washington, DC http://www.epa.gov/iris/subst/0139.htm.
 790 International Agency for Research on Cancer (IARC) (1999)

 Monographs on the evaluation of carcinogenic risk of chemicals to humans, Volume 71, Reevaluation of some organic chemicals, hydrazine and hydrogen peroxide and Volume 97 (in preparation), World Health 

Organization, Lyon, France. 

791 U.S. Department of Health and Human Services National Toxicology Program 11th Report on Carcinogens 

available at: http://ntp.niehs.nih.gov/go/16183. 

792 Bevan, C.; Stadler, J.C.; Elliot, G.S.; et al. (1996) Subchronic toxicity of 4-vinylcyclohexene in rats and mice by inhalation. Fundam. Appl. Toxicol. 32:1-10. 

793 U.S. EPA 1987. Assessment of Health Risks to Garment Workers and Certain Home Residents from Exposure to Formaldehyde, Office of Pesticides and Toxic Substances, 

. April 1987. 

794 Hauptmann, M..; Lubin, J. H.; Stewart, P. A.; Hayes, R. B.; Blair, A. 2003. Mortality from lymphohematopoetic malignancies among workers in formaldehyde industries. 

Journal of the National Cancer Institute 95: 1615-1623. 

795 Hauptmann, M..; Lubin, J. H.; Stewart, P. A.; Hayes, R. B.; Blair, A. 2004. Mortality from solid cancers among workers in formaldehyde industries. American Journal of 

Epidemiology 159: 1117-1130. 

796 Pinkerton, L. E. 2004. Mortality among a cohort of garment workers exposed to formaldehyde: an update. Occup. Environ. Med. 61: 193-200. 

797 Coggon, D, EC Harris, J Poole, KT Palmer. 2003. Extended follow-up of a cohort of British chemical workers 

exposed to formaldehyde. J National Cancer Inst. 95:1608-1615.

798 Conolly, RB, JS Kimbell, D Janszen, PM Schlosser, D Kalisak, J Preston, and FJ Miller. 2003. Biologically motivated computational modeling of formaldehyde 

carcinogenicity in the F344 rat. Tox Sci 75: 432-447. 

799 Conolly, RB, JS Kimbell, D Janszen, PM Schlosser, D Kalisak, J Preston, and FJ Miller. 2004. Human respiratory tract cancer risks of inhaled formaldehyde: Dose-response 

predictions derived from biologically-motivated computational modeling of a combined rodent and human dataset. Tox Sci 82: 279-296. 

800 Chemical Industry Institute of Toxicology (CIIT).1999. Formaldehyde: Hazard characterization and dose-response assessment for carcinogenicity by the route of inhalation. 

CIIT, September 28, 1999. Research Triangle Park, NC. 

801 International Agency for Research on Cancer (2006) Formaldehyde, 2-Butoxyethanol and 1-tert-Butoxypropan2-ol. Monographs Volume 88. World Health Organization, Lyon, France. 

802 Agency for Toxic Substances and Disease Registry (ATSDR). 1999. Toxicological profile for Formaldehyde. 

Atlanta, GA: U.S. Department of Health and Human Services, Public Health Service. 

http://www.atsdr.cdc.gov/toxprofiles/tp111.html 803 WHO (2002) Concise International Chemical Assessment Document 40: Formaldehyde. Published under the 

joint sponsorship of the United Nations Environment Programme, the International Labour Organization, and the 

World Health Organization, and produced within the framework of the Inter-Organization Programme for the Sound 

Management of Chemicals. Geneva. 

804 U.S. EPA (1988). Integrated Risk Information System File of Acetaldehyde. Research and Development, National Center for 

Environmental Assessment, Washington, DC. This material is available electronically at http://www.epa.gov/iris/subst/0290.htm. 

805 U.S. Department of Health and Human Services National Toxicology Program 11th Report on Carcinogens 

available at: http://ntp.niehs.nih.gov/go/16183. 

806 International Agency for Research on Cancer (IARC). 1999. Re-evaluation of some organic chemicals, 

hydrazine, and hydrogen peroxide. IARC Monographs on the Evaluation of Carcinogenic Risk of Chemical to 

Humans, Vol 71. Lyon, France. 

807 U.S. EPA (1988). Integrated Risk Information System File of Acetaldehyde. This material is available 

electronically at http://www.epa.gov/iris/subst/0290.htm. 808 U.S. EPA. 2003. Integrated Risk Information System File of Acrolein. Research and Development, National 

Center for Environmental Assessment, Washington, DC. This material is available electronically at 

http://www.epa.gov/iris/subst/0364.htm. 

809 Appleman, L.M., R.A. Woutersen, and V.J. Feron. (1982). Inhalation toxicity of acetaldehyde in rats. I. Acute 

and subacute studies. Toxicology. 23: 293-297. 

810 Myou, S.; Fujimura, M.; Nishi K.; Ohka, T.; and Matsuda, T. (1993) Aerosolized acetaldehyde induces 

histamine-mediated bronchoconstriction in asthmatics. Am. Rev. Respir.Dis.148(4 Pt 1): 940-943. 

811 Integrated Risk Information System File of Acrolein. Research and Development, National Center for 

Environmental Assessment, Washington, DC. This material is available at http://www.epa.gov/iris/subst/0364.htm 

806
 
 

 

 

 

 

 

 

 

 

812 International Agency for Research on Cancer (IARC). 1995. Monographs on the evaluation of carcinogenic risk of chemicals to humans, Volume 63, Dry cleaning, 

some chlorinated solvents and other industrial chemicals, World Health Organization, Lyon, France. 

813 Weber-Tschopp, A; Fischer, T; Gierer, R; et al. (1977) Experimentelle reizwirkungen von Acrolein auf den 

Menschen. Int Arch Occup Environ Hlth 40(2):117-130. In German 

814 Sim, VM; Pattle, RE. (1957) Effect of possible smog irritants on human subjects. J Am Med Assoc 

165(15):1908-1913. 

815 Morris JB, Symanowicz PT, Olsen JE, et al. 2003. Immediate sensory nerve-mediated respiratory responses to 

irritants in healthy and allergic airway-diseased mice. J Appl Physiol 94(4):1563-1571.

816 Sim VM, Pattle RE. Effect of possible smog irritants on human subjects JAMA165: 1980-2010, 1957. 817 U. S. EPA. 2004. Toxicological Review of Naphthalene (Reassessment of the Inhalation Cancer Risk), Environmental 

Protection Agency, Integrated Risk Information System, Research and Development, National Center for 

Environmental Assessment, Washington, DC. This material is available electronically at 

http://www.epa.gov/iris/subst/0436.htm. 818 Oak Ridge Institute for Science and Education. (2004). External Peer Review for the IRIS Reassessment of the Inhalation Carcinogenicity of Naphthalene. August 2004. 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=84403

819 National Toxicology Program (NTP). (2004). 11th Report on Carcinogens. Public Health Service, U.S.
 

Department of Health and Human Services, Research Triangle Park, NC. Available from: http://ntpserver.niehs.nih.gov.

820 International Agency for Research on Cancer (IARC). (2002). Monographs on the Evaluation of the Carcinogenic Risk of Chemicals for Humans. Vol. 82. Lyon, France. 

821 U. S. EPA. 1998. Toxicological Review of Naphthalene, Environmental Protection Agency, Integrated Risk 

Information System, Research and Development, National Center for Environmental Assessment, Washington, DC. 

