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 

December 30, 2009 

NOTICE 

This technical report does not necessarily represent final EPA decisions or positions. 

It is intended to present technical analyses of issues using data that are currently available. 

The purpose in the release of such a report is to facilitate an exchange of technical information 

and to inform the public of technical developments. 
 2

Table of Contents 

Statement of Need........................................................................................................3 

Overview......................................................................................................................4

List of Acronyms and Abbreviations......................... ................................................6 

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

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

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

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

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

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

Chapter 7: Final Regulatory Flexibility Analysis.................................................... 

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

Endnotes.....................................................................................................................771 
 3

Statement of Need 

 

 The original Renewable Fuel Standard (RFS) program was 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 made several important revisions to the renewable fuel requirements. This 

rule revises the RFS program regulations to implement these EISA provisions. 
 4

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: Final 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. 
 5

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. 
 6

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 
 7

CRP Conservation Reserve Program 

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) 
 8

HEI Health Effects Institute 

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 
 9

NMIM National Mobile Inventory Model (EPA software tool) 

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 
 10

RSM Response Surface Model 

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 
 11

Chapter 1: Renewable Fuel Production and Consumption 

1.1 Biofuel Feedstock Availability 

 Currently, the main feedstocks used for renewable fuel production in the U.S. 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 and converted to 

biofuel 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 that is produced in the U.S. is from corn. Recently, 

there have been plans to convert sugarcane grown in the U.S. into ethanol as well as the 

introduction of relatively new crop varieties for biofuel conversion. We also describe feedstocks 

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

1.1.1.1 Domestic Corn and Other Grain Ethanol 

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

over 10 billion gallons of domestic fuel ethanol estimated to be produced by the end of 2009. 

According to multiple sources, as much as 18 billion gallons of corn ethanol could be produced 

by the 2016-18 timeframe, see Table 1.1-1.1

 For the final rule, we modeled 15 billion gallons of 

corn ethanol to meet the EISA standards. We used the Forestry and Agriculture Sector 

Optimization Model (FASOM) and the Farm and Agricultural Policy Research Institute (FAPRI) 

model to assess the impact of increased renewable fuel volume from business-as-usual on crop 

acreage, crop allocation to fuel vs. other uses, costs, etc. See Section 1.2 for more discussion on 

the renewable fuel volumes assumed for our analyses and Chapter 5 of the RIA for more details 

on the agricultural modeling. Important modeling parameters considered include crop yields and 

ethanol yield per bushel of feedstock as these factors impact the amount of feedstock necessary 

per gallon of biofuel produced. Table 1.1-1 also shows a summary of the parameters used and 

the results from our analyses. 

 
 12

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 14/2018 90 175 35% 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 

 EPA FRM Analysis 

(Base Yield Case) 

15/2022 92/87a 183 35% 2.85 

EPA FRM Analysis 

(Higher Yield Case) 

15/2022 XX 230 XX XX 

a

Acres harvested 

b

We assume all figures above 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.2

 See Table 1.1-2. 

Table 1.1-2. 

U.S. Corn for Grain Area Harvested by State in 2008 and Forecasted November 1, 2009 

State 

Total Harvested 

2008 (1000 Acres) 

2009 Forecast 

(1000 Acres) 

Illinois 11,900 11,800 

Indiana 5,460 5,440 

Iowa 12,800 13,350 

Kansas 3,630 3,870 

Kentucky 1,120 1,130 

Michigan 2,140 1,990 

Minnesota 7,200 7,100 

Missouri 2,650 2,900 

Nebraska 8,550 8,900 

Ohio 3,120 3,120 

South Dakota 4,400 4,600 

Wisconsin 2,880 2,900 

Other States 12,790 12,194 

Total 78,640 79,294

 Corn yield per acre has been increasing over the past three decades.A,3 See Figure 1.1-1. 

In our economic modeling assessment under the base yield case, the national average corn yield 

is approximately 183 bu/acre in 2022, with specific yields calculated at the regional level. The 

national average depends on crop production in each region in a given year (see Chapter 5 of this 

RIA). These yield increases over time are consistent with the United States Department of 

Agriculture (USDA) projections.4

 As further described in Chapter 5, we also investigated a 

 

A Calculated from 1977-2007. 
 13

higher corn yield scenario of 230 bu/acre in 2022, developed in consultation with our colleagues 

at USDA as well as industry groups e.g. Monsanto and Pioneer. 

Figure 1.1-1. U.S. Corn Yields (1978-2009)

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

2007, the percent of U.S. corn used for ethanol was around 23 percent and in 2008 the percent 

had increased to 30 percent. As of December 2009, the majority of corn is still being used as 

animal feed (42 percent), with smaller portions going to ethanol (33 percent), exports (16 

percent), and human food and seed (9 percent).5 For the final rule, the FASOM projects that 

approximately 35 percent of corn would need to be allocated to the ethanol industry by 2022 

under the base corn yield assumption and XX percent of corn under the higher corn yield 

assumptions to produce 15 billion gallons of corn ethanol. 

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. In addition, higher 

crop yields in all countries could decrease the amount of land necessary for a fixed amount of 

renewable fuel produced. We rely on our modeling results to help inform us of the potential 

impacts of an increased growth in renewable fuels (see Chapter 5 for more detail). 

 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.6,7 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 

through advances in plant breeding and new corn varieties. Combining these figures, we project 
 14

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 RIA for more information on 

corn ethanol biofuel production technologies, e.g. dry mill vs. wet mill. 

 Other grains that can be processed into ethanol include grain sorghum (milo), wheat, and 

barley. The production of ethanol from these grains generally involves the same processes as the 

production from corn, and can be used together in the same plant. 

1.1.1.2 Imported Sugar Ethanol

 After corn, sugar crops (i.e. sugar beets and sugarcane) are the world’s next largest 

feedstock sources for ethanol.8,9 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.10 Brazil is currently the 

world’s largest producer of sugarcane (569 million MT in the 2008/9 harvest season) and offers 

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

sugarcane cultivation.11 In Brazil, just 20% of the 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.12

Table 1.1-3. Brazil Land Areas in 2007.13

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

Million Acres

*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 sugarcane. According 

to one study, there is at least 148 million acres of additional land available with proper soil and 
 15

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

and native reserves) and without the use of irrigation.14 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 sugarcane 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.15 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. 

Table 1.1-4. 

Potential Volumes Utilizing Available Land for Sugarcane ExpansionB,16,17 

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

High 659 20 94 13 62

Good 592 281 242 166 143

Average 524 369 414 193 217

Inadequate 0 224 143 0 0

Total 894 894 373 422

Potential

Ethanol Yield 

(gal/acre)

Potential Area 

(million acres)

Potential Ethanol Volume 

(billion gallons)

 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 30 billion gallons of ethanolequivalent 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 RIA for further details on Brazilian ethanol production and consumption. Thus, there 

 

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

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 generally lack the land resources, appropriate soils, and 

climate for large expansion of sugarcane production.18 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. 

1.1.1.3 Domestic Sugar Ethanol

Currently, there are no U.S. plants producing ethanol from sugar feedstocks.19 Brazil and 

several other countries are producing ethanol from sugarcane, sugarbeets, and molasses, 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, sugarbeets, and 

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

Sugarcane in the U.S. is grown mainly in Florida and Louisiana, with smaller amounts 

from Hawaii and Texas. See Table 1.1-5. Sugarbeets, on the other hand, are grown in more 

northern states, with the majority of production in Minnesota, Michigan, and Idaho as shown in 

Table 1.1-6. As noted, these feedstocks are not currently used for commercial production of 

ethanol, however, this may change in the near future. 

Table 1.1-5. Sugarcane Area Harvested (for sugar only, not seed) by State in 2008 and 2009

State 

Total Harvested 

2008 (1000 Acres) 

Total Harvested 

2009 (1000 Acres) 

Florida 384 372 

Hawaii 20 20 

Louisiana 380 375 

Texas 37 39 

Total 821 806
 17

Table 1.1-6. Sugarbeet Area Harvested by State in 2008 and 2009

State 

Total Harvested 

2008 (1000 Acres) 

Total Harvested 

2009 (1000 Acres) 

Idaho 116 163 

Michigan 136 136 

Minnesota 399 455 

Other States 354 397 

Total 1005 1151

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.20 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.21 The company plans to break ground by 

early 2010 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.22 Thus, there is potential for these projects and perhaps others to help contribute to 

the EISA biofuels mandate. 

There is also potential for the use of new crops with certain traits similar to traditional 

sugar and corn feedstocks. For example, a new crop referred to as Sugarcorn is a hybrid cross 

between sugarcane and corn.23 The plant contains genes from Midwestern corn, tropical maize 

and sugarcane, resulting in a variety that doesn’t flower to produce grain but instead produces 

sugar in its stalks. Researchers are currently working to increase sugar yields, increase the 

plant’s hardiness and develop ways to prevent the plant from being pollinated by nearby crops of 

traditional corn. Potential benefits include reduced water and fertilizer consumption during the 

growth of the plant. 

 Another crop receiving greater attention is sweet sorghum. Sweet sorghum refers to 

varieties of sorghum with high concentration of soluble sugars in the sap.24 They are used for the 

production of syrup, alcoholic beverages, crystal sugar, etc. The interest in bioenergy production 

from sweet sorghum comes from the easy accessibility of readily fermentable sugars combined 

with very high yields for biomass. Yield varies with location and variety and ranges from 8-49 

tons/acre. After extraction of the juice, the bagasse can also be used as cellulosic feedstock or 

other purposes. Groups interested in building facilities in the U.S. that can process sorghum juice 
 18

include the Tampa Bay Area Ethanol Consortium in Florida and the Texas BioEnergy Marketing 

Associates in Texas. 

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. 

1.1.2.1 Agricultural Residues

 The harvesting of agricultural residues could provide a large source of readily available 

feedstock for cellulosic biofuels. We estimated the amount of crop residue could potentially be 

produced, and of that, how much could be removed or harvested to determine the total amount 

that could be available to produce biofuel 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 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 RIA. Feedstock costs are discussed in Section 4.XX of the RIA. 

 Sustainable Removal

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

Recent studies and reviews have attempted to address these issues. 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 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.25 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. 26,27 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.28 Current USDA Natural Resource Conservation 

Service (NRCS) practice standards for residue management do not recommend specific residue 

quantities and point to the use of the RUSLE2 model for guidance.29 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 from residue removal. 

Residues have not yet been removed at the contemplated rates over a period sufficiently long for 
 19

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 fully 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 

many variables and 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 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.C

 When soil becomes saturated, particles are 

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.D 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. 

 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 

 

C

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

www.hancockcoingov.org/surveyor/drainage_glossary_of_terms.asp. D saltation: the movement of sand-sized particles by a skipping and bouncing action in the direction the wind is 

blowing 
 20

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. 

 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 

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

control on his lands.30

All agricultural cropland upon which nearly any crop is grown within a particular county 

can exhibit a wide variation in soil erodibility, 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. 

 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 may 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.31

 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. Residue cover can also 

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 
 21

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. 

 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. 

 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).32 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 have discussed 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.33 Removal rates for wheat straw were based on the 

Billion Ton study.34 We believe that given the uncertainties in removal rates, our assumptions 

are reasonable. 
 22

Agricultural Residue Summary 

Corn and wheat are currently receiving the most attention across the industry due to their 

concentrated production areas and because they generate the majority of total residue 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 less 

likely able to support commercial operations. 

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

summarized in Table 1.1-7. The agricultural residue estimates in Table 1.1-7 are based on 

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

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

Table 1.1-7. Estimated Agricultural Residue Feedstock Availability (per year)35,36,37,38,39

Source Total Available Total Removable Sustainably 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 for the final rule, corn stover was the most economical 

agricultural residue projected 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 53 million tons of corn stover would be needed to 

produce the 4.9 billion gallons of cellulosic biofuel estimated to be used by our agricultural 

modeling in 2022.E See Table 1.1-8. Smaller amounts will be required from sugarcane bagasse, 

wheat residue, as well as sweet sorghum pulp (bagasse) to produce another 0.8 billion gallons of 

cellulosic biofuel.F Thus, the residue collected to meet EISA would be a small fraction of the 

total residue produced. See Section 1.8.1.3 for more details on the use of agricultural residues 

for our cellulosic plant siting analysis. 

 

E

 Assuming conversion yield of 92.3 gal/dry ton 

F

 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. 
 23

Table 1.1-8. 

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

State/Region 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

Barley Corn Oats Rice Sorghum Wheat

 

G 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. 
 24

1.1.2.2 Dedicated Energy Crops

Crops developed and grown specifically as a renewable source of cellulosic material for 

biofuel production are not yet commercial, but have significant potential. 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 could likely be the first feedstocks 

used in cellulosic biofuel production due to lower feedstock costs and availability; However, 

there are many uncertainties over land availability and sustainable removal rates for residues. 

Many of the energy crops investigated are 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 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. 

 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 and the potential marginal lands on which they can be grown. While not all of 

these energy crops were specifically modeled in our agricultural models, switchgrass (which is 

often used as the main “model” energy crop), was projected to be a likely and significant 

feedstock for the production of renewable fuel to meet EISA.H,40 For the final rule, FASOM 

projected that 7.9 ethanol-equivalent billion gallons out of the 16 billion gallon cellulosic biofuel 

required would come from switchgrass. See Chapter 5 for more details on the agricultural 

modeling. 

Switchgrass 

The energy crop that has received the most attention is switchgrass. Switchgrass is a 

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 

 

H Assuming 16 Bgal cellulosic biofuel total, 2.3 Bgal from Urban Waste; 13.7 Bgal of cellulosic biofuel for ag 

residues, forestry biomass, and/or energy crops would be needed. 
 25

longer in the fall than annual plants, allowing for a high net conversion of solar energy per 

year.41

Highly variable yields have been estimated at 1-12 dry tons/acre per year depending on 

soil, location, and variety. A yield of 4-5.5 dry tons/acre is a reasonable average today.42 In a 

long term study sponsored by the DOE, average yield after 10 years of growth was 4.8-7.6 

tons/acre for switchgrass when harvested annually.I,43 Biannual harvests were also done 

experimentally to try and achieve the maximum yields possible but the harvests showed little 

difference in total yield. Biannual harvests resulted in approximately 70% of the yield for the 

first cut and 30% for the second.44 

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 a study by S.B. McLaughlin, initial nitrogen fertilization rates were 40-120 kg/acre; 

however they discovered that a reduction to only 20 kg/acre of nitrogen was sufficient to produce 

similar yields in single cut systems in the mid-Atlantic region.45 Reduced nitrogen amounts were 

similar in other regions of the country. 

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 grown for biofuel purposes. The genus is 

primarily tropic or sub-tropic in origin but there is a wide climactic range at the species level.46 

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 to switchgrass with 

high yields and low amounts of input.47 In the Midwest, the growing season of Miscanthus 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.48 

Establishment of a crop takes approximately 2 years, with maximum yields reached in the 

third year depending on soil fertility. 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.49 Yields in Europe ranged widely, with irrigated crops reaching 12 tons/acre and unirrigated 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. 50 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.51 In terms of input, miscanthus uses nitrogen extremely 

 

I

 Switchgrass variety used in this study was Alamo. Other varieties could result in different yields. 
 26

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.52

Challenges in growing and producing miscanthus crop include high establishment costs, 

problems in winter survival during the first year, and potentially 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.53 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.54

Hybrid Poplar 

The poplar tree is another option being investigated for use as a dedicated energy crop. 

Woody perennial plants have some of the same characteristics of the perennial grasses that make 

them suitable for possible use as an energy crop. They retain significant amounts of root 

biomass below ground, require little tillage, grow fast large canopies, and require less 

fertilization than their agricultural counterparts. 

Technological advances in harvesting and genetics may help 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.55 

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 fully optimized. 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 researchers have identified several other plants as potential energy 

crops. These include additional types of grasses such as reed canary grass, high biomass forage 

sorghum, and energy cane. Yields for forage sorghum are high and vary from 10-20 dry tons per 

acre depending on the genotype used.56 High tonnage energy cane perhaps offers the greatest 

potential for much of East Texas and the U.S. Gulf Coast, as commercially grown varieties can 

produce up to 40 dry tons per acre under optimal conditions.57 Hybrid willow, silver maple, 

black locust, sweetgum, and eucalyptus are other perennial woody plants that are possibilities.58 

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 
 27

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 1.1-2). 59 

 

 Figure 1.1-2. 

 Possible Geographic Distribution of Dedicated Energy Crops 

Marginal Land Assessment 

 One of the benefits of perennial species is their suitability for growth on marginal lands. 

A study by Elliot Campbell of Stanford University assessed abandoned land availability and the 

potential for this land to be used for energy crops. 60 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 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 use of that biomass for energy purposes. 

Historical land use data, satellite imagery, and a global ecosystem model were used for 

the estimates. The study 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. 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 
 28

texture, land cover and the normalized difference vegetation index (NDVI), but does not take 

into account fertilizer use or irrigation, which could increase yields. 

 The low and high estimates for global abandoned land, excluding forested and urban 

areas are 951 and 1166 million acres. 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 

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 just 80 gallons of ethanol 

per ton of biomass, there could 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. Although 

perennial grasses can be grown 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. Texas has the largest amount of abandoned land estimated at 10.37 million 

acres. Wyoming, Utah, Oregon, New Mexico, Nevada, Colorado and California each contribute 

over 5 million abandoned acres to the total. Midwestern states including Iowa, Wisconsin, 

Illinois, and Ohio have approximately 3-4 million acres of abandoned land each (see Table 1.1-

9). 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 1.1-2). 
 29

Table 1.1-9. Abandoned Agriculture Land and Potential Production by State61

Area Area Production Ethanol Production Rate 

(Million ha) (Million acres) (MM tons biomass/yr) (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

25.68 Bgal Ethanol/yr 

State

Total Ethanol Volumea

a. Assuming a conservative 80 gal/ton conversion rate 
 30

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.62 As of 

November 2009, there were 31.2 million acres under the CRP contract which is down 2.6 million 

acres from the prior year.63 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 1.1-3 shows the land allocation in the United States in 2008.64 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 possible 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 1.1-3. 2008 CRP Enrollment 

1.1.2.3 Wood 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. 
 31

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 considered not suitable for harvesting for biomass because of poor soil, lack of moisture, high 

elevation, or rockiness.65 

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.66 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.67 Both 

primary and secondary mills produce residue and woody waste 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. Construction waste is made of contemporary building materials with little 
 32

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 remove uncontaminated portions. The potential contribution of urban wood residues 

to the production of biofuels is discussed in the Section 1.1.2.4 of this RIA. 

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. 68 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. 

Accessibility of Wood Residues 

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).69 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 

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. 
 33

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.70 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.71 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).72 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.73 Refer to Section 1.3 for more discussion 

on the harvesting and transport of wood residues. 

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 should 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.74 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.75 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.76 Therefore, although there have been suggested limitations to the amount of 

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

 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.77 As different 

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

determine appropriate recommendations on maintaining biodiversity. 
 34

 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.78 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.79 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.80 These values for woody biomass are 

summarized in Table 1.1-10. 

Table 1.1-10. 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 fuel 

per ton of feedstock. Based on recommendations from our cellulosic modeling efforts with the 

National Renewable Laboratory (NREL), we assumed 101.5 gallons of ethanol could be 

produced per ton for hardwood feedstocks in 2022. This is 10 percent more than the yield of 

92.3 gallons of ethanol per ton used for agricultural residues and switchgrass. The reasoning for 

the higher yields for hardwoods is their potential for higher carbohydrate compositions and thus 

more sugars available for conversion to ethanol. These yields were used in our forest and 

agricultural modeling as described in Chapter 5. NREL also completed a more recent feedstock 

analysis indicating that yield differences may be smaller, i.e. closer to 95 gal/dry ton for 

hardwoods. This work will be beneficial as we continue to make improvements to our analyses 

in the future. For more information on feedstock considerations and their impacts on biorefining 

refer to the NREL report in the docket.81 

Availability 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. In addition, we were able to incorporate the forestry sector 
 35

component in the FASOM model, as further described in Chapter 5. As these feedstocks are 

now allowed to compete with the various agricultural feedstocks and energy crops in the market, 

we believe it is a more robust analysis than our prior proposal method of analyzing the 

agriculture and forestry sectors separately. Therefore, our final rule is based on results taken 

from our forest and agricultural modeling in FASOM. 