This material is available electronically at http://www.epa.gov/iris/subst/0436.htm 

822 International Agency for Research on Cancer (IARC). 1988. Monographs on the evaluation of carcinogenic risk of chemicals to humans, Volume 44, Alcohol 

Drinking, World Health Organization, Lyon, France. 

823 U.S. Department of Health and Human Services. 2005. National Toxicology Program 11th Report on
 

Carcinogens available at: ntp.niehs.nih.gov/index.cfm?objectid=32BA9724-F1F6-975E-7FCE50709CB4C932. 

824 U.S. Department of Health and Human Services. 2000. 10th Special Report to the U.S. Congress on Alcohol and 

Health. June. 2000. 

825 Goodlett CR, KH Horn, F Zhou. 2005. Alcohol teratogeniesis: mechanisms of damage and strategies for 

intervention. Exp. Biol. Med. 230:394-406. 

826 Riley EP, CL McGee. 2005. Fetal alcohol spectrum disorders: an overview with emphasis on changes in brain 

and behavior. Exp. Biol. Med. 230:357-365. 

827 Zhang X, JH Sliwowska, J Weinberg. 2005. Prenatal alcohol exposure and fetal programming: effects on
 

neuroendocrine and immune function. Exp. Biol. Med. 230:376-388. 

828 Riley EP, CL McGee, ER Sowell. 2004. Teratogenic effects of alcohol: a decade of brain imaging. Am. J. Med. 

Genet. Part C: Semin. Med. Genet. 127:35-41. 

829 Gunzerath L, V Faden, S Zakhari, K Warren. 2004. National Institute on Alcohol Abuse and Alcoholism report 

on moderate drinking. Alcohol. Clin. Exp. Res. 28:829-847.

830 World Health Organization (WHO). 2004. Global status report on alcohol 2004. Geneva, Switzerland:
 

Department of Mental Health and Substance Abuse. Available:
 

http://www.who.int/substance_abuse/publications/global_status_report_2004_overview.pdf 831 Chen W-JA, SE Maier, SE Parnell, FR West. 2003. Alcohol and the developing brain: neuroanatomical studies.
 

Alcohol Res. Health 27:174-180. 

832 Driscoll CD, AP Streissguth, EP Riley. 1990. Prenatal alcohol exposure comparability of effects in humans and
 

animal models. Neurotoxicol. Teratol. 12:231-238. 

833 EPA. 2005. Full IRIS Summary for n-Hexane (CASRN 11054-3). Integrated Risk Information System (IRIS),
 

Office of Research and Development, National Center for Environmental Assessment, Washington, DC. Available 

at www.epa.gov/iris/subst/0486.htm. 834 U.S. EPA. 2006. Air quality criteria for ozone and related photochemical oxidants (Ozone CD). Research 

Triangle Park, NC: National Cetner for Environmental Assesssment; report no. EPA/600/R-05/004aF-cF.3v. page 5­

78 Available at http://cfpub.epa.gov/ncea/. 

835 U.S. EPA Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. Environmental 

Protection Agency, Washington, D.C., EPA 600/R-05/004aF-cF, 2006. page 5-63. This document is available in
 

807 
 

 

Docket EPA-HQ-OAR-2005-0161. This document may be accessed electronically at: 

http://www.epa.gov/ttn/naaqs/standards/ozone/s_o3_cr_cd.html 

836 U.S. EPA Air Quality Criteria for Ozone and Related Photochemical Oxidants (Final). U.S. Environmental 

Protection Agency, Washington, D.C., EPA 600/R-05/004aF-cF, 2006. page 5-78. This document is available in 

Docket EPA-HQ-OAR-2005-0161. This document may be accessed electronically at: 

http://www.epa.gov/ttn/naaqs/standards/ozone/s_o3_cr_cd.html 

837 Inhalation health effect concerns for volatilized a.i. compounds are discussed for individual products, e.g., 

oxydimeton-methyl, carbaryl (and carbamates,generally), diazinon, at 

http://www.epa.gov/pesticides/reregistration/status.htm . A.I. vapor pressure and a discussion of product 

volatilization can be found at http://www.epa.gov/ttn/chief/ap42/ch09/final/c9s02-2.pdf 838 U.S. EPA Integrated Risk Information System (IRIS) database is available at: www.epa.gov/iris 

839 Nouchi I, S Toyama. 1998. Effects of ozone and peroxyacetyl nitrate on polar lipids and fatty acids in leaves of 

morning glory and kidney bean. Plant Physiol. 87:638-646. 

840 Oka E, Y Tagami, T Oohashi, N Kondo. 2004. A physiological and morphological study on the injury caused by 

exposure to the air pollutant, peroxyacetyl nitrate (PAN), based on the quantitative assessment of the injury. J Plant 

Res. 117:27-36. 

841 Sun E-J, M-H Huang. 1995. Detection of peroxyacetyl nitrate at phytotoxic level and its effects on vegetation in 

Taiwan. Atmos. Env. 29:2899-2904. 

842 Koukol J, WM Dugger, Jr., RL Palmer. 1967. Inhibitory effect of peroxyacetyl nitrate on cyclic 

photophosphorylation by chloroplasts from black valentine bean leaves. Plant Physiol. 42:1419-1422. 

843 Thompson CR, G Kats. 1975. Effects of ambient concentrations of peroxyacetyl nitrate on navel orange trees. 

Env. Sci. Technol. 9:35-38. 

844 Bytnerowicz A, ME Fenn. 1995. Nitrogen deposition in California forests: A Review. Environ. Pollut. 92:127­

146. 

845 US EPA. 1991. Effects of organic chemicals in the atmosphere on terrestrial plants. EPA/600/3-91/001. 846 Cape JN, ID Leith, J Binnie, J Content, M Donkin, M Skewes, DN Price AR Brown, AD Sharpe. 2003. Effects of 

VOCs on herbaceous plants in an open-top chamber experiment. Environ. Pollut. 124:341-343. 847 Cape JN, ID Leith, J Binnie, J Content, M Donkin, M Skewes, DN Price AR Brown, AD Sharpe. 2003. Effects of 

VOCs on herbaceous plants in an open-top chamber experiment. Environ. Pollut. 124:341-343. 848 Viskari E-L. 2000. Epicuticular wax of Norway spruce needles as indicator of traffic pollutant deposition. Water, 

Air, and Soil Pollut. 121:327-337. 

849 Ugrekhelidze D, F Korte, G Kvesitadze. 1997. Uptake and transformation of benzene and toluene by plant leaves. 

Ecotox. Environ. Safety 37:24-29. 

850 Kammerbauer H, H Selinger, R Rommelt, A Ziegler-Jons, D Knoppik, B Hock. 1987. Toxic components of
 

motor vehicle emissions for the spruce Pciea abies. Environ. Pollut. 48:235-243. 

851 Kwaitkowski, J.R., McAloon, A., Taylor, F., Johnston, D.B., Modeling the process and costs 

of fuel ethanol production by the corn dry-grind process. Industrial Crops and Products 23 

(2006) 288-296. A copy of the current USDA model can be obtained by contacting the 

corresponding author.

852 Gallagher, P.W., Brubaker, H., and Shapouri, H. “Plant Size: Capital Cost Relationships in 

the Dry Mill Ethanol Industry,” Biomass and Bioenergy Vol. 28. 2005. Pp. 565-7.