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).82 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 could 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 to leave behind a 

portion of the logging residue 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 wood 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. 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 estimated 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. 
 36

Approximately 15.6 million dry tons per year were estimated to 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 harvested wood is the pulp and paper mill industry. 

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 estimated 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. Using a forest evaluation tool called the Fuel 

Treatment Evaluator, the Forest Service estimated tree densities for forests all across the U.S. 

and 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 estimated 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 1.1-11, the Billion Ton Study estimates that a total of 67 

million dry tons per year would be available from non-urban forests. 
 37

Table 1.1-11. 

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 in a report titled “US Cellulosic Biomass Supplies and 

Distribution”.83 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 the 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 

1.1-12. 
 38

Table 1.1-12. 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 1.1-13. 

Table 1.1-13. 

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 1.1-14 below estimates the price that specific estimated 

primary mill residue volumes could be available for producing biofuels. 
 39

Table 1.1-14. 

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 
 40

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. Some of these issues were addressed in our cellulosic plant siting analysis in 

Section 1.8. 

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.84 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 (discussed 

later in Section 1.1.2.4). 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 1.1-15, 1.1-16 and 1.1-17. To avoid 

presenting a large 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. 
 41

Table 1.1-15. 

Volume of Forest Residue Available for Producing Biofuel 

Biomass Available at $30/ton 

 Logging 

Residue 

Other 

Removals 

Timerland 

Thinnings 

Unused Mill 

Residue 

 Total 

Quantity 

Alabama 1,202,541 253,620 433,519 7,117 1,896,798

Arizona 8,849 22,436 33,085 1,351 65,721

Arkansas 851,772 385,492 369,083 12,889 1,619,236

California 334,870 0 871,351 65,088 1,271,309

Colorado 9,203 7 0 2,302 11,511

Connecticut 4,195 15,339 10,465 3,949 33,949

Delaware 15,051 12,109 4,918 0 32,077

Florida 535,215 257,704 240,947 2,202 1,036,067

Georgia 1,556,954 496,631 553,627 45,138 2,652,350

Idaho 126,573 0 41,548 6,006 174,126

Illinois 139,101 117,589 115,431 18,523 390,644

Indiana 281,242 52,087 198,112 10,627 542,068

Iowa 56,049 27,580 48,991 159 132,780

Kansas 7,329 44,202 9,676 8,720 69,928

Kentucky 513,989 332,179 344,948 55,196 1,246,311

Louisiana 1,317,139 440,293 300,924 30,075 2,088,431

Maine 1,206,438 470 80,314 42,483 1,329,705

Maryland 90,722 415 40,994 17,067 149,197

Massachusetts 35,461 31,043 13,801 0 80,305

Michigan 379,463 122,476 327,640 13,763 843,343

Minnesota 348,807 331,492 132,712 26,878 839,889

Mississippi 1,548,534 355,071 425,344 95,138 2,424,088

Missouri 387,434 265,146 342,077 79,787 1,074,443

Montana 131,335 0 66,592 9,136 207,063

Nebraska 10,572 9,386 11,707 4,971 36,637

Nevada 15 53 0 0 67

New Hampshire 157,321 174 47,802 7,019 212,316

New Jersey 2,959 39 2,288 1,437 6,723

New Mexico 11,929 1,279 25,898 4,902 44,008

New York 367,003 54,671 163,336 27,390 612,400

North Carolina 1,013,165 629,632 560,814 12,811 2,216,422

North Dakota 1,453 7,601 3,822 265 13,141

Ohio 185,398 9,053 83,676 22,600 300,726

Oklahoma 173,869 98,794 53,043 495 326,200

Oregon 760,276 31 527,702 16,316 1,304,326

Pennsylvania 543,663 699 224,978 170,972 940,312

Rhode Island 884 22,860 2,800 389 26,934

South Carolina 714,551 348,289 301,850 1,051 1,365,741

South Dakota 6,972 14,436 2,993 2,294 26,695

Tennessee 316,706 244,920 423,906 187,583 1,173,115

Texas 616,777 218,464 185,718 3,021 1,023,979

Utah 2,973 7 9,909 4,437 17,325

Vermont 104,876 18,652 48,395 0 171,923

Virginia 741,673 406,800 436,870 39,366 1,624,709

Washington 641,144 22 925,479 21,446 1,588,091

West Virginia 488,356 24,714 161,653 118,779 793,502

Wisconsin 568,800 491,132 260,293 60,410 1,380,636

Wyoming 11,343 0 14,050 34,014 59,407

Total 18,530,943 6,165,088 9,485,083 1,295,560 35,476,674
 42

Table 1.1-16. 

Tons of Forest Residue Available for Producing Biofuel 

Biomass Available at $45/ton 

 Logging 

Residue 

Other 

Removals 

Timerland 

Thinnings 

Unused Mill 

Residue 

 Total 

Quantity 

Alabama 1,202,541 253,620 506,045 7,117 1,969,324

Arizona 13,566 21,210 34,967 1,351 71,094

Arkansas 851,772 385,492 429,414 12,889 1,679,567

California 583,478 0 949,468 65,088 1,598,034

Colorado 10,056 11 30,619 2,302 42,988

Connecticut 4,301 16,095 10,465 3,949 34,810

Delaware 17,932 14,145 6,700 0 38,777

Florida 535,215 257,704 266,597 2,202 1,061,718

Georgia 1,556,954 496,631 644,295 45,138 2,743,018

Idaho 216,303 0 52,594 6,006 274,902

Illinois 139,153 117,589 115,431 18,523 390,696

Indiana 281,464 52,087 221,845 10,627 566,023

Iowa 56,050 27,607 49,551 159 133,367

Kansas 7,329 44,202 9,676 8,720 69,928

Kentucky 513,989 332,179 407,371 55,196 1,308,735

Louisiana 1,317,139 440,293 330,512 30,075 2,118,019

Maine 1,280,511 495 102,442 42,483 1,425,931

Maryland 94,579 421 40,994 17,067 153,060

Massachusetts 39,127 33,191 13,801 0 86,119

Michigan 391,732 128,600 410,302 13,763 944,398

Minnesota 358,518 341,894 159,990 26,878 887,280

Mississippi 1,548,534 355,071 467,935 95,138 2,466,679

Missouri 387,434 265,146 466,082 79,787 1,198,448

Montana 215,597 0 70,775 9,136 295,507

Nebraska 10,710 9,434 11,707 4,971 36,822

Nevada 22 71 0 0 93

New Hampshire 165,519 197 57,566 7,019 230,301

New Jersey 3,184 40 2,423 1,437 7,084

New Mexico 17,239 1,287 26,862 4,902 50,291

New York 384,457 56,552 189,696 27,390 658,094

North Carolina 1,013,165 629,632 668,420 12,811 2,324,028

North Dakota 1,454 7,601 3,822 265 13,142

Ohio 186,022 9,069 88,572 22,600 306,263

Oklahoma 173,869 98,794 62,700 495 335,858

Oregon 1,341,835 34 574,948 16,316 1,933,133

Pennsylvania 1,341,835 34 574,948 170,972 2,087,789

Rhode Island 957 25,039 2,800 389 29,185

South Carolina 714,551 348,289 352,018 1,051 1,415,909

South Dakota 11,872 15,581 3,253 2,294 32,999

Tennessee 316,706 244,920 507,698 187,583 1,256,906

Texas 616,777 218,464 219,187 3,021 1,057,448

Utah 3,758 0 10,786 4,437 18,980

Vermont 108,542 19,182 53,836 0 181,560

Virginia 741,673 406,800 524,372 39,366 1,712,212

Washington 1,067,587 23 981,839 21,446 2,070,895

West Virginia 488,356 24,714 241,184 118,779 873,033

Wisconsin 576,938 499,302 327,027 60,410 1,463,677

Wyoming 18,163 0 18,202 34,014 70,380

Total 20,928,463 6,198,742 11,301,737 1,295,560 39,724,502
 43

Table 1.1-17. 

Tons of Forest Residue Available for Producing Biofuels 

Biomass available at $70/ton 

 Logging 

Residue 

Other 

Removals 

Timerland 

Thinnings 

Unused Mill 

Residue 

 Total 

Quantity 

Alabama 1,202,541 253,620 581,654 7,117 2,044,933

Arizona 13,566 24,510 38,678 1,351 78,105

Arkansas 851,772 385,492 492,094 12,889 1,742,247

California 583,478 0 1,000,615 65,088 1,649,181

Colorado 10,056 11 30,619 2,302 42,988

Connecticut 4,301 16,095 10,465 3,949 34,810

Delaware 17,932 14,145 6,700 0 38,777

Florida 535,215 257,704 332,353 2,202 1,127,474

Georgia 1,556,954 496,631 776,911 45,138 2,875,634

Idaho 216,303 0 61,926 6,006 284,235

Illinois 139,153 117,589 115,431 18,523 390,696

Indiana 281,464 52,087 221,845 10,627 566,023

Iowa 56,050 27,607 49,551 159 133,367

Kansas 7,329 44,202 9,676 8,720 69,928

Kentucky 513,989 332,179 463,904 55,196 1,365,268

Louisiana 1,317,139 440,293 375,052 30,075 2,162,559

Maine 1,280,511 495 166,117 42,483 1,489,605

Maryland 94,579 421 40,994 17,067 153,060

Massachusetts 39,127 33,191 13,801 0 86,119

Michigan 391,732 128,600 533,107 13,763 1,067,203

Minnesota 358,518 341,894 200,599 26,878 927,889

Mississippi 1,548,534 355,071 516,598 95,138 2,515,342

Missouri 387,434 265,146 643,929 79,787 1,376,295

Montana 215,597 0 83,023 9,136 307,755

Nebraska 10,710 9,434 11,707 4,971 36,822

Nevada 22 71 0 0 93

New Hampshire 165,519 197 58,098 7,019 230,833

New Jersey 3,184 40 2,423 1,437 7,084

New Mexico 17,239 1,287 32,187 4,902 55,616

New York 384,457 56,552 192,851 27,390 661,249

North Carolina 1,013,165 629,632 800,455 12,811 2,456,063

North Dakota 1,454 7,601 3,822 265 13,142

Ohio 186,022 9,069 88,572 22,600 306,263

Oklahoma 173,869 98,794 81,634 495 354,792

Oregon 1,251,094 34 566,594 16,316 1,834,037

Pennsylvania 546,418 707 340,497 170,972 1,058,594

Rhode Island 957 25,039 2,800 389 29,185

South Carolina 714,551 348,289 395,555 1,051 1,459,446

South Dakota 11,872 15,581 4,129 2,294 33,875

Tennessee 316,706 244,920 516,550 187,583 1,265,759

Texas 616,777 218,464 253,670 3,021 1,091,931

Utah 3,758 7 14,717 4,437 22,918

Vermont 108,542 19,182 71,105 0 198,829

Virginia 741,673 406,800 630,366 39,366 1,818,206

Washington 1,067,587 23 1,029,985 21,446 2,119,041

West Virginia 488,356 24,714 287,639 118,779 919,489

Wisconsin 576,938 499,302 420,775 60,410 1,557,425

Wyoming 18,163 0 21,598 34,014 73,775

Total 20,042,304 6,202,722 12,593,373 1,295,560 40,133,959
 44

 The U.S. Forest Service data reveals that there are large amounts 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. These numbers are also significantly different than those presented in the 

proposed rule. This is due to a misunderstanding in how the number should be interpreted. 

According to our contacts at the US Forestry Service whether logging residue or timberland 

thinnings would be available would depend on the type of logging operation being used. We 

cannot, therefore, assume that 100% of the logging residue and timberland thinnings would be 

available, as this would be double counting the potential for wood residues. Instead, we must 

assume that a certain percentage of logging operations would produce logging residue and that 

the rest would produce timberland thinnings. Based on suggestions from the forestry service we 

have assumed that 50% of logging operations would produce logging residue and 50% would 

produce forestry thinnings. While these changes result in a significant decrease in the amount of 

wood residue available from current forestry operations they have no impact on our analyses. 

This is due to the fact that the amount of wood residues used in cellulosic biofuel production, as 

projected by the FASOM model, is still far less than the total available wood residue. 

 It is also important to note that this data is based solely on current forestry operations. It 

represents the amount of wood residue that would be available today if these residues were 

recovered. The United States contains much forest land that is not currently in active production 

due to insufficient demand and low prices for forestry products. If demand for cellulosic 

feedstock sufficiently increased the demand for forestry products it is very possible that logging 

operations would expand to meet this need. In this sense, the data from the forestry service is not 

an evaluation of the maximum amount of forestry residue that could be sustainable removed, but 

rather a measure of how much residue could be recovered based on current logging operations. 

Nevertheless, this data is valuable, as the value for cellulosic biomass would likely have to be 

significantly higher than we are projecting in order to drive logging operation expansion. 

Forestry Sector Modeling in FASOM 

[Need discussion from Jeff. C on how the FASOM forest modeling is a subsection of the 

total available material]

 The FASOM modeling projected that 100 million gallons from forestry biomass would 

be used to meet the cellulosic biofuel standard under EISA. 

Wood 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 1.1-18. 
 45

Table 1.1-18. 

Forest Biomass Availability in 2022 at Different Prices (million dry tons/yr) 

Price ($/ton) 

30 45 70 

Billion Ton Study 79 

U.S. Cellulosic 

Biomass Study 20 103 118 

Forest Service Data 35 40 40 

For the rule we were able to incorporate the forestry sector model in FASOM which 

projected 100 million gallons of forestry biomass would be used to meet the cellulosic biofuel 

standard. This would require close to 1 million dry tons per year of forestry biomass. As noted 

by the studies and data from the forestry service, this amount is a small fraction of the large 

amount of forestry biomass potentially available. 

1.1.2.4 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 wastes are used today in a 

variety of ways. Most commonly, wastes are ground into mulch, dumped into land-fills, or 

incinerated. 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. 

Municipal Solid Waste 

 MSW consists of paper, glass, metals, plastics, wood, yard trimmings, food scraps, 

rubber, leather, textiles, etc. See Figure 1.1-4 for the percent composition of MSW generated 

(before recycling) in 2008.85 Construction and demolition debris is not included in the estimate 

and is discussed separately below. 
 46

Figure 1.1-4. 

Total MSW Generation (by Material), 2008 

250 Million Tons (Before Recycling).

 The portion of MSW that can qualify as renewable biomass under the program is already 

discussed in the preamble, Section III.B.1.b. The bulk of the biogenic portion of MSW that can 

be converted into biofuel is cellulosic material such as wood, yard trimmings, paper, and much 

of food wastes. Paper made up the majority of the total MSW generated in 2008, approximately 

31 percent. 

 

 Although recycling/recovery rates are increasing over time, there appears to still be a 

large fraction of biogenic material that ends up unused and in land-fills. 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 2000-2007 for the percent composition of total MSW generated from paper/paperboard, 

wood, and yard trimmings over time as shown in Table 1.1-19 in order to project the percent 

composition of total MSW generated for the year 2022 for those categories (i.e. calculated to be 

24.5% paper, 5.6% wood, and 12.8% yard trimmings and 15.1% food scraps).86 In general, there 

appears to be a decrease in the percentage of total MSW generated from paper, slight increase for 

food scraps, and a relatively stable percent composition of wood and yard trimmings. 

Table 1.1-19. Percent Composition of Total MSW Generated 

(including recyclable material): Paper, Wood, and Yard Trimmings 

 2000 2004 2005 2006 2007 ... 2022 

Material 

Paper/paperboard 36.7 34.6 33.9 33.6 32.7 ... 24.5 

Wood 5.5 5.6 5.6 5.5 5.6 ... 5.6 

Yard Trimmings 12.8 12.7 12.8 12.7 12.8 ... 12.8 

Food Scraps 11.2 11.8 12.1 12.2 12.5 ... 15.1 
 47

 We also analyzed the trends from 2000-2007 for the percent composition of total MSW 

discarded (i.e. after recycling has occurred) to project the percent compositions for the year 2022 

(i.e. calculated to be 8% paper, 8% wood, 3% yard trimmings, and 21.5% food scraps), see Table 

1.1-20 and Table 1.1-21. Comparing Table 1.1-19 and Table 1.1-20, we note that historically 

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 1.1-21 the percent 

composition of total MSW discarded after accounting for both recycling and combustion for 

energy use. 

Table 1.1-20. Percent Composition of Total MSW Discarded 

(not including recycled material): Paper, Wood, and Yard Trimmings 

 2000 2004 2005 2006 2007 

Material 

Paper/paperboard 29.6 26.6 25.1 24.1 22.3 

Wood 7.0 7.3 7.5 7.4 7.6 

Yard Trimmings 8.7 7.0 7.1 7.2 6.9 

Food Scraps 15.4 16.7 17.3 17.6 18.2 

Table 1.1-21. Percent Composition of Total MSW Discarded 

(not including recycled or combusted material): Paper, Wood, and Yard Trimmings 

 2000 2004 2005 2006 2007 ... 2022 

Material 

Paper/paperboard 25.4 23.2 21.9 21.1 19.5 ... 8.0 

Wood 6.0 6.4 6.6 6.5 6.6 ... 8.0 

Yard Trimmings 7.5 6.1 6.2 6.3 6.0 ... 3.0 

Food Scraps 13.2 14.6 15.1 15.4 15.9 21.5 

 The total amount of MSW generated (prior to recycling) is assumed to increase over time 

due to population growth. Biocycle magazine (2008) reports MSW estimates for each state in 

the U.S. based off of 2006 population data.87 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 415 million tons in 2022. 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 

data for the MSW landfilled.

88,89,90,91,92,93,94,95,96,97,98 Using the state composition data, we 
 48

estimated the percent composition of MSW landfilled by state using a ratio of percent 

composition of national material generated (estimated in Table 1.1-19) and landfilled (estimated 

in Table 1.1-21) and state percent composition data for MSW generated (gathered from the 

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, yard trimmings, and 

food scraps have a 10%, 20%, 40%, and 70% moisture content, respectively.99,100 We also 

assumed that wood is approximately 50% contaminated, due to objects such as nails, paint, 

chemicals, etc. typically associated with such feedstocks.101 Paper and food wastes are assumed 

to be mostly uncontaminated, assuming 95% uncontaminated.102 Yard trimmings are also 

assumed to be largely 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 depending on the process 

utilized. Thus, for this analysis we conservatively 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, 90% is assumed to be from wood. 103 We also estimated the amount of food 

waste that is cellulosic material to be 45%.104 We estimate that 23.8 million tons could be 

available after accounting for these factors from paper, 0.9 million tons from yard trimmings, 5.3 

million tons from wood, and 6.5 million tons from food waste. 

Construction and Demolition (C&D) Debris 

C&D debris mostly comes from building demolition and renovation, and the rest comes 

from new construction. 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: 
 49

Table 1.1-22.105

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 approximately 124 million 

metric tons.106 As seen in Table 1.1-22 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.107 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 and a portion of the feedstock 

would likely already be recovered. Thus, we estimate that only 8 million tons would be available 

for biofuels. 

Urban waste summary 

 After estimating the total amount of urban waste available as described in the sections 

above, we further estimated the potential locations that could utilize this material. This is 

described in more detail in Section 1.8.1.3, the cellulosic ethanol plant siting analysis. From this 

analysis we determined that of the 44.5 million dry tons of MSW and C&D wood waste 

available, approximately 26 million dry tons would be used to produce 2.3 ethanol-equivalent 

billion gallons of fuel.J

 We estimated urban wastes outside our agricultural modeling as the 

models do not focus on such feedstocks. The other portion of the 16 billion gallons of cellulosic 

biofuel standard (13.7 billion gallons) was split among the other feedstock types, namely 

agricultural residues, forestry biomass, and energy crops, depending on the economic 

competitiveness. Refer to Chapter 5 more details on the FASOM and FAPRI modeling. 