853 See Tables 4.1-21 and 4.1-22 of this section for biomass costs. Coal costs taken from EIA 

Annual Energy Outlook 2008 Table 15.

854 Bioenergy Feedstock Characteristics from Jonathan Scurlock, Oak Ridge National 

Laboratories, available at http://bioenergy.ornl.gov/papers/misc/biochar_factsheet.html (accessed 

October 1, 2008)

855 EIA Annual Energy Outlook 2008, Tables 8 and 13. Available at 

http://www.eia.doe.gov/oiaf/aeo/aeoref_tab.html

856 Corn Stover Collection Project, David A. Glassner, National Renewable Energy Laboratory, 

1617 Cole Blvd., Golden, CO 80401, James R. Hettenhaus, Chief Executive Assistance, 3211 

808
 
 

Trefoil Ave, Charlotte, NC 28226, and Thomas M. Schechinger, Iron Horse Custom Farming, 

816 Iron Horse Rd, Harlan, IA 51537; in BioEnergy ’98: Expanding BioEnergy Partnerships 

857 Abhijith Mukunda, Graduate Student School of Industrial Engineering, Purdue University, 

West Lafayette IN 47907, Klein E Ileleji, Assistant Professor, School of Agricultural & 

Biological Engineering, Purdue University, West Lafayette IN 47907, Hong Wan, Assistant 

Professor, School of Industrial Engineering, Purdue University, West Lafayette IN47906, 

Simulation of Corn Stover Logistics from On-farm Storage to an Ethanol Plant, Paper Number: 

0661772006, ASABE Annual International Meeting, Portland Convention Center, Portland, 

Oregon, 9 - 12 July 2006

858 Shahab Sokhansanj, , Anthony Turhollow, Oak Ridge National Laboratory, North Logan, UT 

84341-8804, Janet Cushman, Oak Ridge National Laboratory, Oak Ridge, TN 37831-6422, John 

Cundiff, Biological Systems Engineering, Virginia Technical University, Blacksburg, VA 

24061-0303, Engineering aspects of collecting corn stover for bioenergy, Biomass and 

Bioenergy 23 (2002) 347 – 355; Received 15 October 2001; received in revised form 15 April 

2002; accepted 3 May 2002; 2002 Published by Elsevier Science Ltd. 

859 David A. Glassner, National Renewable Energy Laboratory, Golden, CO 80401, James R. 

Hettenhaus, Chief Executive Assistance, Charlotte, NC 28226, and Thomas M. Schechinger, 

Iron Horse Custom Farming, Harlan, IA 51537; Corn Stover Collection Project, in BioEnergy 

’98: Expanding BioEnergy Partnerships 

860 J.E. Atchison, Atchison Consultants, Inc., J. R. Hettenhaus, Chief Executive Assistance, Inc. 

Charlotte, North Carolina, National Renewable Energy Laboratory Golden, Colorado, 

.Innovative Methods for Corn Stover Collecting, Handling, Storing and Transporting, March 

2003. 

861 Daniel R. Petrolia, Department of Applied Economics, College of Food, Agriculture, and 

Natural Resources Sciences, University of Minnesota, The Economics of Harvesting and 

Transporting Corn Stover for Conversion to Fuel Ethanol: A Case Study for Minnesota, 

Staff Paper P06-12 August 2006

862 Renee Sayler & Kenneth Von Bargen, Principal Investigators, Feasibility of Corn Residue 

Collection in Kearney, Nebraska Area, for Western Regional Biomass Energy Program, Report 

of findings, by University of Nebraska-Lincoln, Industrial Agricultural Products Center, Lincoln, 

NE 68583, September 1993. 

863 John S. Cundiff, Professor, Robert D. Grisso, Professor, Biological Systems Engineering 

Dept(MS 0303), Virginia Tech, Blacksburg, VA 24061, Hosein Shapouri, Senior Agricultural 

Economist, U.S.D.A., Office of Energy Policy and New Uses, Washington DC 20250-3815, 

Economic Analysis of two Receiving Facility Designs for a Bioenergy Plant, Paper Number: 

076051,2007 ASABE Annual International Meeting, Sponsored by ASABE, Minneapolis 

Convention Center, Minneapolis, Minnesota, 17 - 20 June 2007 

864 Kevin J. Shinners – Professor of Agricultural Engineering, Ben N. Binversie – Graduate 

Research Assistant, Department of Biological Systems Engineering, University of Wisconsin, 

Madison, WI, Philippe Savoie – Research Scientist, Agriculture and Agri-Food Canada, Quebec, 

Canada, Whole-Plant Corn Harvesting for Biomass: Comparison of Single-Pass and MultiplePass Harvest Systems, Paper Number: 036089 2003 ASAE Annual International Meeting, 

Sponsored by ASAE, Riviera Hotel and Convention Center, Las Vegas, Nevada, USA, 27- 30 

July 2003. 

809 
 

 

865 S. Sokhansanj1, A. Turhollow, and R. Perlack, Oak Ridge National Laboratory, Tennessee, 

USA 37830, Stochastic Modeling of Costs of Corn Stover Costs Delivered to an Intermediate 

Storage Facility, Paper Number: 024190, Presented at: 2002 ASAE Annual International 

Meeting / CIGR XVth World Congress, Sponsored by ASAE and CIGR, Hyatt Regency 

Chicago, Chicago, Illinois, USA, July 28-July 31, 2002 

866 D. Montross, Associate Professor, Scott A. Shearer, Professor, Timothy S. Stombaugh, 

Associate Extension Professor, Stephen F. Higgins, Research Specialist, and Samuel G. McNeill, 

Associate Extension Professor, Department of Biosystems and Agricultural Engineering, 

University of Kentucky, Lexington, Kentucky; and Shahab Sokhansanj, Professor, Oak Ridge 

National Laboratory, Environmental Sciences Division, Oak Ridge, Tennessee, Corn Stover 

Availability and Collection Efficiency Using Typical Hay Equipment, This article is published 

with the approval of the Director of the Kentucky Agricultural Experiment Station and 

designated Paper No. 04-05-066. Transactions of the ASABE, Vol. 50(3): 705−711 – 2007 

American Society of Agricultural and Biological Engineers, ISSN 0001−2351. 

867 American Society of Agricultural and Biological Engineers (ASABE), ASABE Standards, 

2007, 54th Edition, Standards, Engineering Practices, Data, 2950 Niles Road, St. Joseph, MI 

49085-9659. 

868 William Edwards, extension economist, Machinery Management: Estimating Farm 

Machinery Costs, PM 710 Paper version, Revised November 2001; Electronic version Revised 

August 2005, University Extension, Iowa State University. 

869 Mark Hanna, Extension Engineer, University Extension, Iowa State University, Ames Iowa, 

Estimating the Field Capacity of Farm Machines, File A3-24, April 2002.

870 Terry Kastens, Extension Agricultural Economist, Kansas State University Agricultural 

Experiment Station and Cooperative Extension Service, Farm Machinery Operation Cost 

Calculations, MF-2244 May 1997

871 Machinery Cost Estimates: Forage Field Operations, University of Illinois Farm Business 

Management Handbook, University of Illinois Extension FBM 0203 Department of Agricultural 

and Consumer Economics • College of Agricultural, Consumer and Environmental Sciences, 

University of Illinois at Urbana-Champaign 

872 Tim Cross, Agricultural Economics, Agriculture Machinery Cost Calculation Methods, E12­

2015-00-032-98, Agricultural Extension Service, The University of Tennessee Institute of 

Agriculture.

873 Agricultural Prices 2006 Summary, July 2007 United States, Department of Agriculture 

National Agricultural Statistics Service, Pr 1-3 (07) 

874 National Agricultural Statistics Service, Quick Stats (Agricultural Statistics Data Base, State 

and County Data), USDA, http://www.nass.usda.gov/

875 L. O. Pordesimo, W. C. Edens, The University of Tennessee, Dept. of Biosystems 

Engineering and Environmental Science, Knoxville, TN, U.S.A., S. Sokhansanj Oak Ridge 

National Laboratory, Environmental Sciences Division, Oak Ridge, TN, U.S.A., Distribution of 

Above Ground Biomass in Corn , Stover, Paper Number: 02-6059; 2002 ASAE Annual 

International Meeting/CIGR XVth World Congress, Hyatt Regency Chicago, Chicago, Illinois, 

USA,; July 29-31, 2002.

876 Kevin J. Shinners, Professor of Agricultural Engineering, Ben N. Binversie, Graduate 

Research Assistant, Department of Biological Systems Engineering, University of Wisconsin, 

Madison, WI, Philippe Savoie, Research Scientist, Agriculture and Agri-Food Canada, Quebec, 

810
 
 

 

Canada; Harvest and Storage Of Wet and Dry Corn Stover As A Biomass Feedstock, Paper 

Number: 036088, 2003 ASAE Annual International Meeting Riviera Hotel and Convention 

Center, Las Vegas, Nevada, USA, 27- 30 July 2003 

877 R.L. Graham, R.D. Perlack, and L.L. Wright, Environ. Sci. Div., Oak Ridge National Lab., 

Oak Ridge, TN 37831-6407; R. Nelson, Engineering Extension Programs, Kansas State Univ., 

Manhattan, KS 66506, and J. Sheehan, National Renewable Energy Lab., Golden, CO 80401. 

Current and Potential U.S. Corn Stover Supplies, Agronomy Journal 99:1–11, American Society 

of Agronomy, Madison, WI 53711 USA; doi:10.2134/agronj2005.0222 prepared 2005; 

published online 1 January 2007

878 Ron Kotrba, Ethanol Producer Magazine staff writer, The Great Biomass Inquisition, 

Ethanol Producer Magazine, January 2007. 

http://ethanolproducer.com/article.jsp?article_id=2621&q=&page=all 

879 Kevin J. Shinners, Professor of Agricultural Engineering, Ben N. Binversie, Graduate 

Research Assistant, Department of Biological Systems Engineering, University of Wisconsin, 

Madison, WI, Philippe Savoie, Research Scientist, Agriculture and Agri-Food Canada, Quebec, 

Canada; Harvest and Storage Of Wet and Dry Corn Stover As A Biomass Feedstock, Paper 

Number: 036088, 2003 ASAE Annual International Meeting Riviera Hotel and Convention 

Center, Las Vegas, Nevada, USA, 27- 30 July 2003. 

880 William Edwards, Extension Economist, Estimating Farm Machinery Costs, PM710, 

Machinery Management, University Extension, Iowa State University, revised November 2001 

881 Renee Sayler & Kenneth Von Bargen, Principal Investigators, Feasibility of Corn Residue 

Collection in Kearney, Nebraska Area, for Western Regional Biomass Energy Program, Report 

of findings, by University of Nebraska-Lincoln, Industrial Agricultural Products Center, Lincoln, 

NE 68583, September 1993. 

882 Robert D. Grisso , Professor, Virginia Tech, Department of Biological Systems Engineering, 

Blacksburg, Virginia; Paul J. Jasa , Extension Engineer, Biological Systems Engineering 

Department, University of Nebraska, Lincoln, Nebraska; and Dale E. Rolofson , Farm Manager, 

Agri-Cross Farms, Inc. Greenwood, Nebraska. Corresponding author : Paul J. Jasa, Biological 

Systems Engineering Dept., University of Nebraska, Lincoln, Analysis of Traffic Patterns and 

Yield Monitor Data for Field Efficiency Determination, Paper No. 011013, Presented at the 

2000 ASAE Annual Meeting, Applied Engineering in Agriculture Vol. 18(2): 171-178 ( © 2002 

American Society of Agricultural Engineers ). A contribution of the University of Nebraska 

Agricultural Research Division, Lincoln, Nebraska. Journal Series No. 13335. Mention of trade 

and company names are for the reader and do not infer endorsement or preferential treatment of 

the products by the University of Nebraska, Lincoln. 

883 Robert “Bobby” Grisso, Professor, and John C. Cundiff, Professor; and David H. Vaughan, 

Professor, Department of Biological Systems Engineering, Virginia Tech, Blacksburg, VA., 

Investigating Machinery Management Parameters with Computer Tools, Paper Number: 071030, 

Presented at 2007 ASABE Annual International Meeting, Minneapolis Convention Center, 

Minneapolis, Minnesota, 17 - 20 June 2007. Mention of trade and company names are for the 

reader and do not infer endorsement or preferential treatment of the products by Virginia Tech. 

884 Poorna P. Ravula, Robert D. Grisso and John S. Cundiff, Biological Systems Engineering 

Department, Virginia Tech, Blacksburg, VA 24061-0303, Comparison between Two Policy 

Strategies for Scheduling in a Biomass Logistic System, Paper Number: 071095, Presented at the 

811 
 

2007 ASABE Annual International Meeting, Sponsored by ASABE, Minneapolis Convention 

Center 

885 International Fire Code 2903.4: Agricultural Products. Hay, straw or similar agricultural 

products shall not be stored adjacent to structures of combustible materials. Storage shall be 

limited to stacks of 100 tons (91 metric tons) each. Stacks shall be separated by a minimum of 20 

feet (6096 mm) of clear space. Quantities of hay, straw and other agricultural products shall not 

be limited where stored in or near farm structures located outside closely built areas. A permit 

shall not be required for agricultural storage. 

886 Daniel R. Petrolia, Department of Applied Economics, College of Food, Agriculture, and 

Natural Resources Sciences, University of Minnesota, The Economics of Harvesting and 

Transporting Corn Stover for Conversion to Fuel Ethanol: A Case Study for Minnesota, 

Staff Paper P06-12 August 2006

887 Robert D. Perlack, Anthony F. Turhollow, Oak Ridge National Laboratory, Office of 

Scientific and Technical Information, Oak Ridge, TN 37831, Assessment of Options For The 

Collection, Handling, and Transport of Corn Stover, ORNL/TM-2002/44, September 2002, 

Office of Energy Efficiency and Renewable Energy, Biomass Program, U.S. Department of 

Energy.