1.1.2.5 Imported Cellulosic Feedstocks or Biofuels 

Cellulosic biofuel could also be produced internationally. One example of internationally 

produced cellulosic biofuel is ethanol produced from bagasse from sugarcane processing in 

Brazil. Currently, Brazil burns bagasse to produce steam and generate bioelectricity. However, 

improving efficiencies over the coming decade as well as mechanization of sugarcane harvesting 

(no burning of biomass in fields) may allow an increasing portion of bagasse to be allocated to 

other uses, including cellulosic biofuel, as additional straw could potentially be collected and 

used to produce bioelectricity. 

 

J

 Assuming 90 gal/dry ton ethanol conversion yield for urban waste in 2022 
 50

 In fact, a recent study was performed under the Memorandum of Understanding to 

advance collaboration in biofuels, signed by Brazil and the United States on March 2007.108 The 

key objective of the work was to compare the techno-economic performance for thermochemical 

and biochemical conversion of sugarcane residues to ethanol. Studies such as this one help 

identify the anticipated costs and challenges with utilizing cellulosic feedstocks for biofuels. 

Another study assessed the biomass feedstock potential for selected countries outside the 

United States and projected supply available for export or for biofuel production.K,109 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. 

1.1.2.6 Cellulosic Feedstock Summary 

Table 1.1-23 summarizes our internal estimate of the types of cellulosic feedstocks 

projected to be used and their corresponding volume contribution to 16 billion gallons cellulosic 

biofuel by 2022 for the purposes of our impacts assessment. Refer to previous sections for more 

details on how the values in this summary table were derived. The majority of feedstock is 

projected to come from dedicated energy crops, with smaller volumes from agricultural residues, 

forestry biomass, and urban waste. 

Table 1.1-23. 

Cellulosic Feedstocks Assumed To Meet EISA In 2022L

 

Feedstock Volume 

(Ethanol-equivalent Bgal) 

Agricultural Residues 5.7 

Corn Stover 4.9 

Sugarcane Bagasse 0.6 

Wheat Residue 0.1 

Sweet Sorghum Pulp 0.1 

Forestry Biomass 0.1 

Urban Waste 2.3 

Dedicated Energy Crops 

(Switchgrass) 

7.9 

Total 16.0 

 

K Countries evaluated include Argentina, Brazil, Canada, China, Colombia, India, Mexico, and CBI 

L

 Volumes are represented here as ethanol-equivalent volumes, a mix of diesel and ethanol volumes. 
 51

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 for use as food 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 varying portion 

of the biodiesel pool as commodity prices rise and fall. For example, following a rise in soy oil 

prices and then a decline in diesel prices, the share of biodiesel being produced from rendered or 

reclaimed fats or other cheap feedstocks increased steeply in 2008 and 2009. 110 Another 

feedstock we project to become a significant and economical alternative over the next decade is 

corn oil produced during ethanol production (see 1.1.3.2 below). 

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 biofuel and food-related demand 

increases. Modeling scenarios conducted for the year 2022 with the EISA mandates indicates 

that domestic soy oil production would support about 660 million gallons of biodiesel 

production. This material is most likely to be processed by biodiesel plants (as opposed to 

renewable diesel hydrotreating processes) 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 its fermentation co-products in the dry mill ethanol production process. Often called corn 

fractionation, dry separation, or corn oil extraction, these are a collection of processes used to 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. For more information on these technologies, see 

Section 1.4.1.3. 
 52

 Extraction of oil from the thin stillage or distillers’ grains with solubles (DGS) streams is 

a proven technology that can be retrofitted into existing plants relatively cheaply. Front-end 

separation (fractionation) 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. The corn oil 

produced from the fractionation process is food grade corn oil and therefore has a significantly 

higher market value than the inedible corn oil produced by the oil extraction process. For our 

analyses for the final rule we have chosen to focus only on the oil produced by extraction, as we 

believe the higher value of the food grade corn oil makes it highly unlikely it will be used in 

biodiesel production. 

 Information on the expected oil extraction rates, capital costs, and energy use of corn oil 

extraction systems is based on conversations with several technology providers. Depending on 

the configuration, this system can extract 25-75 percent of the oil from the fermentation coproducts, producing an 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 70 percent of projected total ethanol production will implement some type of corn 

oil extraction system by 2022, generating approximately 680 million gallons per year of corn oil 

biofuel feedstock.111,M We expect this material to be processed in biodiesel plants with 

pretreatment capabilities for handling feedstocks with significant free fatty acid (FFA) content. 

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. The 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.112 This figure is broken down into several categories, and 

includes “yellow grease” and “other grease” collected and processed by rendering companies 

each year. The 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.113 (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 

 

M The projected fraction of plants doing corn oil extraction was based on a conversation with several technology 

providers and various people working in the ethanol industry. 
 53

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 not being collected or counted by the NRA that is, or could be, aggregated and direct to 

biofuel production, but there is unfortunately no good way for us to determine this. 

 Our projections would use approximately 22% of this material for biofuel use in 2022 (= 

380 million gallons x 7.5 lb/gal / 13 million lbs). In a written statement by David Meeker of the 

NRA, he asserts that it could be feasible for as much as 30% of the 11 billion lbs to be directed to 

biofuel production on a long-term basis. 114 The feasibility of consumption of this volume of 

rendered material was also supported by comments from a large rendering company (Darling 

International). 

 Much of biodiesel production seems to rely on niches of feedstock availability and 

market outlets. We project that approximately 230 MMgal/yr of rendered or reclaimed fats will 

be processed by biodiesel plants possessing acid pretreatment capabilities to handle these highfree fatty acid feedstocks. We project another 150 MMgal/yr of this material will be used by 

renewable diesel facilities. It is possible that renewable diesel manufacturers will arrange direct 

contract or joint venture with animal processing or rendering operations, taking advantage of 

volumes or prices of feedstock that may not typically be available on the open market to smaller, 

unaffiliated biodiesel plants. 

 Some comments submitted to the docket by Endicott Biofuels, LLC, suggest there are 

additional sources of waste greases and oils sufficient to produce an additional 2 or more billion 

gallons’ worth of biofuel (beyond what we account for above) if they could be collected and 

processed. We have chosen to ignore these volumes in this analysis, as their use will likely 

require further pre-treatment and additional processing steps beyond the capabilities most of the 

installed biodiesel production capacity. However, it is conceivable that these materials may 

begin to be used in significant quantities as dictated by regulatory or economic conditions. 

1.1.3.4 Algae

Algae are single-celled algae species that grow quickly and can be cultivated to produce 

biomass for the downstream production of fuel based on the oil and residuals found in the 

biomass. Many of these algae species are targeted for their high lipid content, and thus are a 

promising feedstock for biofuel production. While some algae 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.N Some of the potential benefits of using algae as a biofuel feedstock 

are that algae can be grown on marginal land, can require low water inputs, can recycle waste 

streams from other processes, does not compete with food production, and has high oil yield. 

 

NAlgenol and Sapphire Energy, see http://www.algenolbiofuels.com/ and http://www.sapphireenergy.com/ 
 54

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.115 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.”116 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. After the program ended the total amount of algae 

research was relatively small because of lack of funding and growing interest in cellulosic 

ethanol.117 In the 1990s Japan’s NEDO-RITE Optical Fiber Bioreactor project obtained support 

from several private companies, laboratories, and academic institutions. However, the program 

was unsuccessful due to high costs for producing algae. Most recently, universities and start-up 

companies have been conducting pilot studies on the cultivation and processing of algae. With 

the high price of oil in 2008 and increased interest from airline providers to cut costs, fuel 

companies and start-ups have begun collaboration efforts to develop alternative biofuels from 

algae. 

For analyses purposes, we assumed that 100 million gallons of algae-based biodiesel 

would be available by 2022 to help meet the biomass-based diesel standard. We believe this is 

reasonable given several announcements from the algae industry about their production plans 

which is further described in Section 1.5.4.3.O 

 

A recent report released in October 2009 entitled “Cultivating Clean Energy: The 

Promise of Algae Biofuels” is a good resource for understanding the basic pathways for algaebased biofuels and summarizes some of the areas that can be improved to further 

commercialization of algae-based biofuels.118 We discuss some of the information contained in 

the report, below. 

In addition, we have consulted with the National Renewable Energy Laboratory (NREL) 

on developing several reasonable pathway scenarios for algae producing oils for biodiesel.119 

While there are many different technologies and fuel combinations being considered for algaebased biofuels, we believe the analyses completed by NREL for the FRM are representative of 

what is possible for the algae industry by 2022. As time permits, we hope to evaluate different 

configurations and their impact on production parameters. To provide further understanding, the 

modeling completed by NREL also included sensitivity analyses which evaluated various 

parameters and their affect on the costs of production (e.g. nutrients required, CO2 delivered, 

 

O Sapphire Energy plans for 135 MMgal by 2018 and 1 Bgal by 2025; Petrosun plans for 30 MMgal/yr facility in 

Arizona; Solazyme plans for 100 MMgal by 2012/13; US Biofuels plans for 4 MMgal by 2010, 50 MMgal by full 

scale. Only several companies have thus far revealed production plans, and more are announced each day. It is 

important to realize that future projections are highly uncertain, and we have taken into account the best information 

we could acquire at the time. 
 55

etc.). The following sections also summarize some of the assumptions and results from the 

NREL modeling for algae; see the technical document for more details. Also, refer to Chapter 2 

for a discussion of how we used the modeling of algae pathways from NREL for our lifecycle 

analyses. For more information on the costs of production for algae from biodiesel, refer to 

Chapter 4. 

 

Cultivation 

 Algae require several inputs, including water, land, nutrients, and in most cases, light to 

sustain growth. The configuration of the algal system impacts the amount of these inputs 

needed. Microalgae, which can have a high mass percentage of triacylglycerols, or natural oils, 

can be cultivated typically 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; generally considered the most efficient 

and low-cost option is the so- called “raceway” ponds, as their shape is similar to an oval 

racetrack. A paddle wheel is used to keep the water in motion around the pond. Other open 

pond systems include unstirred and circular ponds; however, these may have more limited use 

for large scale fuel production. 

The other method of algae cultivation utilizes closed “photobioreactors” which can fall in 

two groups, flat plate and tubular. Flat plate PBRs are made up of a clear plastic containment 

system and tubular PBR’s are clear tubes that carry a circulation of culture between degassing 

and harvesting. Tube PBRs are generally considered more feasible for large scale use since they 

are modular and can accommodate higher flows.120 PBRs can also be placed indoor or outdoor. 

Indoor closed PBRs usually require artificial illumination. Outdoor closed PBRs use natural 

daylight and in some cases also artificial light. There are also variations on cultivation systems 

such as hybrid (combined open and closed) cultivation, heterotrophic cultivation (without light), 

and integrated biofixation systems.P

 

Due to higher cell densities, the use of photobioreactors typically has lower land use in 

comparison to open pond systems producing the same volume of fuel. 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 may limit the amount of land needed due 

to its high productivity and do not require the displacement of agricultural crops. 121,122,123 

When cultivated in enclosed photobioreactors, evaporation of water is limited, and water 

extracted during the drying process can be mostly reclaimed.124 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.125

 

P

 For more information on these variations, refer to the recent report “Cultivating Clean Energy: The Promise of 

Algae Biofuels”. 
 56

 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.126, 127 

However, the salt, other minerals, and contaminants may pose a problem to the dewatering and 

extraction process, depending on the method used. 

Aside from sunlight, land, and water, algae require two main physical inputs for growth: 

CO2 and nutrients.128 Nutrients can be obtained from conventional fertilizers, or from domestic 

or industrial waste sources, such as farm refuse and manure.129 Co-locating algae farms with 

animal husbandry, in order to directly use the manure as a nutrient, would reduce transportation 

costs.130 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.131,132,133 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.134

The US southwest is perhaps one of the most promising locations for economic algae-forbiofuel cultivation, due to its high solar insolation (see Figure 1.1-5), availability of saltwater 

aquifers, and relatively low current land use.135,136 Ideally, algae farms could be co-located with 

coal-burning power plants in order to recycle the carbon emissions. One study states that 1,700 

power plants throughout the United States have enough surrounding land to support a 

commercial-scale algae system, however, only a limited number of these are in the southwest, 

due to lower population densities.137 

Figure 1.1-5. 

PV Solar Radiation in the United States 

 In terms of yields, certain species of algae can produce 80 percent of their body weight as 

oils, however, oil levels of 20-50 percent are more common.138,139 Raceway systems are 

typically lower cost but have lower productivity compared to photobioreactors. The following 

Table 1.1-24 is based on the modeling of algae production from NREL and gives an idea of the 

yields that are reasonable under a base case (assumptions reasonable but still challenging in near 
 57

future), aggressive case (assumes identification of a strain with near optimal growth rates and 

lipid content) and a max case (represents near theoretical maximum based on photosynthetic 

efficiencies). 

Table 1.1-24. Potential Algae YieldQ (gal/acre per year)

Base Case Aggressive Case Max Case 

op PBR op PBR op PBR 

2108 5271 6748 16863 12151 30395 

Harvesting 

Harvesting is necessary to recover biomass from the cultivation system. Commonly used 

techniques include flocculation, dissolved air flotation (DAF), centrifugation, microfiltration, 

and decantation. Additional techniques include discrete sedimentation, membrane filtration, 

phototactic autoconcentration, tilapia-enhanced sedimentation, tube settling, and ultrasonic 

separation. Wet biomass may also be dewatered or dried. Dewatering decreases the moisture 

content by draining or mechanical means. Additional drying can follow using e.g. drum dryer, 

freeze dryer, spray dryer, rotary dryer, or by solar drying. 

Oil Extraction and Recovery 

 Oil from algae can be extracted through chemical, mechanical, or electrical processes to 

separate the algal oil from the cell membrane. The TAGs (Triacylglycerides) are typically the 

main product which goes to biodiesel production. The remainder consists of carbohydrates, 

proteins, nutrients, and ash), usually referred to as algal residue. 

 The extraction step is commonly regarded as the most speculative in terms of large-scale 

feasibility.140 Thus extraction is a critical area of research going forward to achieve practical 

algal lipid production. Some of the methods discussed are solvent extraction, supercritical fluid 

extraction, mechanical extraction, osmotic shock, and sonication. 

The spent biomass (i.e. algal residue) can be used in anaerobic digestion and power 

generation via gas turbine which provides power to run the plant. The other method commonly 

discussed is its use as animal feed. 

Oil Conversion to Biofuel 

 Algal oil can undergo transesterification to produce biodiesel or be hydroprocessed to 

renewable products (e.g. renewable diesel) depending on the slate of products desired. In some 

cases, the entire algae biomass is converted using thermochemical and biochemical methods 

such as pyrolysis, gasification, liquefaction, and fermentation to produce biofuels. See Figure 

1.1-6 for the various pathways for the processing of algal biomass. 

 

Q Only land required for pond/PBR, not including land necessary for processing equipment 
 58

Figure 1.1-6. Pathways for Processing Algal Biomass141

1.1.3.5 Other Potential Feedstocks 

The following sections describe several oil crops that have also been discussed as 

potential biofuel feedstocks. While we have not projected the use of these crops in our current 

impact analyses, these may still be used to help meet the biomass-based diesel and total 

renewable fuel standards under EISA. 

Jatropha

Jatropha is a genus of plants, consisting of both shrubs and trees, some of which hold 

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. The production potential of J. curcas has led to the popularity of the crop as a 

biofuel feedstock. In particular, some potential advantages include growth on marginal lands, 

tolerance to drought, low nutrient and labor inputs, and 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.142,143 Most recently, J. curcas has been investigated 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.144 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.145,146 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.147,148 However, J. curcas may not produce efficiently on 

marginal lands without significant expense. 

As a wild plant which has not yet been domesticated, J. curcas may be considered 
 59

drought-tolerant. However, there is little known on water use efficiency of J. curcas as a crop.149

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. Water use efficiency of 

sister species Jatropha pandurifolia and Jatropha gossypifolia are reported as 3.68 and 2.52 mol 

CO2/mol H2O, respectively.150 This is similar to that of other oil seed species like soybean, with 

a water use efficiency of 3.90 mol CO2 /mol H2O.151 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.152

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 is assumed that the plant would be able to grow as a commercial crop in these 

conditions. However, research indicates that J. curcas growth and production of seed is severely 

limited by soil fertility.153,154 The long-term impact of monocultures of jatropha on soil health 

has also not been studied thoroughly. Some studies indicate that J. curcas may not be 

sustainable, unless specific steps are taken to ensure the plantations’ long term health.155,156 

 The seed of J. curcas, as previously mentioned, has a lipid content of roughly 25-45 

percent by weight.157,158 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.159 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. 

Currently, J. curcas is present in 2 states (Florida and Hawaii) in the U.S.160 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. 161 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.162 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.163

Canola 

 Canola is a type of rapeseed that has been bred to produce edible oil with low levels of 

erucic acid and meal with low levels of toxins, allowing it to be used for livestock feed. It was 

developed in Canada, but is now grown in many places around the world including the United 

States. Currently about 1.2 million acres of canola is grown in the United States. Canola can be 

grown as either a spring or winter crop, with yields for winter canola being significantly higher 

than those for spring canola (1,500 pounds per acre vs. 3,500 pounds per acre)164. The oil 

content of the canola seeds is approximately 40%. The oil produced from the canola seeds is low 

in saturated fat and high in omega-3 fatty acids, making it desirable for use as edible oil. These 

traits, combined with the higher price of canola oil result in very little canola oil being used in 

biodiesel production today. The high oil yields and potential for canola to be grown as a winter 
 60

crop may result in an increase in canola oil production in the United States and a greater 

availability for its use as a biodiesel feedstock. 

Camelina 

 Camelina is an oilseed crop native to Northern Europe and Central Asia that has been 

grown in Europe for thousands of years for use as an edible oil as well as industrial purposes. It 

is primarily considered a weed in North America and is most common in the northern Midwest. 

Recently there has been interest in the potential use of the oil extracted from camelina seeds as a 

biodiesel feedstock. Camelina’s suitability to northern climates, low moisture, and marginal 

soils allow it to be grown in areas that are unsuitable for other major oilseed crops such as soy 

beans, sunflower, and canola. Camelina also requires the use of few, if any, herbicides, as well 

as little to no tillage165. Camelina can also be used to break the continuous planting cycle of 

small grains, effectively reducing the disease, insect, and weed pressure in fields planted with 

wheat the following year166. Camelina seeds contain approximately 40% oil and have averaged 

yields of over 1100 kg/ha (~1000 pounds per acre) in long term trials in Rosemount, Minnesota, 

though future yields improvements through selective breeding are likely165. Camelina is 

currently being grown on over 40,000 acres of land in Montana. 

Pennycress 

 Pennycress is a winter annual weed currently established in every state except Hawaii, 

but especially prevalent in the Midwest and northwest. It has several qualities that make it a 

potential feedstock source for biodiesel production. Pennycress germinates in the fall and grows 

as a winter cover crop. Pennycress flowers and produces seeds in late April and May. These 

seeds can be harvested in early June, allowing the fields to be planted with soy beans. 

Pennycress seed yields have been as high as 2000 pounds per acre in wild stands and yield 36% 

oil when crushed167. In addition to the oil, the seeds of pennycress also contain the chemical 

sinigrin, which has potential uses as a bio-fumigant. The crushed pennycress seeds could be 

used as a weed killer for high value crops that would also provide value as a fertilizer. There are 

concerns, however, about the invasive nature of pennycress. Even though it does not compete 

directly with summer annual crops due to its growing season, there is some concern that, once 

established, pennycress would be very difficult to remove. It has also not been grown as a 

commercial crop, and little is yet known about planting and cultivation requirements. 

 Pennycress is currently being grown on several five to ten acre plots by BioFuels 

Manufacturers of Illinois. They plan to construct a 45 million gallon per year biodiesel plant in 

Peoria County that would use soy oil, animal fats, and vegetable oils as feedstock when it begins 

operation and plans to use pennycress oil as a significant feedstock source in the future168. While 

the initial attempts to grow pennycress were unsuccessful, more recent on farm trials have 

resulted in the successful establishment of pennycress167. Pennycress has a large potential as a 

secondary crop if its cultivation proves to be profitable. 
 61

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.169

 

 EU biodiesel output increased from 200 million gallons in 2000 to 2.3 billion gallons in 

2008.170 According to some analysts, however, the EU does not have the agricultural capacity to 

expand oilseed production and in comparison to other climates, is not particularly good for 

oilseed production.171 Estimates for future EU biodiesel production appear to be roughly 2.5 

billion gallons by 2017.172

 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.173 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 2020.174,175 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, 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.176 If the mandates as 

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 

2020.177 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. 
 62

 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 2010.178 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.179 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.180 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.181 However, in 2006, palm oil prices began to track soybean and rapeseed oil prices.182 

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)183, 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. 