888 Dr. R.L. (Bob) Nielsen, Agronomy Department, Purdue University, West Lafayette, IN 

47907-1150; Questions Relative to Harvesting & Storing Corn Stover; Prepared September 

1995. Originally published as Agronomy Extension publication AGRY-95-09. 

889 Ron Kotrba, staff writer, The Great Biomass Inquisition, Ethanol Producer Magazine. January 

2007 Issue. Reach him at rkotrba@bbibiofuels.com, © 2007 BBI International 

http://ethanolproducer.com/article.jsp?article_id=2621&q=&page=all 

890 Ron Kotrba, staff writer, The Great Biomass Inquisition, Ethanol Producer Magazine. January 

2007 Issue. Reach him at rkotrba@bbibiofuels.com, © 2007 BBI International 

http://ethanolproducer.com/article.jsp?article_id=2621&q=&page=all 

891 Graeme R Quick, Single-pass Corn and Stover Harvesters: Development and Performance. 

Proceedings of the International Conference on Crop Harvesting and Processing, 9-11 February 

2003, Louisville, Kentucky USA, ASABE, St. Joseph, Mich.; ASAE Publication Number 

701P1103e 

892 A. Aden, M. Ruth, K. Ibsen, J. Jechura, K. Neeves, J. Sheehan, and B. Wallace 

National Renewable Energy Laboratory (NREL); L. Montague, A. Slayton, and J. Lukas Harris 

Group, Seattle, Washington, Ethanol Process Design and Economics Utilizing Co-Current Dilute 

Acid Prehydrolysis and Enzymatic Hydrolysis for Corn Stover; June 2002;NREL is a U.S. 

Department of Energy Laboratory Operated by Midwest Research Institute • Battelle • Bechtel; 

Contract No. DE-AC36-99-GO10337 

893 Robert M. Prewitt, Graduate Research Assistant, Michael D. Montross, Associate Professor, 

Scott A. Shearer, Professor, Timothy S. Stombaugh, Associate Extension Professor, Stephen F. 

Higgins, Research Specialist, Samuel G. McNeill, Associate Extension Professor, Department of 

Biosystems and Agricultural Engineering, University of Kentucky, Lexington, KY; Shahab 

Sokhansanj, Professor, Oak Ridge National Laboratory, Environmental Sciences Division, Oak 

Ridge, TN, Corn Stover Availability and Collection Efficiency Using Typical Hay Equipment, 

Transactions of the American Society of Agricultural and Biological Engineers (ASABE), Vol. 

50(3): 705−711, 2007, ISSN 0001−2351; Publication of this article approved by the Director of 

the Kentucky Agricultural Experiment Station and designated Paper No. 04-05-066. 

812
 
 

894 Graeme R Quick, Single-pass Corn and Stover Harvesters: Development and Performance. 

Proceedings of the International Conference on Crop Harvesting and Processing, 9-11 February 

2003, Louisville, Kentucky USA, ASABE, St. Joseph, Mich.; ASAE Publication Number 

701P1103e 

895 Kevin J. Shinners, Professor of Agricultural Engineering, Graham S. Adsit, Graduate 

Research Assistant, Benjamin N. Binversie, Graduate Research Assistant, Matthew F. Digman, 

Graduate Research Assistant, Department of Biological Systems Engineering, University of 

Wisconsin, Richard E. Muck, Research Scientist, Paul. J. Weimer, Research Scientist, US Dairy 

Forage Research Center – USDA-ARS, Madison, WI, Characteristic Performance and Yields 

using a Single-Pass, Split- Stream Maize Grain and Stover Harvester, Paper Number: 056051, 

presented at the 2004 ASAE/CSAE Annual International and the 2005 ASAE Annual 

International Meeting, Sponsored by ASAE, Tampa Convention Center, Tampa, Florida 17 - 20 

July 2005

896 Shahab Sokhansanj, , Anthony Turhollow, Oak Ridge National Laboratory, North Logan, UT 

84341-8804, Janet Cushman, Oak Ridge National Laboratory, Oak Ridge, TN 37831-6422, John 

Cundiff, Biological Systems Engineering, Virginia Technical University, Blacksburg, VA 

24061-0303, Engineering aspects of collecting corn stover for bioenergy, Biomass and 

Bioenergy 23 (2002) 347 – 355; Received 15 October 2001; received in revised form 15 April 

2002; accepted 3 May 2002; 2002 Published by Elsevier Science Ltd. 

897 Kevin J. Shinners, Professor of Agricultural Engineering, Garrit C. Boettcher, Graduate 

Research Assistant, Jesse T. Munk, Graduate Research Assistant, Matthew F. Digman, Graduate 

Research Assistant, Department of Biological Systems Engineering, University of Wisconsin; 

Richard E. Muck, Research Engineer, Paul. J. Weimer, Research Scientist, US Dairy Forage 

Research Center, USDA-ARS, Madison, WI, Single-Pass, Split-Stream of Corn Grain and 

Stover: Characteristic Performance of Three Harvester Configurations, Presented at: ASABE 

Annual International Meeting, 2006; Oregon Convention Center, Portland, Oregon, 9 – 12 July 

2006. 

898 W. C. Edens, L. O. Pordesimo, The University of Tennessee, Dept. of Biosystems 

Engineering and Environmental Science, Knoxville, TN, S. Sokhansanj, Oak Ridge National 

Laboratory, Environmental Sciences Division, Oak Ridge, TN, Field Drying Characteristics and 

Mass Relationships of Corn Stover Fractions, Presented at the ASAE Annual International 

Meeting/ CIGR XVth World Congress, 2002, Hyatt Regency Chicago, Chicago, Illinois, USA, 

July 28-31, 2002.

899 Richard Hess, Idaho National Laboratory, Uniform Format Feedstock Supply System Design 

for Lignocellulosic Biomass, Western Region Biomass Workshop August 27, 2007 

http://sungrant.oregonstate.edu/workshop/HESS_Western_RP_workshop.pdf 

900 Kevin J. Shinners, Professor of Agricultural Engineering, Ben N. Binversie, Graduate 

Research Assistant, Department of Biological Systems Engineering, University of Wisconsin, 

Madison, WI, Philippe Savoie, Research Scientist, Agriculture and Agri-Food Canada, Quebec, 

Canada; Harvest and Storage Of Wet and Dry Corn Stover As A Biomass Feedstock, Paper 

Number: 036088, 2003 ASAE Annual International Meeting Riviera Hotel and Convention 

Center, Las Vegas, Nevada, USA, 27- 30 July 2003. 

901 Shahab Sokhansanj and Janet Cushman, Bioenergy Feedstock Development Program 

Oak Ridge National Laboratory (ORNL), Feedstock Engineering, Presentation, Lincoln, NB, 

December 12, 2001 ORNL, Energy Efficiency and Renewable Energy, US DOE, USA 

813 
 

 

 

902 Sudhagar Mani, Ph.D. Candidate, Shahab Sokhansanj, Adjunct Professor, Xiaotao Bi, 

Associate Professor, Department of Chemical & Biological Engineering, University of British 

Columbia, Vancouver, BC CANADA V6T 1Z4, Modeling of Forage Drying in Single and Triple 

Pass Rotary Drum Dryers, Paper Number: 056082, 2005 ASAE Annual International Meeting, 

Tampa Convention Center, Tampa, Florida, 17 - 20 July 2005 

903 Xianzhe Zheng, Professor, Yiyuan Jiang, Professor, College of Engineering, North East 

Agricultural University, Harbin, China; Yubin Lan, Associate Professor, Agricultural 

Engineering Technology, Fort Valley State University, University Systems of Georgia, Fort 

Valley, GA 31030, Determination of Parameters for an Alfalfa Rotary Dryer, Paper Number: 

056186, 2005 ASAE Annual International Meeting, Tampa Convention Center, Tampa, Florida, 

17 - 20 July 2005

904 This information came in a confidential, personal communication. 

905 Christopher T. Wright , Peter A. Pryfogle, Nathan A. Stevens , J. Richard Hess , 

Corey W. Radtke , Idaho National Laboratory , Idaho Falls, ID, Value of Distributed 

Preprocessing of Biomass Feedstocks to a Bioenergy Industry, Paper No: 066151 

Presented at the ASABE Annual International Meeting, 2006, Oregon Convention Center 

Portland, Oregon, 9 - 12 July 2006

906 Roger G. Ginder, Professor of Economics, Department of Economics, Iowa State University, 

Ames, Iowa 50011, Potential Infrastructure Constraints on Current Corn Based and Future 

Biomass Based U.S. Ethanol Production, Working Paper # 07018 , July 2007 

907 E-mailed file from Robert Perlack, U.S. Department of Agriculture, May 2008. 

908 Conversation with Bryce Stokes, U.S. Forestry Service, May 2008. 

909 OECD, “Biofuels: Linking Support to Performance,” ITF Round Tables No. 138, March 

2008. 