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.184

 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 U.S. 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 not forecasting imports of 

biodiesel to the U.S. for our analyses. 

1.1.3.7 Biodiesel Feedstock Summary 

 Table 1.1-25 shows the volumes and uses of biodiesel and renewable diesel feedstocks as 

projected for the analyses in this rulemaking. Total volume here (1.67 billion gallons) fulfills the 

Biomass Based Diesel category requirements (1.0 billion gallons) and contributes to the Other 

Advanced Biofuel (0.67 billion gallons), as projected for our primary control case (see section 

1.2.2). 
 63

Table 1.1-25. 

Estimated 2022 Biodiesel & Renewable Diesel Volumes 

Based on Feedstock Availability (million gallons of fuel)

Feedstock type Base catalyzed 

biodiesel 

Acid pretreatment 

biodiesel 

Renewable 

diesel 

Virgin vegetable oil 660 - - 

Corn oil from ethanol production 680 - - 

Rendered animal fats and greases - 230 150 

Algae oil or other advanced source 100 - - 

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 best 

estimate 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. To assess the impacts of the increase in renewable fuel volume from 

business-as-usual (what is likely to have occurred without EISA), we have established reference 

and control cases. The reference cases are projections of renewable fuel volumes without the 

enactment of EISA and are described in further detail in Section 1.2.1. It is difficult to ascertain 

how much of the impact from the displacement of gasoline and diesel with renewable fuels 

might be due to the natural growth in renewable fuel use due to market forces as crude oil prices 

rise versus what might be forced by the RFS2 standards. Regardless, these assessments provide 

important information on the wider public policy considerations related to renewable fuel 

production and use, climate change, and national energy security. The control cases are 

projections of the volumes and types of renewable fuel that might be used to comply with the 

EISA volume mandates. For the NPRM we focused on one primary control case whereas for the 

final rule we have expanded the analysis to include two additional sensitivity cases. We assume 

in each of the cases the same ethanol-equivalence basis as was used in the RFS1 rulemaking to 

meet the standard. Volumes listed in the tables for this section are in straight-gallons and allow 

for the reader to calculate ethanol-equivalent gallons if necessary (i.e. times 1.5 for biodiesel or 

1.7 for cellulosic diesel and renewable diesel). Sections 1.2.2 and 1.2.3 aim to describe the 

control cases in greater detail as well as provide fuel volumes and types for years prior to 2022. 

The main difference between the volumes used for the NPRM and the volumes used for 

the FRM is the inclusion of cellulosic diesel for the FRM. The NPRM made the simplifying 

assumption that the cellulosic biofuel standard would be met entirely with cellulosic ethanol. 

However, due to growing interest and recent developments in hydrocarbon-based or so-called 

“drop-in” renewable fuels as well as butanol, and marketplace challenges for consuming high 
 64

volumes of ethanol, we have included projections of more non-ethanol renewables in our 

primary control case for the final rule.R

 In the future, this could include various forms of “green 

hydrocarbons” (i.e., cellulosic gasoline, diesel and jet) and higher alcohols, but for simplicity our 

analyses have modeled it all as cellulosic diesel fuel. We have also included some algae-derived 

biofuels in our FRM analyses given the large interest and potential for such fuels. We have 

continued to assume zero volume for renewable fuels or blendstocks such as biogas, jatropha, 

palm, imported cellulosic biofuel, and other alcohols or ethers in our control cases. Although we 

have not included these renewable fuels and blendstocks in our impact analyses, it is important to 

note that they can still be counted under our program if they meet the lifecycle thresholds and 

definitions for renewable biomass, and recent information suggests that some of them may be 

likely. 

1.2.1 Reference Cases 

Our primary reference case renewable fuel volumes are based on the Energy Information 

Administration’s (EIA) Annual Energy Outlook (AEO) 2007 reference case projections.S

 While 

AEO 2007 is not as up-to-date as AEO 2008 or AEO 2009, we chose to use AEO 2007 because 

later versions of AEO already include the impact of increased renewable fuel volumes under 

EISA as well as fuel economy improvements under CAFE as required in EISA, whereas AEO 

2007 did not. 

For the final rule we also assessed a number of the impacts relative to the reference case 

assuming the mandated renewable fuel volumes under RFS1 from the Energy Policy Act of 2005 

(EPAct). This allows for a more complete assessment of the impacts of the EISA volume 

mandates, especially when combined with the impacts assessment conducted for the RFS1 

rulemaking (though many factors have changed since then). Table 1.2-1 and Table 1.2-2 

summarize the renewable fuel volumes for years 2022 and prior, for the AEO 2007 and the RFS1 

reference cases, respectively. 

 

R

 Comments received from Advanced Biofuels Association, Testimony on June 9, 2009 suggesting a number of 

advanced biofuel technologies will be able to produce renewable diesel, jet fuels, gasoline, and gasoline component 

fuels (e.g. butanol, iso-octane). 

S

 AEO 2007 was only used to derive renewable fuel volume projections for the primary reference case. AEO 2009 

was used for future crude oil cost estimates and for estimating total transportation fuel energy use. 
 65

Table 1.2-1. AEO 2007 Reference Case Renewable Fuel Volumes (billion gallons) 

Advanced Biofuel 

Cellulosic 

Biofuel 

BiomassBased Diesela Other Advanced Biofuel 

NonAdvanced 

Biofuel 

Year Cellulosic Ethanolc FAME Biodieselb Ethanol Imported Corn Ethanol 

Total 

Renewable 

Fuel 

2022 0.25 0.38 0.64 12.29 13.56 2021 0.25 0.38 0.63 12.07 13.33 2020 0.25 0.37 0.60 11.83 13.05 2019 0.25 0.37 0.58 11.69 12.89 2018 0.25 0.36 0.54 11.49 12.64 2017 0.25 0.36 0.53 11.30 12.44 2016 0.25 0.35 0.51 11.16 12.27 2015 0.25 0.25 0.39 11.10 11.99 2014 0.25 0.23 0.20 11.01 11.69 2013 0.25 0.33 0.19 10.93 11.70 2012 0.25 0.33 0.18 10.81 11.57 2011 0.19 0.33 0.16 10.69 11.37 2010 0.12 0.32 0.29 10.49 11.22 

a Biomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel. b Only fatty acid methyl ester (FAME) biodiesel volumes were considered c AEO 2007 reference case assumes actual production of cellulosic biofuel (i.e. not corn ethanol plants utilizing 90% biomass for energy) and therefore 

was assumed to be 0.25 billion gallons. 
 66

Table 1.2-2. RFS1 Reference Case Renewable Fuel Volumes (billion gallons) 

Advanced Biofuel 

Cellulosic 

Biofuel 

BiomassBased Diesela Other Advanced Biofuel 

NonAdvanced 

Biofuel 

Year Cellulosic Ethanolc FAME Biodieselb Ethanol Imported Corn Ethanol 

Total 

Renewable 

Fuel 

2012 2011 n/a n/a n/a n/a n/a 2010 n/a n/a n/a n/a n/a 

0.00 0.303 0.00 7.046 7.35

2013 0.00 0.303 0.00 7.046 7.352014 0.00 0.303 0.00 7.046 7.352015 0.00 0.303 0.00 7.046 7.352016 0.00 0.303 0.00 7.046 7.352017 0.00 0.303 0.00 7.046 7.352018 0.00 0.303 0.00 7.046 7.352019 0.00 0.303 0.00 7.046 7.352020 0.00 0.303 0.00 7.046 7.352021 0.00 0.303 0.00 7.046 7.352022 0.00 0.303 0.00 7.046 7.35 a Biomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel. b Only fatty acid methyl ester (FAME) biodiesel volumes were considered 

c Under the RFS 1 reference case, we assumed the 0.25 billion gallons of cellulosic biofuel would be met primarily by corn ethanol plants utilizing 90% 

biomass for energy, thus actual production of cellulosic biofuel is zero. 
 67

1.2.2 Primary Control Case 

Table 1.2-3 summarizes the fuel types and volumes for the primary control case for the 

years 2010-2022. Although actual volumes and feedstocks will likely be different, we believe 

the projections made here are within the range of expected outcomes when the standards are met 

and allow for an assessment of the potential impacts of the RFS2 rule. More details on 

contributions of different feedstock types within the renewable fuel categories here can be found 

in Section 1.1.
 68

Table 1.2-3. 

Primary Control Case Projected Renewable Fuel Volumes (billion gallons) 

Advanced Biofuel 

Cellulosic Biofuel Biomass-Based Diesela Other Advanced Biofuel 

Non-Advanced 

Biofuel 

Year 

Cellulosic 

Ethanol 

Cellulosic 

Dieselb 

FAMEc

Biodiesel NCRDd Other Biodiesele Ethanol Imported Corn Ethanol 

Total 

Renewable 

Fuelf 

2022 4.92 6.52 0.85 0.15 0.82 2.24 15.00 30.50 2021 4.15 5.50 0.85 0.15 0.77 1.81 15.00 28.23 2020 3.23 4.28 0.85 0.15 0.72 1.88 15.00 26.11 2019 2.61 3.46 0.85 0.15 0.68 1.96 15.00 24.71 2018 2.15 2.85 0.85 0.15 0.64 1.51 15.00 23.15 2017 1.69 2.24 0.85 0.15 0.60 1.07 15.00 21.60 2016 1.31 1.73 0.85 0.15 0.56 0.63 15.00 20.23 2015 0.92 1.22 0.85 0.15 0.53 0.39 14.79 18.85 2014 0.54 0.71 0.85 0.15 0.39 0.20 14.09 16.93 2013 0.31 0.41 0.92 0.08 0.28 0.19 13.42 15.61 2012 0.15 0.20 0.92 0.08 0.12 0.18 12.83 14.48 2011 0.08 0.10 0.72 0.08 0.17 0.16 12.07 13.38 2010 0.03 0.04 0.61 0.04 0.22 0.29 11.24 12.48 

a Biomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel. b Cellulosic Diesel includes 1.96 billion gallons from Fischer-Tropsch Biomass-to-Liquids (BTL) processes and 4.56 billion gallons from this or other types of 

cellulosic diesel processes in year 2022. In order to calculate the split of cellulosic ethanol vs. cellulosic diesel in years prior to 2022, we assumed the same 

c 

percentage of the total cellulosic biofuel standard as in year 2022, i.e. 31% cellulosic ethanol and 69% cellulosic diesel. 

Fatty acid methyl ester (FAME) biodiesel 

d Non-Co-processed Renewable Diesel (NCRD) e Other Biodiesel is biodiesel that could be produced in addition to the amount needed to meet the biomass-based diesel standard.

May not total due to rounding. f 
 69

1.2.2.1 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 or heating oil, 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. For instance, 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. 

It will also depend on the relative demand for gasoline and diesel fuel. For example, 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. 

 

 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 RIA for more discussion). Thus, the production of cellulosic diesel instead of 

cellulosic ethanol could help increase consumption of renewable fuels. 

Cellulosic biofuel could also be produced internationally. One example of internationally 

produced cellulosic biofuel is ethanol produced from bagasse from sugarcane processing in 

Brazil. Currently, Brazil burns bagasse to produce steam and generate bioelectricity. However, 

improving efficiencies over the coming decade as well as mechanization of sugarcane harvesting 

(no burning of biomass in fields) may allow an increasing portion of bagasse to be allocated to 

other uses, including cellulosic biofuel, as additional straw could potentially be collected and 

used to produce bioelectricity. 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, our analyses for cellulosic 

biofuel primarily focus on North America, and for our impact analyses just on domestic supplies. 

As discussed, there is uncertainty as to which mix of cellulosic biofuels will be produced 

to fulfill the 16 Bgal mandate by 2022. For assessing the impacts of the RFS2 standards, we 

used AEO 2009 (April release) cellulosic ethanol volumes (4.92 billion gallons), as well as the 

cellulosic biomass-to-liquids (BTL) diesel volumes (1.96 billion gallons) using Fischer-Tropsch 
 70

(FT) processes. We consider BTL diesel from FT processes as a subset of cellulosic diesel. In 

order to reach a total of 16 billion ethanol-equivalent gallons, we assumed that an additional 4.56 

billion gallons of cellulosic diesel could be produced from BTL or other cellulosic diesel 

processes. 

1.2.2.2 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. 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 1.2.2.1. 

 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 

preferentially processed by biodiesel plants. Other feedstocks assumed to be used by biodiesel 

plants are fuel-grade corn oil from corn oil extraction, fats, waste oils, and waste greases. For 

the FRM we have also included a small volume of oil feedstock from algae for biodiesel 

production. We note that there are a wide range of new feedstocks being researched and 

developed for the production of biodiesel, e.g. camelina and pennycress. While these new 

feedstocks may prove to be commercially available in the future, we have not assumed that they 

are used for analyses purposes. 

For RD, we assumed that the feedstocks used are from fats, waste oils, and waste greases. 

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, waste oils, and waste 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, waste oils, and waste 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 operation. 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 
 71

commercial production of RD is currently underway, and little public information is available 

about the comparative economics and feasibility of the two methods. Current industry plans 

indicate, however, that co-processing renewable diesel may not be as favorable as non-coprocessed RD, and therefore, we have chosen to assume zero volumes of co-processed RD.T

Non-co-processed RD volumes are based on production plans from Syntroleum. 

 

1.2.2.3 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 1.2.2.1 and Section 1.2.2.2 

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 assumes that the cellulosic biofuel volumes will not exceed those 

required under EISA. We do assume, however, that additional biodiesel than that needed to meet 

the biomass-based diesel volume will be used to meet the total advanced biofuel volume. 

Despite additional volumes assumed from biodiesel, to fully meet the total advanced biofuel 

volume required under EISA, other types of advanced biofuel are necessary through 2022. 

 We have assumed for the analyses conducted that for our control case the most likely 

source of advanced fuel other than cellulosic biofuel and biomass-based diesel would be from 

imported sugarcane ethanol and perhaps limited amounts of co-processed renewable diesel. Our 

assessment of international fuel ethanol production and demand indicate that anywhere from 3.8-

4.2 Bgal of sugarcane ethanol from Brazil could be available for export by 2020/2022. If this 

volume were to be made available to the U.S., then there would be sufficient volume to meet the 

advanced biofuel standard. To calculate the amount of imported ethanol needed to meet the 

EISA advanced biofuel standards, we assumed it would make up the difference not met by 

cellulosic biofuel, biomass-based diesel and additional biodiesel categories. The amount of 

imported ethanol required by 2022 is approximately 2.2 Bgal.U 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.V There are at least two projects being developed at this time that 

 

T

 On May 13, 2009 ConocoPhillips and Tyson suspended plans for building RD co-processing facilities. The tax 

credit for RD co-processing that helped fund the project was cut from $1 a gallon to 50 cents a gallon as part of the 

credit bill approved by Congress and signed by President Bush in late 2008. The non-co-processing tax credit 

remains at $1 a gallon. 

U The exceptions were for the years from 2010-2015 in the control case, where we assumed AEO 2007 imported 

ethanol volumes; otherwise, imported ethanol volumes would be zero and lower than the reference case volumes. 

V Personal communication with Nathalie Hoffman, Managing Member of California Renewable Energies, LLC, 

August 27, 2008 
 72

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 contains less oxygen, allowing it to 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. 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 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 

processing of biomass. 
 73

 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 24 billion ethanolequivalent gallons 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.185, 186 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 mostly non-transportation uses such as 

electrical power generation or facility heating. 

1.2.2.4 Other Renewable Fuel 

 The remaining portion of total renewable fuel not met with advanced biofuel is assumed 

to come from corn-based ethanol (including small amounts from other starch grains and waste 

sugars). EISA effectively sets a limit for participation in the RFS program of 15 Bgal of corn 

ethanol, and we are assuming for our analysis that sufficient corn ethanol will be produced to 

meet the 15-Bgal limit that either meets the 20% GHG threshold or is grandfathered. It should 

be noted, however, that there is no specific “corn-ethanol” mandated volume, and that any 

advanced biofuel produced above and beyond what is required for the advanced biofuel 

requirements could reduce the amount of corn ethanol needed to meet the total renewable fuel 

standard. This occurs in our projections during the earlier years (2009-2015) in which we project 

that some fuels could compete favorably with corn ethanol (e.g. biodiesel and imported ethanol). 

Beginning around 2016, fuels qualifying as advanced biofuels likely will be devoted to meeting 

the increasingly stringent volume mandates for advanced biofuel. It is also important to note that 

more than 15 Bgal of corn ethanol could be produced and RINs generated for that volume under 

the RFS2 regulations. However, obligated parties would not be required to purchase more than 

15 Bgal worth of non-advanced biofuel RINs, e.g. corn ethanol RINs. 

 We are assuming for our analysis that sufficient corn ethanol will be produced to meet 

the 15 Bgal limit. This assumes that 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. 
 74

1.2.3 Additional Control Cases Considered 

Since there is significant uncertainty for what fuels will be produced to meet the 16 

billion gallon cellulosic biofuel standard, we have decided to investigate two other sensitivity 

cases for our cost and emission impact analyses conducted for the rule. The first case, we refer 

to as the “Low-Ethanol” control case and assume only 250 million gallons of cellulosic ethanol 

(from AEO 2007 reference case). The rest of the 16 billion gallon cellulosic biofuel standard is 

made up of cellulosic diesel (9.26 billion gallons), as shown in Table 1.2-4. The second case, we 

refer to as the “High-Ethanol” control case and assume the entire 16 billion gallon cellulosic 

biofuel standard is met with cellulosic ethanol, see Table 1.2-5. 
 75

Table 1.2-4. 

Low-Ethanol Control Case Projected Renewable Fuel Volumes (billion gallons) 

Advanced Biofuel 

Cellulosic Biofuel Biomass-Based Diesela Other Advanced Biofuel 

Non-Advanced 

Biofuel 

Year 

Cellulosic 

Ethanol 

Cellulosic 

Dieselb 

FAMEc

Biodiesel NCRDd Other Biodiesele Ethanol Imported Corn Ethanol 

Total 

Renewable 

Fuelf 

2022 0.25 9.26 0.85 0.15 0.82 2.24 15.00 28.57 2021 0.21 7.82 0.85 0.15 0.77 1.81 15.00 26.61 2020 0.16 6.08 0.85 0.15 0.72 1.88 15.00 24.85 2019 0.13 4.92 0.85 0.15 0.68 1.96 15.00 23.69 2018 0.11 4.05 0.85 0.15 0.64 1.51 15.00 22.31 2017 0.09 3.18 0.85 0.15 0.60 1.07 15.00 20.94 2016 0.07 2.46 0.85 0.15 0.56 0.63 15.00 19.72 2015 0.05 1.74 0.85 0.15 0.53 0.39 14.79 18.49 2014 0.03 1.01 0.85 0.15 0.39 0.20 14.09 16.72 2013 0.02 0.58 0.92 0.08 0.28 0.19 13.42 15.49 2012 0.01 0.29 0.92 0.08 0.12 0.18 12.83 14.42 2011 0.00 0.14 0.72 0.08 0.17 0.16 12.07 13.35 2010 0.00 0.06 0.61 0.04 0.22 0.29 11.24 12.47 

a Biomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel. b Cellulosic Diesel includes 1.96 billion gallons from Fischer-Tropsch Biomass-to-Liquids (BTL) processes and 4.56 billion gallons from this and other types of 

cellulosic diesel processes in year 2022. In order to calculate the split of cellulosic ethanol vs. cellulosic diesel in years prior to 2022, we assumed the same 

c 

percentage of the total cellulosic biofuel standard as in year 2022, i.e. 2% cellulosic ethanol and 98% cellulosic diesel. 

Fatty acid methyl ester (FAME) biodiesel 

d Non-Co-processed Renewable Diesel (NCRD) e Other Biodiesel is biodiesel that could be produced in addition to the amount needed to meet the biomass-based diesel standard.

May not total due to rounding. f 
 76

Table 1.2-5. 

High-Ethanol Control Case Projected Renewable Fuel Volumes (billion gallons) 

Advanced Biofuel 

Cellulosic Biofuel Biomass-Based Diesela Other Advanced Biofuel 

Non-Advanced 

Biofuel 

Year 

Cellulosic 

Ethanol 

Cellulosic 

Dieselb 

FAMEc

Biodiesel NCRDd Other Biodiesele Ethanol Imported Corn Ethanol 

Total 

Renewable 

Fuelf 

2022 16.00 0.00 0.85 0.15 0.82 2.24 15.00 35.06 2021 13.50 0.00 0.85 0.15 0.77 1.81 15.00 32.08 2020 10.50 0.00 0.85 0.15 0.72 1.88 15.00 29.11 2019 8.50 0.00 0.85 0.15 0.68 1.96 15.00 27.13 2018 7.00 0.00 0.85 0.15 0.64 1.51 15.00 25.15 2017 5.50 0.00 0.85 0.15 0.60 1.07 15.00 23.17 2016 4.25 0.00 0.85 0.15 0.56 0.63 15.00 21.44 2015 3.00 0.00 0.85 0.15 0.53 0.39 14.79 19.70 2014 1.75 0.00 0.85 0.15 0.39 0.20 14.09 17.43 2013 1.00 0.00 0.92 0.08 0.28 0.19 13.42 15.89 2012 0.50 0.00 0.92 0.08 0.12 0.18 12.83 14.62 2011 0.25 0.00 0.72 0.08 0.17 0.16 12.07 13.45 2010 0.10 0.00 0.61 0.04 0.22 0.29 11.24 12.51 

a Biomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel. b Cellulosic Diesel is assumed to be zero, while cellulosic ethanol is assumed to be 100% of the cellulosic biofuel standard. c Fatty acid methyl ester (FAME) biodiesel d Non-Co-processed Renewable Diesel (NCRD) e Other Biodiesel is biodiesel that could be produced in addition to the amount needed to meet the biomass-based diesel standard.

May not total due to rounding. f 
77

1.3 Feedstock Harvesting, Transportation, & Storage 

 A reliable and affordable source of cellulosic feedstocks will be vital for the development 

of a large scale cellulosic biofuel industry. While Section 1.1 of the RIA examined the 

availability of cellulosic feedstocks for conversion to biofuels, this section focuses instead on the 

process of harvesting, storing, and transporting these feedstocks to the biofuel production 

facilities. For biofuels that use traditional crops such as corn, soy bean oil, or sugar cane, these 

feedstock storage and delivery systems are already well established. For other feedstocks, 

however, such as herbaceous energy crops or wood residue, new feedstock supply systems will 

have to be put into place. Each of these potential feedstocks presents unique challenges that 

must be overcome in order for them to be used for large scale biofuel production. For more 

information on the costs associated with the harvest, storage, and transportation processes see 

Chapter 4 of the RIA. 

1.3.1 Feedstock Harvesting 

 Feedstock harvesting refers to all the steps necessary to make the feedstock available at 

the roadside for transportation and storage. For MSW, this is a relatively simple process. MSW 

is already collected on a large scale and in order to enable it to be used as a feedstock all that is 

required is that it be sorted to remove the portion that is undesirable for biofuel production. 

Agricultural residues and herbaceous energy crops, on the other hand, are not currently being 

harvested on a large scale and therefore new processes must be developed to make them 

available to be used in the production of biofuels. 

1.3.1.1 Municipal Solid Waste (MSW) Collection 

As discussed above, MSW is one of the potential sources of renewable fuel feedstock that 

already has a well developed collection system already in place. In many cases cities and 

municipalities are already recovering recyclable materials, such as metals, plastics, and paper, 

from the collected waste streams. After these valuable materials have been removed from the 

waste stream the remainder of the waste material can, in many cases, be used for the production 

of renewable with little or no additional separation required. Alternatively, a waste stream of 

similar quality may be able to be obtained without the potentially expensive separation process if 

the waste material is separated by the waste producer at the curbside. One potential producer of 

biofuels from MSW indicated in a confidential conversation that this was the method they 

planned to use to obtain their feedstock. 

In parts of the country where these recyclable materials are not currently recovered it will 

be necessary for the biofuel producer who wishes to use this material to first remove the metals, 

plastics, and other contaminated materials before this material may be used. This sorting can be 

done either by hand or with an automated process. Cleaner streams are produced when the waste 

stream is sorted by hand, however this is a slower and more expensive process. Potential biofuel 

producers indicated to us that the automated separation systems that currently exist produce 

waste streams of acceptable quality and are thus more likely to be used due to their lower costs. 

If the biofuel producer was responsible for waste separation it is likely that the separation facility 

and the biofuel production facility would be located at the same site, and thus no transportation 

would be necessary between these two facilities. 

1.3.1.2 Wood Residue Collection and Harvest 
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 Another potential source of feedstock that may be converted to cellulosic biofuels are 

wood residues. This category of feedstock refers to a large range of currently unused wood 

wastes from forestry and wood processing industries. Significant sources of wood residue are 

either currently available or expected to be available in the near future in the form of mill 

residues, forest residue, and forestry thinnings. 

Mill Residue

 One source of currently available wood residue is mill residue. Mill residue is a waste 

product of both primary mills, mills that convert roundwood into other wood products, and 

secondary mills, those that produce finished consumer products. Because this residue is 

currently being produced at the primary and secondary mills all that would be required for its use 

as a cellulosic biofuel feedstock is it’s collection and transportation to the biofuel production 

facility or for the co-located construction of a biofuel facility. 

Forest Residue

The largest portion of wood residue available as cellulosic feedstock is forest residues. 

However, unlike residues such as primary or secondary mill residues that could be available onsite 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.clxxxvii 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”.clxxxviii 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.clxxxix 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.cxc Fortunately, there have been developments in alternative methods to 

reduce the costs of biomass collection systems. 

There has been much focus recently 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 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 
 79

weathering. Utilizing roll on/off containers allows for recovery of residue from difficult-toaccess 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. 

Forest Thinnings 

A third source of wood residue is forestry thinnings. Forest thinnings refer to woody 

material removed from forests that have become overgrown, either to reduce the risk of forest 

fires or to increase productivity of the forest. The material removed is too small or damaged in 

some other way and is unsuitable to be sold as roundwood. Because of its low value, much of 

the wood residue removed from forests today as forest thinnings is either burned or left to 

decompose. Currently the cost to fell the thinnings is paid for by the land owner. Therefore, in 

order to use this material as a cellulosic feedstock the forest thinnings would only have to be 

collected from the forest and moved to the roadside. Once at the roadside they would likely be 

either chipped or bundled using the process previously discussed to increase the density of the 

thinnings, and thus reduce the transportation costs. 

1.3.1.3 Agricultural Residue Harvest 

 Agricultural residue is a very large and potentially readily available cellulosic feedstock 

source for biofuels producers. While the residues of some crops have been harvested for many 

years, much crop residue is left on the fields in order in increase soil quality and protect against 

erosion from wind and rain as discussed in Section 1.1. Despite the many benefits of leaving 

agricultural residue on the fields we believe that it is possible to remove some portion of the 

agricultural residues without significant negative impacts to the soil quality in many parts of the 

country. We also believe that agricultural residues will make up a large portion of the cellulosic 

feedstocks used for biofuel production by 2022. The following section discusses the likely 

process for agricultural residue harvest and the associated challenges we anticipate. We have 

chosen to focus our discussion on corn stover as it is expected that it will be used more 

extensively than any other agricultural residue, and because there is more uncertainty 

surrounding its harvest than other small grains, such as wheat, oats, barley, and rice, that are 

regularly harvested currently. 

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 
 80

a windrow, of sorts, following which the windrow is baled.cxci 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.cxcii 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. After baling, the bales, whether round or square, would be 

picked up from the field and moved to the roadside, where they would await transportation to a 

storage facility. 

We anticipate that by 2022, the corn stover harvest will 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. 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 

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. 

 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. If sugarcane bagasse were to be used as a cellulosic 

feedstock the only additional step that would be required would be to transport the bagasse from 
 81

the sugar fermentation facility to the cellulosic biofuel production facility if they are not colocated. 

1.3.1.4 Energy Crop Harvest 

Energy crops are another very large potential, yet currently unutilized, source of 

cellulosic feedstock. As with corn stover, no harvesting process for energy crops currently 

exists. Additionally, the harvesting process used for energy crops will vary greatly depending on 

whether the energy crop is herbaceous, such as switchgrass or miscanthus, or woody, such as 

hybrid poplar. Nevertheless, we believe that the harvesting practices for energy crops will 

resemble those currently used for small grains and tree plantations respectively. 

Herbaceous Energy Crops 

 The harvesting process for herbaceous energy crops, such as switchgrass and miscanthus, 

is expected to closely resemble that described for corn stover in the preceding section. When the 

herbaceous energy crops are sufficiently dry they will be cut with a mower or swather, similar to 

those used to harvest hay, and left on the field in windrows. The energy crops will then be baled 

and moved to the roadside where they will await transportation to a storage location. 

 While it is possible to harvest herbaceous energy crops using currently available 

equipment designed for hay and other agricultural residues, the high yields of these crops present 

several challenges. The higher production rates per acre of energy crops, when compared to hay 

or corn stover, will require unique equipment designs. There is also likely to be a small harvest 

window where the crop is ready to be harvested, but before the onset of winter weather, 

especially in northern parts of the country. As more energy crops are grown and harvested as 

feedstocks for biofuels and energy sources in other sectors, it is likely that harvesting equipment 

will be developed that is optimized for energy crops. 

 There may also be significant regional variation in the harvesting process for energy 

crops. Energy crops grown in the south will have a longer harvest window, as winter weather 

arrives at a later date, and in many cases is not severe enough to halt harvesting operations. 

Longer growing seasons in the south may also enable multiple harvests in the same year to 

further increase yields. Finally, in parts of the country where year round harvest is possible 

energy crops may be able to be harvested on an as needed basis, negating the need for secondary 

storage and significantly reducing the delivered cost of the energy crops to the biofuel producers. 

For more information on cellulosic feedstock storage and it’s impact on feedstock price see 

sections 1.3.2 and 4.1.1.2. 

Woody Energy Crops 

 As with herbaceous energy crops, it is possible to harvest woody energy crops with 

equipment currently in use by logging operations and the pulp and paper industry. Trees can be 

cut and gathered using a feller buncher and then transported to the roadside. Once at the 

roadside they can either be chipped and blown into chip vans for transportation to the biofuel 

production facility, or bundled using the process described above in the forest residue section. It 
 82

is more likely, however, that woody energy crops will be harvested using equipment specifically 

designed for that purpose and able to take advantage of the regular spacing of the trees found on 

tree plantations. In Europe self propelled harvesters that cut and chip the woody energy crops 

are being used. The wood chips are then stored in large stacks until they are transported to the 

facility where they will be usedcxciii. Work is also being done in Canada to design a harvester 

capable of cutting, shredding, and baling woody energy crops. These bales would then be 

transported to a storage area and allowed to dry before being chipped and used for biofuel 

production. We anticipate that woody energy crops will be harvested using a process optimized 

to fit the individual woody energy crop plantation, likely resembling one of the processes just 

described. 

1.3.2 Feedstock Transportation and Storage 

Once cellulosic feedstocks have been made available at the roadside, either through 

collection or harvesting, they must then be transported to the biofuel production facility. For 

some feedstocks, such as sorted MSW, this may be as simple as delivering the feedstock to a 

biofuel production facility rather than a landfill. For other feedstocks, such as agricultural 

residue or energy crops, it will require a much more complicated process involving multiple 

relocations, loadings, and unloadings, as well as storage in a secondary storage facility. The 

complexity of the transportation of the feedstock from the location where it is produced to the 

biofuel production facility is most dependent on whether the feedstock is available year round 

and harvested on an as needed basis or collected or harvested on an annual or semi-annual basis. 

1.3.2.1 Secondary Storage 

One potential challenge for cellulosic biofuel producers is where the cellulosic material 

will be stored before it is converted into fuel. Some feedstocks, such as MSW or wood residues, 

can be collected or harvested year round. It will therefore only be necessary for the biofuel 

production facility to store a small amount of feedstock on site, we estimate 3-4 days worth, and 

additional feedstock can be received regularly directly from the producers. Agricultural residues 

and herbaceous energy crops, however, are harvested annually or semi-annually, and therefore 

the biofuel producer must be able to store a years worth of feedstock. Because of the low energy 

density of cellulosic feedstocks it would not be feasible to store a years worth of feedstock at the 

biofuel production site, as this would require an area of several hundred acres for feedstock 

storage alone at larger facilities. 

One method that has been suggested is storing baled feedstock at the roadside on the 

farms where it is produced. It would then be loaded onto trucks and transported to the biofuel 

production facility as needed. This method of cellulosic storage at the farms where it is 

produced would be problematic. Storing significant quantities of feedstock at the farm sites 

could force land that would otherwise be used for feedstock production to be instead used for 

feedstock storage. Heavy traffic by the bale loaders and trucks used for transportation could 

cause significant damage to the farmers’ fields. Finally, because access to these feedstocks 

would often be over unimproved private roads on the farmers land there is a real risk that 

feedstock supply could be interrupted by extended periods of inclement weather. We believe 
 83

that the combination of these factors makes feedstock storage at the site where it is produced 

unlikely. 

Another storage option would be to use secondary storage sites. In this method of 

feedstock storage baled cellulosic feedstock would be moved from the site of production to a 

secondary storage facility at the time of harvest. It would then be transported from the secondary 

storage site to the biofuel production facility as needed. Feedstock from many farms would be 

collected at a single secondary storage site. The number of secondary storage sites would 

depend on the size of the biofuel production plant and the density of the feedstock production. 

Storing cellulosic feedstock in secondary storage sites increases the delivered cost of the 

feedstock, but could be necessary due to the limitations of on farm storage mentioned above. 

In addition to where the cellulosic feedstock is stored, there is also the question of how 

the feedstock will be stored. Many different ways of storing the feedstock have been suggested, 

ranging from stacked bales exposed to the weather, to bales wrapped in plastic, to storage in 

covered buildings or pole barns. The issue of whether the feedstock should be baled as round or 

square bales also effects how the feedstock should be stored. Round bales store better in the 

open than square bales since rain, and particularly snow, collect on flat surfaces more readily 

than on round. When stacked, however, round bales usually cannot be stacked more than three 

bales high without the risk of deformation, instability of the stack, and dry matter loss. Square 

bales, however, can be stacked as many as five high without the risk of instability. 

In making the decision whether to store the bales in an indoor facility the cost of the 

storage facility must be weighed against the dry matter loss that will result from storing the bales 

in the open. Dry stover bales stored indoors or outdoors had average dry matter losses of 5% and 

15%, respectively. Wrapping dry bales in net or plastic wrap and storing on a well drained 

surface significantly reduced dry matter loss compared to storing twine wrapped dry bales on the 

ground.cxciv Wrapping bales in net of plastic, however, is usually done at the time of bailing at the 

farm site, and it is not clear whether it is feasible to transport and stack wrapped bales at a 

secondary storage site. 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. Considering these many factors, we believe 

that indoor storage is the storage method that will be most widely utilized. This is the storage 

method which was used in our cost analysis, which can been seen in more detail in Section 4.1.1. 

1.3.2.2 Municipal Solid Waste (MSW) Transportation 

 Transportation and storage of MSW as a feedstock is relatively simple. If the biofuel 

producer is using MSW that has already been separated, all that would be required would be to 

transport the feedstock from the facility where it is separated, most likely a recycling center, to 

the biofuel production facility. This would be done in large over-the-road trucks. The biofuel 

producer would have to store several days worth of feedstock at the fuel production site to ensure 

that fuel production is not interrupted, but because MSW is produced and collected year round 

no secondary storage would be necessary. 
 84

 If the biofuel producer is receiving unsorted MSW it is probable that the sorting facility 

would be co-located with the biofuel production facility. If the biofuel production facility is near 

the source of MSW it may be possible for the local refuse collection trucks to deliver the MSW 

to the plant directly. If the biofuel production facility is located some distance from the MSW 

source it will be more cost effective to transfer the MSW from local refuse collection trucks to 

large over-the-road trucks for transportation to the biofuel production facility. Once again, no 

secondary storage would be required due to the consistent availability of MSW. In this case, 

however, the biofuel producer would have to arrange for the transportation of recovered 

recyclable materials, as well as contaminated waste that cannot be used to produce biofuels. 

1.3.2.3 Wood Residue Transportation 

Wood residues are expected to be collected from the places they are produced, the 

primary or secondary mill for mill residues and the roadside of the forestry operation for forest 

residue and forest thinnings, and transported directly to the biofuel production facility in large 

over-the-road trucks. For each of the three types of wood residues we expect that the wood will 

be chipped or processed in some other way to increase the density of the residue before 

transportation. This will reduce transportation costs by allowing a greater mass of wood residue 

to be transported by each truck. As with MSW, secondary storage is unlikely to be necessary for 

wood residues as they are available to be harvested throughout the year. 

1.3.2.4 Agricultural Residue and Energy Crop Transportation and Storage 

Unlike MSW and wood residues, which are available to be harvested and collected 

throughout the course of the year, agricultural residues and herbaceous energy crops are 

harvested on an annual or semi-annual basis. As a result, a large amount of feedstock, enough to 

supply the biofuel production facility for a whole year, must be stored and delivered throughout 

the year. We expect secondary storage sites, as described above, will be the best option. 

Following the baling operation, the bales of agricultural residue or energy crops 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 today. 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 1.3.2.1). 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. Grinding the baled feedstock before transportation to 

the biofuel production facility would increase the density of the feedstock, and therefore increase 

the mass that each truck could transport and lower the overall transportation costs. 

As discussed in Section 1.3.1.2, we anticipate that the corn stover harvest could become a 

single-pass operation by 2022. In this case corn stover would be transported from the farm to a 

specialized cellulosic feedstock depot to be processed. Equipment at the would chop and dry the 

corn stover. This distributed preprocessing facility can provide significant cost benefits by 

producing a higher value cellulosic feedstock with improved handling, transporting, and 
 85

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.cxcv 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, significantly reducing dry matter losses. The biofuel producer would then 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 could have a significantly higher bulk-density than baled 

stover, which should translate into lower transportation costs. 

1.3.3 Cellulosic Feedstock Transportation and Storage Model 

In order to better estimate the impacts of transport and secondary storage on the overall 

price of cellulosic ethanol, we have developed a model that estimates the location of future 

cellulosic ethanol plants. Using these locations, we can estimate the average cost for transport of 

feedstock material both locally (within the plant-containing county) as well as imported from 

other areas in the country. The model also provides us an estimate of the type of feedstock 

material used by each plant, allowing us to determine the average cost of secondary storage for 

these materials. 

1.3.3.1 Basis and Assumptions for Transport Model 

Feedstock densities and locations have been compiled on a county basis for use within 

the model. This information has been provided by a variety of sources, including the National 

Forestry Service for forestry residue, the National Agricultural Statistical Service (NASS, 2007) 

for agricultural residues and Elliot Campbell from Stanford University for energy crops. 

Municipal solid waste is also considered for this model. For more information regarding the 

sources of data used for the model, see Section 1.1.2 of this RIA. Data for agricultural residues 

provided by NASS reported harvested grain values, and needed to be modified to reflect 

agricultural residue values, using grain to residue ratioscxcvi. Data provided from FASOM 

modeling was used in this model for total feedstock usage as well as farmside cost. 

In order to simplify the location of plants within the model, we have assumed that plants 

will be constructed at a county centroid. Therefore, transport within a county to a plant is based 

on the transport of feedstock material from farmside to the county centroid, with consideration 

for feedstock density within the county as well as the total county area. Furthermore, transport of 

feedstock between counties (for plants importing feedstock outside the county they are located 

in) is based on the distance between county centroid locations, with an additional factor to 

account for the added distance of using on-road transportation. Information regarding the costs of 

this transportation can be found in Section 4.1.1.2 of this RIA. 