910 International Energy Agency (IEA), “Biofuels for Transport: An International Perspective,” 

2004. 

911 Goldemberg, J. as sited in Rothkopf, Garten, “A Blueprint for Green Energy in the 

Americas,” 2006. 

912 Unicamp, “A Expansāo do Proalcool como Programa de Desenvolvimento Nacional,” 

Powerpoint presentation at Ethanol Seminar in BNDES, 2006. As quoted in OECD, “Biofuels: 

Linking Support to Performance,” ITF Round Tables No. 138, March 2008. 

913 Ibid. 

914 Ibid. 

915 Ibid. 

916 Macedo. I.C., “Green house gases emissions in the production and use of ethanol from 

sugarcane in Brazil: The 2005/2006 Averages and a Prediction for 2020,” Biomass and 

Bioenergy, 2008.

917 Ibid.
 918 Smeets E, Junginger M, Faaij A, Walter A, Dolzan P, Turkenburg W, “The sustainability of 

Brazilian ethanol-An Assessment of the possibilities of certified production,” Biomass and 

Bioenergy, 2008.

919 Official Statistics of the U.S. Department of Commerce, USITC 

920 Haas, M.J, A process model to estimate biodiesel production costs, Bioresource Technology 

97 (2006) 671-678. 

814
 
 

 

 

 

 

 

 

921 Wright, Mark M; Brown, Robert C.; Comparative Economics of Biorefineries based on the 

Biochemical and Thermochemical Platforms, May 17, 2007. 

922 RFS1 final rule regulatory impact analysis, EPA420-R-07-004, April 2007, 

http://epa.gov/otaq/renewablefuels/420r07004.pdf

923 Infrastructure Requirements for an Expanded Fuel Ethanol Industry, Downstream
 

Alternatives Inc., January 15, 2002. 

924 RFS1 final rule regulatory impact analysis, EPA420-R-07-004, April 2007, 

http://epa.gov/otaq/renewablefuels/420r07004.pdf

925 Tables ES-9 and ES 10, Infrastructure Requirements for an Expanded Fuel Ethanol Industry, 

Downstream Alternatives Inc, January 15, 2002.

926 Petroleum 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 . 

927 BNSF railway biodiesel freight cost information can be found at 

http://www.bnsf.com/markets/agricultural/bnsf4024/cur/itm31001.txt

928 National Petroleum News, Market Facts 2007, October 2007, www.npn.web. 

929 National Petroleum News, Market Facts 2007, October 2007, www.npn.web. 

930 Modeling the Effect of Renewable Fuels Standards 2, Prepared for the Environmental Protection Agency by
 

Jacobs Consultancy under contract with Southwest Research Associates, August 2008. 

931 Table 12, Reference and High Price Cases, Annual Energy Outlook 2008; Energy Information Administration,
 

Department of Energy, June 2008. 

932 Table 2, Reference Case, Annual Energy Outlook 2007; Energy Information Administration, Department of 

Energy, February 2007. 

933 Table 2, Reference Case, Annual Energy Outlook 2008; Energy Information Administration, Department of
 

Energy, June 2008. 

934 D5798-99 (Reapproved 2004), ASTM International. 

935 National Association of Convenience Stores (NACS) online annual price resource kit, NACS, February 2, 2006. 

936 Combined local, state and federal gasoline taxes, American Petroleum Institute, January 2008. 

937 Greene, David L.; Alternative Fuel Market Share as a Function of Fuel Availability and Price Advantage, 1997. 

938 Brownstone, D., Small, K., 2005. Valuing time and reliability: assessing the evidence from road pricing
 

demonstrations. Trans. Res. Part A 39, 279-293. 

939 Brownstone, D., Ghose, D., Golob, T., Kazimi, C., Van Amelsfort, D., 2003. Driver's willingness-to-pay to 

reduce travel time: evidence from the San Diego I-15 Congestion Pricing Project. Trans. Res. Part A 37, 373-387. 

940 Lam, T., Small, K., 2001. The value of time and reliability: measurement from a value pricing experiment. 

Trans. Res. Part E 37 (2-3), 231-251.

941 Steimetz, S., Brownstone, D., 2005. Estimating consumers' 'Value of time' with noisy data: a multiple imputation
 

approach. Trans. Res. Part B 39, 865-889. 

942 Spot Annual Crude Oil Prices for Western Texas Intermediate (WTI), Cushing Oklahoma; 

http://tonto.eia.doe.gov/dnav/pet/hist/rwtca.htm; Energy Information Adminstration, 2008. 

943 National Annual Average Gasoline and Diesel Fuel Prices (all grades); 

http://tonto.eia.doe.gov/dnav/pet/pet_pri_gnd_dcus_nus_a.htm; Energy Information Adminstration, 2008. 

944 U.S. Department of Agriculture, National Agricultural Statistics Service, “Crop and Plants, 

Field Corn”, http://www.nass.usda.gov. 

945 U.S. Department of Agriculture, “Acreage report”, 2008, 

http://usda.mannlib.cornell.edu/usda/current/Acre/Acre-06-30-2008.pdf 

946 Committee on Water Implications of Biofuels Production in the United States, National 

Research Council, Water Implications of Biofuels Production in the United States, The National 

Academies Press, 2008, page 3. 

815 
 

 

947 Huang , Wen-yuan, “Tight Supply and Strong Demand May Raise U.S. Nitrogen Fertilizer 

Prices”, Amber Waves, November 2007, page 7, available online at: 

http://www.ers.usda.gov/AmberWaves/November07/PDF/TightSupply.pdf. 

948 U. S. Environmental Protection Agency, EPA Science Advisory Board, “Hypoxia in the 

Northern Gulf of Mexico”, EPA-SAB-08-003, December 2007, available on line at: 

http://yosemite.epa.gov/sab/sabproduct.nsf/C3D2F27094E03F90852573B800601D93/$File/EPA 

-SAB-08-003complete.unsigned.pdf. 

949U. S. Department of Agriculture, Economic Research Service, “U.S. Fertilizer Use and 

Price”, http://www.ers.usda.gov/Data/FertilizerUse, April 2008. 

950 Inhalation health effect concerns for volatilized a.i. compounds are discussed for individual 

products, e.g., oxydimeton-methyl, carbaryl (and carbamates,generally), diazinon, at 

http://www.epa.gov/pesticides/reregistration/status.htm . A.I. vapor pressure and a discussion of 

product volatilization can be found at http://www.epa.gov/ttn/chief/ap42/ch09/final/c9s02-2.pdf 

951 A discussion of acetochlor toxicity can be found in EPA’s Re-registration Eligibility 

Document (RED) for this product at http://www.epa.gov/IRIS/subst/0521.htm. 