Assumptions for secondary storage used in the model closely follow the determinations 

made in Section 1.3.2 above. Secondary storage costs in the model are based on the amount of 

feedstock to be stored, the density of the feedstock being stored, as well as the type of feedstock 

itself. As discussed in Section 1.3.2, the model assumes that no secondary storage is necessary 
 86

for either municipal solid waste, which would be transported to the plant directly by waste 

removal services; or for forest residue, which can be harvested year-round and transported on asneeded to the plant. Capital costs used in the model for plant selection are based on current 

refinery modeling, broken down by PADD location. These capital costs are based on the total 

production volume of the plant and the PADD that it is located within. For more information on 

transport, secondary storage, and capital costs, please refer to Section 4.1.1.2 in this RIA. 

1.3.3.2 Transport Model Operation 

The model begins operation by compiling feedstock availability (by county) based on the 

data sources discussed in Section 1.3.3.1. Using county locations, it builds a list for each county 

that contains the locations of other counties within a set maximum range (these other counties 

will be referred to as neighbors for the remainder of this section). This list will serve as the basis 

for county to county feedstock transport further on in the model operation. The model then adds 

feedstock information such as feedstock densities, total amount of feedstock available, and 

feedstock type specific to each county. Using this feedstock information, the model generates a 

list of all feedstocks available for each county; both within the county itself as well as feedstock 

available for import from other neighboring counties. At the end of this step in the model 

operation, each county has a datapoint in the model which contains a complete list of all 

feedstock available to that location.

Using the list of feedstocks available to each county generated in the last step, as well as 

the transportation and secondary storage cost assumptions discussed in Section 1.3.3.1, the 

model calculates and adds complete cost information for each feedstock available to a county. 

These costs include the farmside cost of the feedstock, the transportation required to move the 

feedstock to the centroid of its own county and the secondary storage of that feedstock. If the 

feedstock is available by import from a neighboring county, the transportation cost of moving 

that feedstock from the neighboring county is also added to the complete feedstock cost for that 

source. At the end of this step in the model operation, each county datapoint contains a list 

detailing the total cost of each feedstock available as they would be delivered to that county. 

In the next step of the model operation, the list of feedstock availability cost is used to 

choose feedstocks that a plant located at each county centroid would processes. For each county, 

the cheapest feedstock from the list is selected for the plant. The volume of feedstock available at 

this price is then converted to gallons (based on feedstock conversion modeled by FASOM) and 

added to a running count of the total volume of feedstock processed by that county. Capital costs 

associated with the increased volume are also added to the total cost of the feedstock processing 

for that county. The model continues adding feedstock sources to a county by selecting the next 

cheapest feedstock on the list. Selection proceeds until either the county either reaches a set 

maximum processing volume, or when adding another feedstock would produce a result more 

expensive on a price per gallon basis. At the end of this step, each county datapoint contains 

information regarding the cheapest total cost to produce cellulosic ethanol at that location. 

The model proceeds by scanning the entire list of county locations for the cheapest 

processing location that could be constructed. This location is added as an estimated cellulosic 

ethanol plant location for the final output of the model. The feedstock used in by location is 
 87

removed as a source from any feedstock availability list used by other counties. The model then 

repeats using this modified feedstock data, starting from the step involving the selection of 

feedstocks used in a county. In this way, a list of estimated plant locations is chosen by always 

selecting the next cheapest location in which a plant can be built; this provides the final output of 

the model. The model stops operation when the total processed volume of all locations selected 

reaches the sixteen billion gallon maximum discussed in Section 1.3.3.1. 

1.3.3.3 Final Model Output and Interpretation 

**This subsection will probably need more work in synchronization with section 4**

 Not only does the model provide estimated plant locations, it also provides 

supplementary information we have used to estimate average transportation and storage costs for 

feedstocks used by each plant, and subsequently all plants estimated by the model. Since both the 

farmside feedstock cost as well as the contribution of capital cost is known for each of the 

estimated plants (as these are inputs to the model), the transportation and storage costs can be 

calculated for each ton of feedstock processed by that plant, including county to county transport. 

The cost of transportation for each plant can then be averaged with the other plants selected by 

the model to arrive at a total transportation and storage cost average across all plants selected by 

the model. For more information about how these transportation and storage costs are used, see 

Section 4.1.2 in this RIA. 

Figure 1.3-1 

Illustration of Estimated Plant Sites Selected by Model 

Counties in black show active plant locations, counties in grey show active feedstock use 

 In Figure 1.3-1 above, an illustration of the plant locations selected by the model can be 

seen. It is important to note that the above average number of plants selected for the southern 
 88

region of the United States is most likely due to the lower capital costs associated within the this 

region. The model takes into account regional variations of plant construction and operation 

costs. The lower capital cost in the southern region (most likely due to existing construction 

infrastructure for conventional oil refineries) reduces the overall price of plants selected in these 

locations, and we feel explains why the model has a preference for this region of the country. 

More specific information on these capital cost regions can be found in Section 4.1.1.2 of this 

RIA. 

 The model was run multiple times using differing values for total feedstock availabilities 

as well as the percentage of feedstock associated with each type. We have selected the model 

output that most closely matches the output for feedstock usage provided by the FASOM model, 

as we feel that it is important to keep the feedstock usage quantities consistent across our 

analyses. However, as improved input factors and estimates are developed over time, the model 

can be easily adjusted and updated to take into account this new information. 

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. 
 89

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. 

1.4.1.1 Dry Milling Technology197 

 

 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, 
 90

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. The result is 200-proof anhydrous 

(waterless) ethanol. At this point, a denaturant, which typically is natural gas liquids, 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. 

 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. 
 91

Figure 1.4-2. Dry Milling Process 

1.4.1.2 Wet Milling Technology198 

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 
 92

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 exploring new technologies with the potential to 

increase their profits by producing higher value co-products and reducing the ethanol plants 

energy requirements. Dry fractionation and corn oil extraction seek to recover the oil in the corn 

kernel for sale in the food, feed, or biodiesel markets. Cold starch fermentation and membranes 

that reduce ethanol distillation energy requirements are two of several new technologies focusing 

on reducing the energy usage of ethanol production facilities. 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. 

Dry Fractionation 
 93

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 the small, non-fermentable part of the kernel consisting primarily 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. 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 

by up to 30%. 

While the production capacity of the plant increases with the addition of dry 

fractionation, the amount of corn used to produce a gallon of ethanol increases by approximately 

2-3% due to starch loss in the fractionation process. Dry fractionation is also a capital intensive 

process, costing an estimated $35 million to add to an existing 100 million gallon per year 

ethanol plant. Dry fractionation is currently able to recover 50% or more of the corn oil 

contained in the corn kernel. For our economic analyses we have assumed an oil recovery rate of 

50% for ethanol plants that use dry fractionation. Several companies, including ICM, Delta-T, 

and POET currently offer dry fractionation options for new or existing plants. 

Corn Oil Extraction199 

An alternative method to recovering the oil contained in the corn kernel is corn oil 

extraction. Corn oil extraction is a method of mechanical separation, often by centrifuge, used to 

extract the crude corn oil from the thin stillage (the non-ethanol liquid left after fermentation), 

the DGS before it has been dried, or a combination of both. 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. We estimate that adding 

corn oil extraction equipment to an existing 100 million gallon per year corn ethanol plant would 

cost between $5 million and $12 million, depending on the type of equipment used and the 

percentage of oil recovered. The starch losses associated with dry fractionation do not occur 

with corn oil extraction as the whole kernel still goes through the fermentation process. The 

gains in plant capacity and reduced enzyme usage of the dry fractionation process are similarly 

not realized. 

The oil recovered using the corn oil extraction process is distressed oil and cannot be sold 

as a food grade product. Markets for this product do exist, however, as an additive to cattle feed 

or as a biodiesel feedstock. In addition to generating an additional revenue stream, extracting the 

corn oil has several other benefits for the ethanol producer. Because the oil is an insulator, 

removing it improves the heating efficiency of the DGS dryers and reduces the energy demand 

of the ethanol plant. Reducing the oil content of the DGS also improves its flowability and 
 94

concentrates its protein content. The de-fatted DGS is potentially more marketable than DGS 

containing corn oil, as higher quantities may be able to be included in the diets of poultry and 

swine. Several ethanol producers are currently using corn oil extraction technology and have 

reported oil recovery rates of greater than 33%. Technology providers have indicated that in the 

near future they expect to be able to extract up to 75% of the oil contained in the kernel. For our 

economic analyses we have assumed that by 2022 ethanol production plants using oil extraction 

technology will be able to extract 66% of the oil in the corn.

Cold Starch Fermentation200201 

 POET Biorefining, the United States’ largest corn ethanol producerW, 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 least 20 POET plants currently utilize 

the BPXTM cold starch fermentation technology. 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. 

 As with any new process there are several potential drawbacks to cold starch 

fermentation. Because heat is not used to aid in the hydrolysis of starch, more enzymes may be 

required. These additional enzymes may cost the ethanol producer more than $500,000 per year 

for a 100 million gallon per year plant. An additional benefit of the cooking process is that it 

sterilizes the starch slurry before fermentation, killing microorganisms and neutralizing toxins 

that are often contained in the corn. Without this step, the microorganisms may compete with 

the yeast, lowering ethanol yields. Toxins may pass through the process to the DGS and cause 

problems with the animals that eat it. One way to minimize these problems is to treat the starch 

slurry with antibiotics, however recently this practice has been criticized for contributing to 

antibiotic tolerant or resistant bacteria. Any ethanol producer considering using cold starch 

fermentation must first determine whether the potential gains in ethanol yields and energy 

savings outweigh these risks. 

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 

 

W At the time of our November 299 plant assessment. For more information, refer to Section 1.5.1.1. 
 95

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. 

Combined Heat and Power202

 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).X However a growing number of 

ethanol 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. 

 

X 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. 
 96

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. Grants are available for industries looking to use CHP at both the state 

and national level. These grant programs will likely encourage a greater adoption of CHP among 

ethanol producers than would have otherwise been expected. We expect 26% of ethanol plants 

to use CHP, either solely owned or in partnership with a local utility company. 

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 

syrup), manure biogas (methane from nearby animal feedlots), and landfill gas (generated from 

the digestion of municipal solid waste). One potential alternative boiler fuel is biogas produced 

by the anaerobic digestion of the stillage in the ethanol production process. Sending the stillage 

to an anaerobic digester rather than drying it and selling it as DGS would produce sufficient 

biogas to exceed the energy requirements of the ethanol production facility. Excess methane 

could be sold to provide an additional revenue stream, however all revenue from DGS sales 

would be lost. Whether or not these systems are adopted in the future is likely to be dependent 
 97

on the relative prices of electricity, natural gas, and DGS, as well as the capital costs of these 

systems. 

 For a breakdown of current and near-termY 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 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 the juice 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 done by addition of cyclohexane or by the 

use molecular sieves. See Figure 1.4.5 for a diagram of the sugarcane ethanol and sugar 

production process.203 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

 

Y Based on current company plants.
 98

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 in Brazil is not currently harvested (it is typically burned in the field); however, 

it is anticipated to be collected for use in the future (i.e. 2020 and beyond) since the burning of 

sugarcane in Brazil is being phased-out and there is an increased mechanization of harvesting 

sugarcane. In the U.S., sugarcane trash is currently mechanically harvested and delivered to the 

factory with stalks. The collection and use of trash at the sugarcane ethanol facility is beneficial 

as greater electricity can be produced and potentially sold to the grid. 

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 

its use to produce steam for electricity. 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, most facilities are able to produce more energy than needed and have exported excess 

electricity to the grid. This is further discussed in Chapter 2 in the lifecycle section, as surplus 

electricity production displaces primarily fossil-based electricity production. 

Filter Cake Mud 

Filter cake is the dried, leftover solid material from precipitated mud after 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. Some countries are allowed to spray vinasse on sugarcane 

crops as fertilizer. For instance, it is produced and used throughout the harvest in Brazil but is 

not allowed in the U.S. Environmental legislation prohibits inappropriate disposal of vinasse 

into rivers, lakes, the ocean, and soils. 

 

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. 
 99

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. Lumber 

production decreased following World War I, which resulted in the closing down of cellulosic 

plants.204, 205 Although corn-grain ethanol was used in the early 20th Century, especially by highperformance 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 or liquid oil 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.206 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.207 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 (waterrepelling) agent in cell walls.208 Cellulose and hemicellulose are made up of sugars 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. 
 100

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.209 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 
 101

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 10,000.210 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.211 

 To review, a significant part of the reason it is more difficult and more costly to produce 

ethanol from cellulosic feedstocks, 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.212 

 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 into alcohol. These are two of the major problems that must be 

satisfactorily resolved for biochemical conversion of cellulosic feedstocks. 

 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.213 Concentrated acid 

hydrolysis is typically much faster than enzymatic approaches, albeit at the cost of reduced sugar 

yields due to undesirable side reactions.214 Enzymatic hydrolysis is mostly suitable for 

homogeneous mixtures because specific enzymes are needed to convert a given type of 

feedstock. The cost to enzymatically hydrolyze cellulose is expected to decline significantly as 

these technologies continue to improve.215 

In general, steps of the biochemical process include: feedstock pretreatment, hydrolysis, 

saccharification and fermentation, ethanol dehydration, and lignin recovery. Refer to Figure 1.4-

6 for an illustration of the enzymatic biochemical production process. We used NREL’s study as 
 102

a guide to describe, somewhat generically, how such a process might work. Refer to the NREL 

technical documents for greater detail.216,217

 

Figure 1.4-6. 

Cellulosic Ethanol Biochemical Production Process (Enzymatic) 

Stage 1 – Feedstock Pretreatment 

 

Lignocellulosic biomass 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 may 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.218 

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 

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.219 
 103

 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 

enzymes.220,221 These chemicals cause the biomass to react quite differently.222 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.223 For more information on feedstock considerations and their impacts on 

biorefining refer to the NREL report completed for the final rule.224 

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, mannan, arabinan and galactan, to produce the mixed sugars and further 

helps prepare the cellulose for hydrolysis. A small amount of glucan in the hemicellulose and in 

the cellulose is converted into glucose. 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 insolubles, 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 

enzyme cocktail, saccharification of the cellulose to glucose occurs first at an elevated 
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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.225,226,227 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 on it. This continues to be high on the list of challenges researchers are working on, but 

good progress has been made toward fermenting a higher percentage of xylose during the past 

few years.228

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.229

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 
 105

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 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.230 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.231 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, wood residues, 

and municipal solid waste are all being considered as potential feedstocks. Geographic location, 

availability of biomass, the existence of biomass suppliers, and costs would all likely influence 

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. For greater detail on the thermochemical mixedalcohols route refer to NREL technical documentation.232 
 106

Figure 1.4-7. 

 Cellulosic Ethanol Thermochemical Gasification Process 

Stage 1 – Feedstock Handling 

 The particle size requirement for a thermochemical process is around 10-mm to 100-mm 

in diameter.233 Once the feed is ground to the proper size, flue gases from the char combustor 

and tar reformer catalyst regenerator dry the feed from the as received moisture level of around 

30% to 50% 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 

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 
 107

advantage of not requiring oxygen, most operate at low pressure and therefore require product 

gas compression for downstream purification and synthesis unit operations. 234,235 

 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.

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 
 108

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 are high in methanol, but 

contain a wide distribution of several different alcohols. One 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 process.236

For the final rule, we worked with NREL to develop the thermochemical mixed-alcohols model 

for the 2015 and 2022 timeframe, as discussed in greater detail in the technical document.237 The 

analyses were used to inform us of the materials and energy use for these technologies for our 

lifecycle analyses discussed in Chapter 2. 

 In contrast to the catalytic processing of syngas to produce fuels there is also a 

fermentation process being pursued that utilizes a special microorganism (Clostridium 

ljungdahlii) to convert the syngas to ethanol.238 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.239 

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.240

1.4.3.2 Cellulosic Diesel 

 Cellulosic diesel fuel tecnologies convert cellulosic feedstocks to diesel fuel. There 

could be a whole set of technologies which fall in this category including thermochemical and 

other chemical processes and biochemical processes. 
 109

BTL Technology 

 One important cellulosic diesel fuel technology is a thermochemical process which is also 

termed biomass-to-liquids (BTL). Like the thermochemical ethanol process described 

previously, the BTL process produces a syngas from biomass. However, instead of reacting the 

syncas to alcohol, the syngas is fed to a Fischer-Tropsch (FT) reactor to primarily produce diesel 

fuel and some naphtha.241 

 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. 

 Figure 1.4-8 is a block diagram of a BTL process. 

Figure 1.4-8. 

 Biomass to Liquids (BTL) Thermochemical Gasification Process 

 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 syngas is sent to a water gas shift reactor (WGS) 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. 
 110

 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 a variety of hydrocarbons that boil over a wide distillation range (a mix of heavy and light 

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. 

Pyrolysis Diesel Fuel and Gasoline

 Pyrolysis oils, or bio-oils, are produced by decomposing cellulosic biomass at lower 

temperatures than the gasification process, thus producing a liquid oil instead of a synthesis 

gas.

242 The reaction can occur either with or without the use of catalysts, but it occurs without 

any additional oxygen being present. 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, however, 

very little has been done in terms of optimizing the process, and as such, there are still many 

possibilities yet to be explored.243 One of the finished fuels produced by the pyrolysis process is 

diesel fuel, however, a significant amount of gasoline would likely be produced as well. 

1.4.3.3 Developing Technologies 

 When evaluating the array of biofuel technologies which could produce one or more fuels 

that could qualify under RFS2, we found that it is helpful to organize them into fuel technology 

categories. Organizing them into categories eases the task of understanding the costs and life 

cycle impacts of these technologies because like technologies likely have similar cost and life 

cycle impacts. The simplest organization is by the fuel produced. However, we frequently 

found that additional subdivisions were also helpful. Table 1.4-1 provides a list of technologies, 

the cellulosic fuels produced and a list of many of the companies which we learned are pursuing 

the technology (or something very similar to the technology listed in the category). 
 111

Table 1.4-1 

List of Biofuel Categories, the Fuels Produced and the Companies Pursuing the 

Technologies 

Technology Category Fuels Produced Companies 

Biochemical from Corn Grain Ethanol ICM, Delta T, Broin 

Biochemical Cellulosic Ethanol Ethanol Abengoa, AE Fuels, Cornell Univ., Citrus Energy, 

DuPont/Danisco, Florida Crystals, Novenzymes, 

Poet, Western Biomass, ICM, Alltech/Ecofin, 

IOGEN, Qteros, and Raven Biofuels, BPI, New Age 

Energy, Universal, Fiberight, KL Energy. 

Thermochemical/Catalytic 

conversion of Cellulose 

Ethanol Range Fuels, Pearson Technologies, Fulcrum 

Bioenergy, Enerkem, and Gulf Coast Energy. 

Thermochemical/Biochemical 

conversion of Cellulose 

Ethanol Coskata and INEOS Bio. 

Strong Acid Hydrolysis of 

Cellulose/Biochemical 

Ethanol Blue Fire, Arkenol, Pencor, Pangen, Auburn Univ., 

Agresti. 

Dilute Acid, Steam Explosion of 

Cellulose/Biochemical 

Ethanol Verenium, BP, Central Minnesota Ethanol Coop. 

Consolidated Bioprocessing (one 

step hydrolysis and fermentation) of 

Cellulose/Biochemical 

Ethanol Mascoma 

Biochemical conversion of Cellulose 

via carboxylic acid 

Ethanol, Gasoline, 

Jet Fuel, Diesel 

Fuel 

Terrabon, Swift Fuels, Zeachem 

Thermochemical/Fischer Tropsch Diesel Fuel and 

Naphtha 

Choren, Flambeau River Biofuels, Baard, Clearfuels, 

Gulf Coast Energy, Rentech, TRI. 

Thermochemical/Fischer Tropsch DME Chemrec, New Page. 

Catalytic Depolymerization of 

Cellulose 

Diesel, Jet Fuel or 

Naphtha 

Cello Energy 

Biochemical conversion of Cellulose Diesel, Jet Fuel or 

Naphtha 

Bell Bioenergy 

Catalytic Reforming of Sugars Gasoline Virent 

Biochemical conversion of Sugars Diesel, Jet Fuel or 

Gasoline 

Amyris, Gevo, LS9. 