952 A discussion of carbaryl toxicity can be found in EPA’s Re-registration Eligibility Document 

(RED) for this product at http://www.epa.gov/IRIS/subst/0019.htm. 

953 A discussion of alachlor toxicity can be found in EPA’s Re-registration Eligibility Document 

(RED) for this product at http://www.epa.gov/IRIS/subst/0129.htm 

954 See http://www.irac-online.org/ , Insecticide Resistance Action Committee, for toxicity 

classifications and toxicity mode of action definitions used. 

955 See carcinogen weight of evidence (WoE) determination and description of toxicity for 

methomyl at http://www.epa.gov/pesticides/reregistration/REDs/0028red.pdf 

956 U. S. Department of Agriculture, Economic Research Service, “Farm Income and Costs: 2008 

Farm Sector Income Forecast”, 

http://www.ers.usda.gov/Briefing/FarmIncome/nationalestimates.htm , August 2008. 

957U. S. Environmental Protection Agency, EPA Science Advisory Board, op. cit., p. 7. 

958 Secchi, S., J. Tyndall, L. Schulte, and H. Asbjornsen. “Raising the Stakes”, Journal of Soil 

and Water Conservation, Volume 63, Number. 3, 2008, pages 68A-73A. 

959 McLachlan, M., M. Carter, C. Rustay, Effects of the Conservation Reserve Program 

on Priority Mixed-grass Prairie Birds: A Conservation Effects Assessment Project, 2007, 

available online at: ftp://ftpfc.sc.egov.usda.gov/NHQ/nri/ceap/Final%20BCR19%20CRP%20Report.pdf . 

816
 
 

 

 

960 Iowa State University Extension, 2007 Iowa Land Value Survey, 2008, available online at: 

http://www.extension.iastate.edu/Publications/FM1825.pdf. 

961 U. S. Environmental Protection Agency, EPA Science Advisory Board, op. cit., p. 177. 

962 Wilhelm, W. W., J. M. F. Johnson, D. L. Karlen, and D. T. Lightle, “Corn Stover to Sustain 

Soil Organic Carbon Further Constrains Biomass Supply”, Agronomy Journal, Volume 99, 2007, 

pages 1665–1667. 

963 U.S. Environmental Protection Agency, Office of Water, Wadeable Streams Assessment: A 

Collaborative Survey of the Nation's Streams, EPA 841-B-06-002, 2006, available online at: 

http://www.epa.gov/owow/streamsurvey. 964 U. S. Environmental Protection Agency, Office of Water, National Water Quality Inventory: 

Report to Congress 2002 Reporting Cycle, U.S. EPA 841-R-07-001, 2007, available online at 

http://www.epa.gov/305b/2002report/. 

965 Paerl, H.W., D. Robin, D. R. Whitall , “Atmospheric Deposition of Nitrogen: Implications 

for Nutrient Over-Enrichment of Coastal Waters”, Estuaries, Volume 25, Number 4B, 2002, 

pages 677-693. 

966 Chesapeake Bay Program, Sources of Nitrogen Loads to the Bay, available online at: 

http://www.chesapeakebay.net/status_nitrogensources.aspx?menuitem=19797 

967 New York State Department of Environmental Conservation and Connecticut Department of 

Environmental Protection, A Total Maximum Daily Load Analysis to Achieve Water Quality 

Standards for Dissolved Oxygen in Long Island Sound, December 2000, available online at: 

http://www.longislandsoundstudy.net/pubs/reports/Tmdl.pdf . 

968 Roberts, D. M., and J. E. Reuter, DRAFT Lake Tahoe Total Maximum Daily Load Technical 

Report: California and Nevada, California Regional Water Quality Control Board, Lahontan 

Region and Nevada Division of Environmental Protection, September 2007, available online at: 

http://www.waterboards.ca.gov/lahontan/water_issues/programs/tmdl/lake_tahoe/docs/laketahoe 

_tmdl_techrpt.pdf . 

969 Chesapeake Bay Program, Science and Technical Advisory Committee, 

Workshop on Atmospheric Deposition of Nitrogen: Media Brief, May 30, 2007, available online 

at: http://www.chesapeake.org/stac/Press/AtmoNmediabrief.pdf 

970 Roberts, D. M., op.cit., page 4-164. 

971 Committee on Water Implications of Biofuels Production in the United States, National 

Research Council, op. cit. 

817 
 

972 Louisiana Universities Marine Consortium, ‘Dead Zone’ Again Rivals Record Size, July 28, 

2008, available online at: 

http://www.gulfhypoxia.net/research/shelfwidecruises/2008/PressRelease08.pdf 

973 Mississippi River/Gulf of Mexico Watershed Nutrient Task Force, “Gulf Hypoxia Action 

Plan 2008 for Reducing, Mitigating, and Controlling Hypoxia in the Northern Gulf of Mexico 

and Improving Water Quality in the Mississippi River Basin”, 2008, page 22, available online 

at: http://www.epa.gov/msbasin/actionplan.htm. 

974 U. S. Environmental Protection Agency, EPA Science Advisory Board, op. cit. 

975 Mississippi River/Gulf of Mexico Watershed Nutrient Task Force, op.cit., page 37. 

976 Alexander, R.B., Smith, R.A., Schwarz, G.E., Boyer, E.W., Nolan, J.V., and Brakebill, J.W., 

“Differences in Phosphorus and Nitrogen Delivery to the Gulf of Mexico from the Mississippi 

River Basin”, Environmental Science and Technology, Volume 42, Number 3, 2008, pages 822– 

830, available online at: 

http://pubs.acs.org/cgi-bin/abstract.cgi/esthag/2008/42/i03/abs/es0716103.html. 

977 Donner, S. D. and Kucharik, C. J., 2008, “Corn-based Ethanol Production Compromises Goal 

of Reducing Nitrogen Export by the Mississippi River”, PNAS, Volume 105, Number 11, 

2008, pages 4513–4518, available online at: http://www.pnas.org/content/105/11/4513.full. 978 U. S. Environmental Protection Agency, EPA Science Advisory Board, op.cit. page 205. 

979 Institute for Agriculture and Trade Policy, Staying home: How ethanol will change U.S. corn 

exports, 2006, Minneapolis, MN, 26 pages, available online at: 

http://www.agobservatory.org/library.cfm?refid=96658 . 

980 Mississippi River/Gulf of Mexico Watershed Nutrient Task Force, op.cit., page 15. 

981Aulenbach, B.T., Buxton, H.T., Battaglin, W.A., and Coupe, R.H., Streamflow and Nutrient 

Fluxes of the Mississippi-Atchafalaya River Basin and Subbasins for the 

Period of Record Through 2005: U.S. Geological Survey Open-File Report 2007-1080, 2007, 

available online at: http://toxics.usgs.gov/pubs/of-2007-1080/index.html. 

982 U. S. Environmental Protection Agency, EPA Science Advisory Board, op. cit., p. 89. 

983 Mississippi River/Gulf of Mexico Watershed Nutrient Task Force, op. cit., page 16. 

984 Gassman, P.W., Reyes, M. R., Green, C. H. , Arnold, J. G. , “The Soil and Water Assessment 

Tool: Historical Development, Applications, and Future Research Directions”, Transactions of 

the American Society of Agricultural and Biological Engineers, Volume 50, Number 4, 2007, 

pages 1211-1240, available online at:. 

http://www.card.iastate.edu/environment/items/asabe_swat.pdf. 

818
 
 

 

985 Arnold, J. G., R. S. Muttiah, R. Srinivasan, and P. M. Allen, “Regional Estimation of Base 

Flow and Groundwater Recharge in the Upper Mississippi Basin”, Journal of Hydrology, 

Volume 227, 2000, pages 21-40, available online at: 

http://www.sciencedirect.com/science?_ob=ArticleURL&_udi=B6V6C-3YRVDK7­

2&_user=14684&_rdoc=1&_fmt=&_orig=search&_sort=d&view=c&_version=1&_urlVersion= 

0&_userid=14684&md5=ede76b4f1132783167d829c06196e66d . 

986 Jha, M., P. W. Gassman, S. Secchi, and J. Arnold, “Upper Mississippi River Basin Modeling 

System Part 2: Baseline Simulation Results”, in: Coastal Hydrology and Processes (Eds. V.P. 

Singh and Y.J. Xu), Water Resources Publications, Highland Ranch, CO, 2006, pages. 117-126. 

987 Homer, C. C. Huang, L. Yang, B. Wylie and M. Coan. “Development of a 2001 National 

Landcover Database for the United States”. Photogrammetric Engineering and Remote Sensing, 

Volume 70, Number 7, 2004, pages 829-840, available online at 

http://www.mrlc.gov/pdf/July_PERS.pdf . 

988 U.S. Department of Agriculture, National Agricultural Statistic Service, 

http://www.nass.usda.gov/research/Cropland/SARS1a.htm. 

989 U.S. Department of Agriculture, Natural Resources Conservation Service, 

http://www.nrcs.usda.gov/techical/NRI . 

990 Conservation Technology Information Center, http://www.ctic.purdue.edu/. 

991 American Society of Agricultural and Biological Engineers, Manure Production and 

Characteristics. ASAE D384.2 MAR2005. available online at: 

http://asae.frymulti.com/abstract.asp?aid=19432&t=1. 

992 Renewable Fuels Association, “Ethanol Biorefinery Locations,” 

http://www.ethanolrfa.org/industry/locations, April 2008. 

993 Chesapeake Bay Commission, Biofuels and the Bay: Getting It Right to Benefit Farms, 

Forests and the Chesapeake, Chesapeake Bay Commission, Annapolis, Maryland, 2007, 32 

pages, available online at: 

http://www.chesbay.state.va.us/Publications/BiofuelsAndTheBay1.pdf 

994 Simpson, T. W., A. N. Sharpley, R.W. Howarth, H.W. Paerl, and K. R. Mankin, “The New 

Gold Rush: Fueling Ethanol Production while Protecting Water Quality”, Journal of 

Environmental Quality, Volume 37, 2008, pages 318-324. 

995 Chesapeake Bay Foundation, 2007 State of the Bay, 2007, available online at: 

http://www.cbf.org/site/DocServer/2007SOTBReport.pdf?docID=10923. 

996 Chesapeake Bay Commission, op. cit., page 11. 

819 
 

 

 

 

 

 

 

997 U.S. Environmental Protection Agency, Region 7, Environmental Laws Applicable to 

Construction and Operation of Ethanol Plants, EPA-907-B-07-001, November 2007,104 pages, 

available online at: 

http://www.epa.gov/region07/priorities/agriculture/ethanol_plants_manual.pdf 

998 Regassa, T., Koelsch, R., Erickson, G., Impact of Feeding Distillers Grains on Nutrient 

Planning for Beef Cattle Systems, University of Nebraska-Lincoln Extension—RP190, 2008, 8 

pages, available online at: http://www.ianrpubs.unl.edu/epublic/live/rp190/build/rp190.pdf 

999 Jacob, M. D., Fox, J. T., Drouillard, J. S., Renter, D. G., Nagaraja, T. G., “Effects of Dried 

Distillers’grain on Fecal Prevalence and Growth of Escherichia Coli O157 in Batch Culture 

Fermentations from Cattle”, Applied and Environmental Microbiology, Volume 74, Number 1, 

2008, p. 38-43, available online at: http://aem.asm.org/cgi/content/abstract/74/1/38 

1000 U.S. Department of Agriculture, Natural Resources Conservation Service, “Comprehensive 

Nutrient Management Planning Technical Guidance”, National Planning Procedures 

Handbook, Part 600.5, available online at: http://policy.nrcs.usda.gov/17088.wba. 

1001 Ruiz-Aguilar, G. M. L.; O’Reilly, K.; Alvarez, P. J. J, “Forum: A Comparison of Benzene 

and Toluene Plume Lengths for Sites Contaminated with Regular vs. Ethanol-amended 

Gasoline”, Ground Water Monitoring and Remediation, Volume 23, 2003, pages 48-53. 

1002 Reilly, T.E., Dennehy, K.F., Alley, W.M., and Cunningham, W.L., Ground-Water 

Availability in the United States: U.S. Geological Survey Circular 1323, 2008, page 33, available 

online at http://pubs.usgs.gov/circ/1323/ 

1003 McGuire, V.L, Changes in Water Level and Storage in the High Plains Aquifer, 

Predevelopment to 2005: U.S. Geological Survey Fact Sheet 2007-3029, 2007, available online 

at http://pubs.usgs.gov/fs/2007/3029/ . 

1004 U.S. Environmental Protection Agency, Consumer Fact Sheet on Nitrates/Nitrites, available 

online at: http://www.epa.gov/safewater/dwh/c-ioc/nitrates.html 

1005 U.S. Environmental Protection Agency, Office of Water, FACTOIDS: Drinking Water and 

Ground Water Statistics for 2007, EPA 816-K-07-004, 2008, available online at: 

http://www.epa.gov/safewater/data/pdfs/data_factoids_2007.pdf 

1006 U.S. Environmental Protection Agency, Consumer Fact Sheet on Atrazine, available online 

at: http://www.epa.gov/safewater/contaminants/dw_contamfs/atrazine.html 

1007 See 40 CFR, Part 141, Subpart O, App. A. 

1008 U.S. Environmental Protection Agency, A Review of Contaminant Occurrence in Public 

Water Systems, EPA 816-R-99-006, 1999, available online at: 

http://www.epa.gov/OGWDW/occur/nov99_lo.pdf 

820
 
 

 

1009 U.S. Environmental Protection Agency, of Occurrence Estimation Methodology and 

Occurrence Findings Report for the Six-Year Review of Existing National Primary Drinking 

Water Regulations, Office of Water, EPA-815-R-03-006, 2003, pages 38 and 40, available 

online at 

http://epa.gov/OGWDW/standard/review/pdfs/support_6yr_occurancemethods_final.pdf. 

1010 U.S. Environmental Protection Agency, Safe Drinking Water Information System (SDWIS) 

End of Year data for FY 2007, 2007. 

1011 Gilliom, R. J., The Quality of Our Nation's Waters Pesticides in the Nation's Streams and 

Ground Water, 1992-2001: U.S. Geological Survey Circular 129, 2006, Tables 7A-1 to 7A-4, 

available online at: http://water.usgs.gov/nawqa/pnsp/pubs/circ1291/appendix7/7a.html 

1012 Committee on Water Implications of Biofuels Production in the United States, op. cit. 

1013 Great Lakes Commission, The Potential Impacts of Increased Corn Production for Ethanol 

in the Great Lakes-St. Lawrence River Region, 2007, available online at: 

http://www.glc.org/tributary/pubs/documents/EthanolPaper121807FINAL.pdf. 

821