Biochemial of Sugars – converted 

corn ethanol plants 

Isobutanol Gevo/ICM. 

Pyrolysis of Cellulose Diesel, Jet Fuel, or 

Gasoline, 

Envergent (UOP/Ensyn), Dynamotive, Petrobras, 

Univ. of Mass, KIOR. 

Hydrotreating of Plant Oils Renewable Diesel 

Fuel 

UOP, Neste, Eni,Conoco-Phillips, Dynamic Fuels 

(Syntroleum/Tyson). 

Fatty Acid Methyl Ester (FAME) Biodiesel Many 

Free Fatty Acid to Biodiesel Biodiesel Endicott 

Production of Algae Oils via 

Photobioreactor or open pond 

Algae Oil 

(Biodiesel or 

Renewable Diesel 

Fuel) 

Solazyme, Algenol, Aurora Biofuels, Petrosun, 

Sapphire Energy, Livefuels, Solix, HR Biopetroleum 

(Cellana), XL Renewables, Petroalgae, Synthetic 

Genomics, GreenFuel. 

 

 Of the technologies listed above, many of them are considered to be “second generation” 

biofuels or new biofuel technologies capable of meeting either the advanced biofuel or cellulosic 

biofuel RFS standard. The following sections describe specific companies and the new biofuel 

technologies which the companies have developed or are developing. This summary is not 
 112

meant to be an unabridged list of new biofuel technologies, but rather a description of some of 

the more prominent or interesting of the new biofuel technologies that serve to provide a sense of 

the technology categories listed above. The process technology summaries are based on 

information provided by the respective companies. EPA has not been able to confirm all of the 

information, statements, process conditions, and the process flow steps necessary for any of these 

processes and companies. 

Sugar to Diesel Fuel - Amyris Biotechnologies 

 The Amyris technology produces hydrocarbon fuels from sugars through biochemical 

reactions. The technology uses custom designed yeast cells and is modular in design and can be 

collocated with existing ethanol plants to produce diesel fuel and gasoline. 

 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 starch ethanol, which could be sugar cane 

or corn grain. Amyris has a 100 gallon per week pilot plant operating in Emeryville, CA, and in 

mid-2009 has completed construction of a pilot plant as well as a commercial demonstration 

plant in Brazil to showcase their technology. Amyris intends to convert its own sugar cane mills 

over with this technology starting in 2011. In 2012, Amyris expects to begin converting sugar 

cane mills owned by others with its sugar to hydrocarbon technology. 

 The diesel fuel capable of being produced from the process is compatible with the 

existing petroleum distribution system and provides better storage and cold flow properties than 

biodiesel. 

Biochemical to Diesel Fuel - Bell Bio-Energy 

 Bell Bio-Energy has developed a biochemical technology which uses genetically 

engineered bacteria to convert cellulosic feedstocks directly to synthetic hydrocarbon fuels and 

compost. 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, an eight carbon hydrocarbon molecule that boils 

within the distillation temperature range of gasoline. 

 

 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, however, of the original 7 conceived 

pilot plants, only one pilot plant was built at Fort Stewart in Georgia. The Fort Stewart pilot 

plant began operating in late 2008. Bell Bioenergy intends on starting up two demonstration 

plants – one associated with the University of California in Fresno, the other with the City of 

Atlanta. The primary output of these plants will be compost, however, these two plants are also 

expected to produce 1 to 2 million gallons of diesel fuel on an annual basis. 
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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 to 60 days to fully digest the cellulose. The 

produced fuel is constantly removed from the reaction vessel, and a significant amount of 

organic material is also produced which will be marketed as potting soil. The process is 

expected to produce 30 to 40 gallons of renewable product per ton of feedstock and the 

simplicity of the process results in low capital costs per volume produced. 

Strong Acid Hydrolysis/Biochemical - BlueFire Ethanol 

 BlueFire Ethanol has a commercial strong 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. 

 BlueFire has successfully operated a pilot plant for six 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. As of the third quarter of 2009, BlueFire had obtained 

the permits to build this facility and was seeking additional funding and bids for the construction 

of the plant. The plant is expected to start up in 2011 or 2012 and will produce up to 3.9 million 

gallons of cellulosic ethanol per year from municipal solid waste (MSW). BlueFire is planning 

to start up another cellulosic ethanol plant which they call their Mecca or El Sobrante plant also 

using MSW as feedstock. Although this plant was initially envisioned to be located in California, 

it is likely that this plant will be built elsewhere in the U.S. No start up date has been announced 

for their Mecca plant. 

Chemical Depolymerization - Cello-Energy 
 114

 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 the process needs. The only energy input is electricity - no natural 

gas or 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 is claimed to only incur 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 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 demonstration 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. As of late 2009, the plant is operational, however, the production volumes are still very 

low. Cello is working to increase the production volume of its plant. According to the company, 

they are currently working to resolve materials handling and processing issues that surfaced 

when they attempted to scale up production to 20 MGY from a previously operated 

demonstration plant. As of November 2009, they had ordered new equipment and are waiting 

for it to arrive and be installed which they hoped would allow for operations to be restarted as 

early as February or March, 2010. Cello energy already has chosen locations to construct and 

start up two 50 million gallons per year plants by early 2011, though these are on hold until the 

Bay Minette facility is operational. This includes a facility in conjunction with the State of 

Georgia Energy Innovation Center, and one additional plant in Alabama. Cello explained that 

they will use prefabrication techniques so that these plants can readily be constructed, shipped 

and installed anywhere in the U.S. 

Thermochemial/Fischer Tropsch - Choren 

 
 115

 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 temperatures 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 produce primarily diesel fuel. 

 Choren will be 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. 

Thermochemical/Biochemical - 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 carbonaceous 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 

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 other cellulosic and corn based production methods. 
 116

Initial ethanol production cost estimates are lower than the biochemical and thermochemical 

cellulosic technologies described in previously in Subsections 1.4.3.1 and 1.4.3.2. 

 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 provide 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 its larger 40,000 gallon per 

year pilot plant became operational in 2009 in Madison, Pennsylvania. Coskata is targeting to 

design and build a 50 million gallons per year commercial demonstration plant that it expects to 

be operational in 2011. 

Pyrolysis - 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 biooil 

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 reactor temperatures of about 400-500 degrees Celsius. 

 Dynamotive has two small demonstration plants. One demonstration plant is located in 

Guelph, Ontario, Canada and its capacity is 66,000 dry tons of biomass a year with an energy 

output equivalent to 130,000 barrels of oil. The other of its demonstration plants is located in 

West Lorne Ontario, Canada. This plant started operation in early 2005 using waste sawdust as a 

feedstock. The West Lorne plant has a capacity to convert 130 tonnes of biomass into BioOil per 

day which, if proportional to the Guelph plant, translates to an energy-equivalent of 84,500 

barrels of oil per year. The BioOil production capacity between the two plants is estimated at 

around 9 MGY of bioOil, but both plants are currently operating at a fraction of their rated 

capacity. However, according to a recent press release, Dynamotive has contracts in place to 

supply a U.S.-based client with at least nine shipments of BioOil in 2010. Although Dynamotive 
 117

has been working on a technology for converting its biooil to transportation fuels, they have not 

announced plans for building such a facility 

Biochemical Ethanol - 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. 

Biochemical Ethanol – Iogen, KL Energy, DuPont Danisco, Fiberight 

 Like Poet, Iogen is pursuing a biochemical cellulosic ethanol technology very similar to 

the biochemical pathway described in previously in Section 1.4.3. utilizing their own proprietary 

enzymes. Iogen opened the first commercial demonstration cellulosic ethanol plant in North 

America. Iogen’s plant located in Ottawa, Canada has been producing cellulosic ethanol from 

wheat straw since 2004. Iogen has slowly been ramping up production at its 0.5 MGY plant. 

According to the company’s website, they produced approximately 24,000 gallons in 2004 and 

34,000 gallons in 2005. Production dropped dramatically in 2006 and 2007 but came back 

strong with 55,000 gallons in 2008. Up to the last quarter of 2009, Iogen has produced over 

127,000 gallons of ethanol from their demonstration plant. 

Iogen also recently became the first cellulosic ethanol producer to sell its advanced 

biofuel at a retail service station in Canada. Their cellulosic ethanol was blended to make E10 

available for sale to the consumers at an Ottawa Shell station. Iogen also recently announced 

plans to build its first commercial scale plant in Prince Albert, Saskatchewan in the 2011/2012 

timeframe. 

KL Energy Corporation (KL Energy), through its majority-owned Western Biomass 

Energy, LLC (WBE) located in Upton, WY, is designed to convert wood products and wood 

waste products into ethanol using a biochemical pathway similar to that described previously in 

Section 1.4.3. Since the end of construction in September 2007, equipment commissioning and 

process revisions continued until the October 2009 startup. The plant was built as a 1.5 MGY 

demonstration plant and was designed to both facilitate research and operate commercially. It is 

KL Energy’s intent that WBE’s future use will involve the production and sale of small but 

commercial-quality volumes of ethanol and lignin co-product. The company’s current 2010 

production goal is for WBE to generate RINs under the RFS2 program. 
 118

 DuPont Danisco Cellulosic Ethanol, LLC (DDCE), a joint venture between Dupont and 

Danisco, is another company pursuing biochemical conversion of cellulosic material into 

ethanol. DDCE received funding from the State of Tennessee and the University of Tennessee to 

build a small 0.25 MGY demonstration plant in Vonore, TN to pursue switchgrass-to-ethanol 

production. According to DDCE, construction commenced in October 2008 and the plant is now 

mechanically complete and currently undergoing start-up operations. The facility is scheduled to 

come online in January and the company hopes to operate at or around 50% of production 

capacity in 2010. According to the DDCE, the objective in Vonore is to validate processes and 

data for commercial scale-up. 

 

 Fiberight, LLC (Fiberight) is yet another company pursing cellulosic ethanol from a 

biochemical process, but using MSW as a feedstock. According to Fiberight, they have been 

operating a pilot-scale facility in Lawrenceville, VA for three years. They have developed a 

proprietary process that not only fractionates MSW but biologically converts the non-recyclable 

portion into cellulosic ethanol and biochemicals. Fiberight recently purchased a shut down corn 

ethanol plant in Blairstown, IA and plans to convert it to become MSW-to-ethanol capable. 

According to the company, construction is currently underway and the goal is to bring the 2 

MGY demo plant online by February or March, 2010. Fiberight’s long-term goal is to expand 

the Blairstown plant to a 5-8 MGY capacity and build other small commercial plants around the 

country that could convert MSW into fuel. 

Thermochemical Ethanol - Range Fuels and Enerkem 

 Range Fuels produces cellulosic ethanol via a two step thermochemical process. Their 

technology converts biomass to syngas followed by catalytic conversion of the syngas to 

alcohols. Range claims that their technology is capable of producing more ethanol than other 

cellulosic technologies based on yields per energy input. They utilize 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 methanol, which are then converted in an additional 

reactor into ethanol. 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. In its initial phase, the Range plant is expected to produce 4 million gallons 

per year of methanol. After the company is confident in its operations, Range will begin efforts 

to expand the plant and add additional reaction capacity to convert the methanol to ethanol. 

Enerkem is another company like Range Fuels pursuing cellulosic ethanol production via 

the thermochemical route. The Canadian-based company was recently announced as a recipient 
 119

of a $50 million grant from DOE to build a 10 MGY woody biomass-to-ethanol plant in 

Pontotoc, MS. The U.S. plant is not scheduled to come online until 2012, but Enerkem is 

currently building a 1.3 MGY demonstration plant in Westbury, Quebec. According to the 

company, plant construction in Westbury started in October 2007 and the facility is currently 

scheduled to come online around the middle of 2010. While it’s unclear at this time whether the 

cellulosic ethanol produced will be exported to the United States, Enerkem has expressed interest 

in selling its fuel commercially. 

Reforming of Sugars to Gasoline - Virent Bioreforming 

 Virent is pursuing a process called “Bioforming” which 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 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 many 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. 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

1.4.4.1 Biodiesel 

 Plant oils and animal fats are triglycerides, 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 1.4-9). 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 coproduct 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. 
 120

Figure 1.4-9. Overview of biodiesel conversion process 

 In the case of feedstocks containing more than a few percent free fatty acids (FFAs), such 

as rendered fats, waste greases, or corn oil extracted after ethanol production, addition of base 

will result in the formation of soap, an undesirable process contaminate when present above trace 

levels. To avoid this, these feedstocks must 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 coproduct and unreacted alcohol and catalyst are recovered. At that point the biodiesel is subjected 

to quality control testing and then released for sale. Figure 1.4-10 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 only a very small fraction of biodiesel 

production is distilled. 244

+

transesterification

methyl esters

(biodiesel)

glycerin

triglyceride

+

transesterification

methyl esters

(biodiesel)

glycerin

triglyceride
 121

Figure 1.4-10. Schematic of typical biodiesel production from virgin plant oil

 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 already 

sufficient existing U.S. capacity to produce all the biodiesel required to meet the biomass-based 

diesel standard put forth in EISA. 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. 

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

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
 122

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. 

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. 

1.4.4.2 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 co-products. The reactions can 

also saturate the olefin bonds in the feedstock oils, converting them to paraffins; additional steps 

can also be taken to isomerize a portion of the paraffins to create fuels with varying properties. 

All of these reactions consume significant amounts of hydrogen. The yield of these reactions to 

the primary product (diesel) 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 

we assume approximately 90% yield to diesel, with the remainder split between light fuel gas 

and naphtha. Figure 1.4-11 shows a flow diagram of the primary steps of renewable diesel 

production. 
 123

Figure 1.4-11. Process flow diagram of primary steps in renewable diesel production 

Renewable diesel can 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 or a chemical operation with excess hydrogen 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 trace metals that may poison hydrotreating 

catalysts. 

For a period during 2007 and 2008, ConocoPhilips produced some (300-500 bbl/day) 

renewable diesel at their Borger, Texas, refinery from beef tallow generated by Tyson Foods, 

Inc. in Amarillo, Texas. 245 In fall of 2008, Dynamic Fuels, LLC (a joint venture of Syntroleum 

Corp. and Tyson Foods, Inc.) announced construction of 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 Bio-Synfining process. Start-up is scheduled for mid-2010, with the primary 

product being high-quality diesel fuel that will be fungible within the existing petroleum supply 

system. 246 This facility plans to utilize supplies of hydrogen available in the industrial area 

where it will be located, as well as rail and shipping infrastructure already in place nearby. 247

 Syntroleum Corp was founded in 1984 and holds a number of patents in gas-to-liquids 

and biomass-to-liquids conversion processes. One such process has the trade name Synfining, 

and upgrades Fischer-Tropsch paraffins to isomers with properties more favorable for diesel fuel. 

S, N, 

metal 

removal

Mixed grease 

feedstock

Hydrogen

Heat in

Flash 

separator

Heat out

Liquid fuel for 

blending or further 

separation

Water, light 

hydrocarbons

Hydrotreating 

reactor

S, N, 

metal 

removal

Mixed grease 

feedstock

Hydrogen

Heat in

Flash 

separator

Heat out

Liquid fuel for 

blending or further 

separation

Water, light 

hydrocarbons

Hydrotreating 

reactor
 124

They have further adapted this process to use a variety of fats and oils as feedstocks, calling it 

Bio-Synfining. It is this technology 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. 248

 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 discuss the current state of the biofuel industry and how production 

might grow in the future under the RFS2 program based on our volume assumptions. The bulk 

of the discussion focuses on corn ethanol, imported sugarcane-based ethanol and conventional 

FAME-based biodiesel, today’s most established U.S. biofuel sources. However, we also 

discuss renewable diesel, cellulosic diesel, algae-based biodiesel and other up-and-coming 

second generation biofuels that are likely to develop during the course of the RFS2 program. 

 In the subsections that follow, we’ll discuss corn ethanol and how the industry might look 

once it finishes building out production capacity to 15 billion gallons and employs 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. Domestic sugarcane- and sweet sorghum-based ethanol plants could also 

contribute to meeting the advanced biofuel standard in EISA. Following this discussion, we will 

characterize the present state of the cellulosic biofiuel industry and talk about the projected 

timeline for commercialization based on industry plans and technological breakthroughs aided 

by state and federal grants, tax incentives, and loan guarantee programs. As part of this 

discussion we will describe our assessment of the cellulosic industry in the context of setting the 

standard for 2010. 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 along with renewable diesel and algae-based biodiesel. 

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 RFS2 program. 
 125

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 nine billion gallons of fuel ethanol for domestic consumption, the majority of which 

came from domestically-grown corn.249 The nation is currently on track for producing over 10 

billion gallons by the end of 2009.26 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)27, elevated crude oil prices, state mandates and tax incentives, the 

introduction of the Federal Volume Ethanol Excise Tax Credit (VEETC)28, the implementation 

of the existing RFS1 program,29 and the new volumes established under EISA. As shown in 

Figure 1.5-1, U.S. ethanol production has grown exponentially over the past decade. 

Figure 1.5-1. 

Historical Growth in U.S. Corn/Starch Ethanol Production250

1.4 1.6 1.7

2.0

2.7

3.3

3.8

4.6

6.3

9.0

0

1

2

3

4

5

6

7

8

9

10

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

Year

Corn/Starch Ethanol Production (Bgal)

 

26 Based on total transportation ethanol reported in EIA’s September 2009 Monthly Energy Review (Table 10.2) 

less imports (http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm). 

27 Based on fuel ethanol from EIA’s October 2009 Short Term Energy Outlook less projected imports. 

28 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. 29 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. 
 126

 As of November 2009 there were 180 corn/starch ethanol plants operating in the U.S. 

with a combined production capacity of approximately 12 billion gallons per year.30 This does 

not include idled ethanol plants, discussed later in this subsection. The majority of today’s 

ethanol production (91.5% by volume) is produced exclusively from corn. Another 8.3% comes 

from a blend of corn and/or similarly-processed grains (milo, wheat, or barley) and less than half 

a percent is produced from small plants processing waste beverages or other waste sugars and 

starches. A summary of U.S. ethanol production by feedstock is presented in Table 1.5-1. 

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 10,994 91.5% 155 86.1%

Corn, Milob 817 6.8% 15 8.3%

Corn, Wheat 130 1.1% 1 0.6%

Milo 3 0.0% 1 0.6%

Wheat, Milo 50 0.4% 1 0.6%

Waste Beveragesc 20 0.2% 5 2.8%

Waste Sugars & Starchesd 7 0.1% 2 1.1%

Total 12,020 100% 180 100%

a

Includes one facility processing seed corn, one facility operating a pilot cellulosic butanol 

plant, one facility with plans to build a pilot cellulosic ethanol plant, and two facilities with 

plans to build small commercial cellulosic ethanol plants 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 180 operating plants, 173 process corn and/or other 

similarly processed grains. Of these facilities, 162 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 plants using front-end fractionation to 

produce food-grade corn oil or back-end extraction to produce fuel-grade corn oil for the 

biodiesel industry. A company called Greenshift has a patented and patent-pending corn oil 

extraction technology that is currently employed at five ethanol plants in Michigan, Indiana, 

 

30 Our November 2009 corn/starch ethanol industry characterization was based on a variety of sources including: 

Renewable Fuels Association (RFA) Ethanol Biorefinery Locations (updated October 22, 2009); Ethanol Producer 

Magazine (EPM) Producing plant list (last modified on October 22, 2009), ethanol producer websites, press releases, 

and follow-up correspondence. The baseline does not include ethanol plants whose primary business is industrial or 

food-grade ethanol production nor does it include plants that might be located in the Virgin Islands or U.S. 

territories. Where applicable, current/historic production levels have been used in lieu of nameplate capacities to 

estimate production capacity. 
 127

New York and Wisconsin.31 Collectively, these facilities are designed to extract in excess of 7.3 

million gallons of corn oil per year. Primafuel Solutions is another company offering corn oil 

extraction technologies to make existing ethanol plants more sustainable. For more information 

on corn oil extraction and other advanced technologies being pursued by today’s corn ethanol 

industry, refer to Section 1.4.1 of the RIA 

 In contrast to 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, 11.4% 

of the current grain ethanol production comes from the 11 previously-mentioned wet mill 

facilities listed in Table 1.5-2. 

Table 1.5-2. 

Existing Wet Mill Corn Ethanol Plants 

Ethanol Plant/Company Location

Capacity

MGY

% of Tot

Capacity

Archer Daniels Midlanda Cedar Rapids, IA 250 2.1%

Archer Daniels Midlanda Clinton, IA 190 1.6%

Archer Daniels Midlanda Columbus, NE 95 0.8%

Archer Daniels Midlanda Decatur, IL 290 2.4%

Archer Daniels Midlanda Marshall, MN 40 0.3%

Aventine Renewable Energy Pekin, IL 100 0.8%

Cargill, Inc. Eddyville, IA 35 0.3%

Cargill, Inc. Blair, NE 185 1.5%

Grain Processing Corp Muscatine, IA 20 0.2%

Penford Products Cedar Rapids, IA 45 0.4%

Tate & Lyle Loudon, TN 126 1.0%

Total 1,376 11.4%

a

Estimated plant capacities.

 The remaining seven ethanol plants process 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. Due to their limited 

feedstock supplies and niche markets, these plants have a fraction of the ethanol production 

capacity as dry mill corn ethanol plants. A summary of today’s average ethanol plant sizes is 

found in Table 1.5-3 below. 

 

31 Two plants in Michigan and one in each of the other three states. All company information based on GreenShift’s 

Q2 2009 SEC filing. 
 128

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 10,618 88.3% 162 90.0% 65.5

Wet Millinga 1,376 11.4% 11 6.1% 125.1

Otherb 26 0.2% 7 3.9% 3.8

Total 12,020 100.0% 180 100.0% 66.8

a

Includes a total of three corn ethanol plants with plans to process cellulosic feedstocks in the 

future. To the extent that cellulosic facilities are integrated with existing processes, these 

plants will need additional front-end technology to supplement existing dry milling equipment.

b

Facilities that do not process traditional grain-based crops and thus do not require milling. 

Includes plants processing waste beverages or sugars and starches. 

 Ethanol production is a relatively resource-intensive process that requires the use of 

water, electricity, and steam. Steam needed to heat the process is generally produced on-site or 

by other dedicated boilers.32 The ethanol industry relies primarily on natural gas. Of today’s 

180 ethanol production facilities, an estimated 152 burn natural gas33 (exclusively), three burn a 

combination of natural gas and biomass, one burns natural gas and coal (although natural gas is 

the primary fuel), one burns a combination of natural gas, landfill biogas and wood, and two 

burn natural gas and syrup from the process. We are aware of 17 plants that burn coal as their 

primary fuel and one that burns a combination of coal and biomass.34 Our research suggests that 

two corn ethanol plants rely on a combination of waste heat and natural gas and one plant does 

not have a boiler and relies solely on waste heat from a nearby power plant. All together, our 

research suggests that 27 online plants currently utilize cogeneration or combined heat and 

power (CHP) technology, although others may exist. CHP is a mechanism for improving overall 

plant efficiency. Whether owned by the ethanol facility, their local utility, or a third party, CHP 

facilities produce their own electricity and use the waste heat from power production for process 

steam, reducing the energy intensity of ethanol production.35 A summary of the energy sources 

and CHP technology utilized by today’s ethanol plants is found in Table 1.5-4. 

 

32 Although some plants pull steam directly from a nearby utility. 

33 Facilities were assumed to burn natural gas if the plant boiler fuel was unspecified or unavailable on the public 

domain. 

34 Includes corrections from NPRM based on new information obtained on Cargill plants and Blue Flint ethanol 

plant. Also includes updated CHP and energy information provided by EPA’s Combined Heat and Power 

Partnership. 

35 For more on CHP technology, refer to Section 1.4 .1.3. 
 129

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 1,758 14.6% 17 9.4% 8

Coal, Biomass 50 0.4% 1 0.6% 0

Natural Gasb 9,706 80.7% 152 84.4% 14

Natural Gas, Biomassc 115 1.0% 3 1.7% 1

Natural Gas, Coal 35 0.3% 1 0.6% 1

Natural Gas, Landfill Biogas, Wood 110 0.9% 1 0.6% 0

Natural Gas, Syrup 101 0.8% 2 1.1% 0

Waste Heatd 50 0.4% 1 0.6% 1

Waste Heatd

, Natural Gas 96 0.8% 2 1.1% 2

Total 12,020 100.0% 180 100.0% 27

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 switch to biomass in the future.

b

Includes two facilities that might switch to biomass, one facility that intends to burn thin stillage and biogas, and 

two facilities that were once considering switching to coal in the future.

c

Includes one facility processing bran in addition to natural gas.

d

Waste heat from utility partnerships. 

 During the ethanol fermentation process, large amounts of carbon dioxide (CO2) gas are 

released. In some plants, the CO2 is vented into the atmosphere. But where local markets exist, 

it is captured, purified, and sold to the food processing industry for use in carbonated beverages 

and flash-freezing applications. We are currently aware of 40 fuel ethanol plants that recover 

CO2 or have facilities in place to do so. According to Airgas, a leading gas distributor, the U.S. 

ethanol industry currently recovers 2 to 2.5 million tons of CO2 per year which translates to 

about 5-7% of all the CO2 produced by the industry.36

 Since the majority of ethanol is made from corn, it is no surprise that most of the plants 

are located in the Midwest near the Corn Belt. Of today’s 180 ethanol production facilities, 163 

are located in the 15 states comprising PADD 2. For a map of the Petroleum Administration for 

Defense Districts or PADDs, refer to Figure 1.5-2. 

 

36 Based on information provided by Bruce Woerner at Airgas on August 14, 2009. 
 130

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 1 150 1.3% 3 1.7%

PADD 2 11,329 94.2% 163 90.6%

PADD 3 294 2.4% 4 2.2%

PADD 4 152 1.3% 7 3.9%

PADD 5 95 0.8% 3 1.7%

Total 12,020 100.0% 180 100.0%

Leading the Midwest in ethanol production are Iowa, Nebraska, Illinois, Minnesota, and 

South Dakota. Together, these five states’ 109 ethanol plants account for over two-thirds (or 

about 8.2 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 November 2009 industry assessment indicates 

that Arizona, California, Colorado, Georgia, Idaho, 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 the online ethanol 

production capacity by state is presented in Table 1.5-6. 
 131

Table 1.5-6. 

Current Corn/Starch Ethanol Production Capacity by State 

State

Capacity

MGY

% of

Capacity

No. of

Plants

% of

Plants

Iowa 3,214 26.7% 39 21.7%

Nebraska 1,560 13.0% 23 12.8%

Illinois 1,342 11.2% 13 7.2%

Minnesota 1,113 9.3% 20 11.1%

South Dakota 987 8.2% 14 7.8%

Indiana 716 6.0% 9 5.0%

Wisconsin 529 4.4% 9 5.0%

Kansas 439 3.6% 11 6.1%

North Dakota 355 3.0% 5 2.8%

Ohio 320 2.7% 5 2.8%

Missouri 261 2.2% 6 3.3%

Texas 240 2.0% 3 1.7%

Tennessee 236 2.0% 2 1.1%

Michigan 217 1.8% 4 2.2%

Colorado 138 1.1% 5 2.8%

Georgia 100 0.8% 2 1.1%

Mississippi 54 0.4% 1 0.6%

New York 50 0.4% 1 0.6%

Arizona 50 0.4% 1 0.6%

Kentucky 40 0.3% 2 1.1%

Oregon 40 0.3% 1 0.6%

Wyoming 9 0.1% 1 0.6%

California 5 0.0% 1 0.6%

Idaho 5 0.0% 1 0.6%

Oklahoma 2 0.0% 1 0.6%

Total 12,020 100.0% 180 100.0%

 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.251 Furthermore, nearly 30% of the total domestic product comes from 40 

plants owned by just three different companies – POET Biorefining, Archer Daniels Midland 

(ADM), and Valero Renewables. For a summary of ethanol production by company, refer to 

Figure 1.5-3 below. 
 132

Figure 1.5-3. 

Current Corn/Starch Ethanol Production Capacity by Company 

Green Plains Renewable 

Energy, 480

Valero Renewables, 770

Archer Daniels Midland, 

1,100

POET Biorefining, 1,535

Hawkeye Renewables, 

460

The Andersons, 275

Glacial Lakes Energy, 

LLC, 250

Aventine Renewable 

Energy, 207

BioFuel Energy Corp., 230

Other, 6,714

 

 Valero entered the ethanol industry in March of 2009 when it acquired seven ethanol 

plants from former ethanol giant, Verasun. The oil company currently has agreements in place 

to purchase three more ethanol plants that would bring the company’s ethanol production 

capacity to 1.1 billion gallons per year.37 However, ethanol plants are much smaller than 

petroleum refineries. Valero’s smallest petroleum refinery in Ardmore, OK has about twice the 

throughput of all its ethanol plants combined.38 Still, as obligated parties under RFS1 and RFS2, 

the refining industry continues to show increased interest in biofuels. Suncor and Murphy Oil 

recently joined Valero as the second and third oil companies to purchase idled U.S. ethanol 

plants. Many refiners are also supporting the development of cellulosic biofuels and algaebased biodiesel, discussed in Sections 1.5.3 and 1.5.4.3 

1.5.1.2 Forecasted Production Under RFS2 

 As highlighted earlier, domestic ethanol production is projected to grow to over 10 billion 

gallons in 2009. And with 12 billion gallons of capacity online as of November 2009, ethanol 

production should continue to grow in 2010, provided plants continue to produce at or above 

today’s production levels. In addition, despite current market conditions (i.e., poor ethanol 

margins), the ethanol industry is expected to grow in the future under the RFS2 program. 

Although there is not a set corn ethanol requirement, EISA allows for 15 billion gallons of the 

 

37 Valero recently announced that it has purchase agreements in place to acquire the last two Verasun plants in 

Linden, IN and Bloomington, OH and the former Renew Energy plant in Jefferson Junction, WI. 

38 Based on refinery information provided at http://www.valero.com/OurBusiness/OurLocations/ 
 133

36-billion gallon renewable fuel standard to be met by conventional biofuels. We expect that 

corn ethanol will fulfill this requirement, provided it is more cost competitive than imported 

ethanol or cellulosic biofuel in the marketplace. 

 In addition to the 180 aforementioned corn/starch ethanol plants currently online, 27 

plants are presently idled. Some of these are smaller ethanol plants that have been idled for quite 

some time, whereas others are in a more temporary “hot idle” mode, ready to be restarted. In 

response to the economic downturn, a number of ethanol producers have idled production, halted 

construction projects, sold off plants and even filed for Chapter 11 bankruptcy protection. Some 

corn ethanol companies have exited the industry all together (e.g., VeraSun) whereas others are 

using bankruptcy as a means to protect themselves from creditors as they restructure their 

finances with the goal of becoming sustainable. 

 Crude oil prices are expected to increase in the future making corn ethanol more 

economically viable. According to EIA’s AEO 2009, crude oil prices are projected to increase 

from about $80/barrel (today’s price) to $116/barrel by 2022.39 As oil and gas prices rebound, 

we expect that the biofuels industry will as well. Since our April 2009 industry assessment used 

for the NPRM, nine corn ethanol plants have come back online. 

 For analysis purposes, we assumed that all 27 idled corn/starch ethanol plants would 

resume operations by 2022 under the RFS2 program. We also assumed that nine new ethanol 

plants and four expansion projects40 currently under construction or in advanced stages of 

planning would come online. This includes two DOE-funded combination corn/cellulosic 

ethanol plants. While several of these projects are delayed or on hold at the moment, we expect 

that these facilities (or comparable replacement projects) would eventually come online to get 

the nation to approximately 15 billion gallons of production capacity as shown below in Table 

1.5-7.. 

Table 1.5-7. 

Potential Corn/Starch Ethanol Industry Expansion Under RFS2 

Plants 

Currently

Online

Idled

Plantsa

Under 

Constructionb

Planned Exp. or

DOE-Funded

Projectsc Total

Plant Capacity (MGY) 12,020 1,440 1,301 166 14,927

No. of Plants 180 27 10 new 1 new, 2 exp 218

a

Assumes all idled plants come back online in the future.

b

Includes construction projects that are currently on hold. Considers two dry mill expansion projects currently 

underway at existing ADM wet mill sites to be new plants.

c

Includes an expansion project at an existing corn ethanol plant and two planned combination corn/cellulosic ethanol 

plants that received funding from DOE. 

 

39 EIA’s Annual Energy Outlook 2009 – ARRA Update (Table 12). 

40 Includes the addition of dry mill plant capacity at two existing wet mill plants. 
 134

 While theoretically it only takes 12-18 months to build a corn ethanol plant41, 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).42 

However, it is possible that some of the required growth could come from minor process 

improvements (e.g., debottlenecking) at existing facilities. Allowing a 5% tolerance on the 

baseline volume for grandfathering facilities (per §80.1403) could promote such growth. 

 Once the aforementioned capacity expansion is complete, we project that there will be 

218 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 (almost 88% by volume) is expected to come from corn-fed 

plants. Another 12% is forecasted to come from plants processing a blend of corn and/or other 

grains, and a tiny capacity increase is projected to come from an idled cheese whey plant coming 

back online. A summary of the forecasted ethanol production by feedstock under the RFS2 

program is found in Table 1.5-8. 

 

41 For more information on our estimated plant build rates, refer to Section 1.2.5. 

42 For our NPRM impact analysis, we relied on an earlier May 2008 industry assessment. For more information, 

refer to Section 1.5.1.5. 
 135

Table 1.5-8. 

Projected RFS2 Ethanol Production Capacity by Feedstock 

Capacity

MGY

No. of

Plants

Capacity

MGY

No. of

Plants

Barley 65 1 65 1

Corna 2,549 30 13,543 185

Corn, Milob 173 3 990 18

Corn, Wheat 0 0 130 1

Corn, Wheat, Milo 110 2 110 2

Corn, Whey 7 1 7 1

Milo 0 0 3 1

Wheat, Milo 0 0 50 1

Cheese Whey 3 1 3 1

Waste Beveragesc 0 0 20 5

Waste Sugars & Starchesd 0072

Total 2,907 38 14,927 218

Additional Production Total RFS2 Estimate

Plant Feedstock

(Primary Listed First)

a

Includes one facility processing seed corn, one facility operating a pilot cellulosic butanol plant, 

two facilities with plans to build pilot cellulosic ethanol plants, and two facilities with plans to 

build small commercial cellulosic ethanol plants. 

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.

 With the exception of one facility, all new corn/grain ethanol plants are expected to 

utilize dry milling technologies and the majority of new production is expected to come from 

plants burning natural gas. However, we anticipate two manure biogas plants43, one biomassfired plant, and two coal-fired ethanol plants will be added to the mix.44 Of these new and 

returning idled plants, we’re aware of five currently planning to use CHP technology, bringing 

the U.S. total to 32 as shown in Table 1.5-9. 

 

43 One manure biogas plant is currently idled and the other that was under construction is now on hold. 

44 The two aforementioned coal fired plants are dry mill expansions at existing wet mill corn ethanol plants. These 

projects commenced construction prior to December 19, 2007 and would therefore be grandfathered. For more on 

our grandfathering assessment, refer to Section 1.5.1.4 of the RIA. 
 136

Table 1.5-9. 

Projected Near-Term Corn/Starch Ethanol Production Capacity by Energy Source 

Capacity

MGY

No. of

Plants

Capacity

MGY

No. of

Plants

CHP

Tech.

Biomass 88 1 88 1 1

Coala 550 2 2,308 19 10

Coal, Biomass 0 0 50 1 0

Manure Biogas 139 2 139 2 0

Natural Gasb 2,130 33 11,836 185 16

Natural Gas, Biomassc 0 0 115 3 1

Natural Gas, Coal 0 0 35 1 1

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

Natural Gas, Syrup 0 0 101 2 0

Waste Heat 0 0 50 1 1

Waste Heat, Natural Gas 0 0 96 2 2

Total 2,907 38 14,927 218 32

Total RFS2 Estimate

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 switch to biomass in the future.

b

Includes four facilities that might switch to biomass in the future, one facility that intends to burn thin stillage and 

biogas, one facility that gets 40% of its host steam from a nearby power plant and a total of five facilities that were 

once considering switching to coal in the future.

c

Includes one facility processing bran in addition to natural gas.

d

Waste heat from utility partnerships. 

Plant Energy Source

(Primary Listed First)

Additional Production

 The information presented in Table 1.5-9 is based on the industry’s current near-term 

production plans. However, we anticipate growth in advanced ethanol production technologies 

under the RFS2 program. Forecasted fuel prices are projected to drive corn ethanol producers to 

transition from conventional boiler fuels to biomass feedstocks. In addition, fossil 

fuel/electricity prices will likely drive a number of ethanol producers to pursue CHP technology. 

For more on our projected 2022 utilization of these technologies under the RFS2 program, refer 

to Section 1.5.1.3 of the RIA. 

 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, 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. 
 137

Table 1.5-10. 

Projected RFS2 Corn/Starch Ethanol Production Capacity by PADD 

Capacity

MGY

No. of

Plants

Capacity

MGY

No. of

Plants

PADD 1 349 4 499 7

PADD 2 2,011 25 13,340 188

PADD 3 145 2 439 6

PADD 4 50 1 202 8

PADD 5 352 6 447 9

Total 2,907 38 14,927 218

PADD

Additional Production Total RFS2 Estimate

 Based on current production plans, we project that Iowa, Nebraska, Illinois, Minnesota 

and South Dakota will continue to dominate ethanol production with a collective production 

capacity of about 9.5 billion gallons per year. 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. 
 138

Table 1.5-11. 

Projected RFS2 Corn/Starch Ethanol Production Capacity by State 

Capacity

MGY

No. of

Plants

Capacity

MGY

No. of

Plants

Iowa 545 3 3,759 42

Nebraska 453 4 2,013 27

Illinois 178 3 1,520 16

Minnesota 28 2 1,141 22

South Dakota 61 1 1,048 15

Indiana 286 3 1,002 12

Kansas 168 3 607 14

Ohio 224 3 544 8

Wisconsin 7 1 536 10

North Dakota 11 1 366 6

Texas 115 1 355 4

Michigan 50 1 267 5

Missouri 0 0 261 6

California 239 5 244 6

Tennessee 0 0 236 2

New York 114 1 164 2

Oregon 113 1 153 2

Colorado 0 0 138 5

Pennsylvania 110 1 110 1

Georgia 0 0 100 2

Virginia 65 1 65 1

North Carolina 60 1 60 1

Idaho 50 1 55 2

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

Oklahoma 0 021

Total 2,907 38 14,927 218

Additional Production

State

Total RFS2 Estimate

 The majority of future ethanol plants are expected to be company-owned. Of the 38 

plants we are expecting to be built or brought back online under the proposed RFS2 program, 36 

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 is expected to be the third largest ethanol 

producer with over 1.1 billion gallons of production capacity, provided the most recent ethanol 
 139

plant acquisition goes through. 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 

Other, 7,874

Tate & Lyle, 241

Green Plains Renewable 

Energy, 480

Valero Renewables, 1,120

POET Biorefining, 1,580

Archer Daniels Midland, 

1,650

Hawkeye Renewables, 

460 Abengoa, 457

AltraBiofuels Plants, 290

Glacial Lakes Energy, 250

The Andersons, 275

White Energy Plants, 250

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. 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 the energy needs of the 

ethanol plant to be met entirely, or to a greater extent, by waste products and locally produced 

biofuels. This would greatly reduce the purchase and transportation costs of the biofuels. If 
 140

ethanol producers do decide to make a transition to biofuels, is likely that plants currently using 

natural gas would transition to using biogas, and those using coal would transition to using solid 

biomass. This is primarily due to their ability to make these transitions without investing in new 

boiler equipment. The same factors that may cause ethanol producers to increase biofuels usage, 

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 1.5-12.45

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 at plants with CHP 

technology. 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. 

 

45 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 
 141

Table 1.5-13.46

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%

 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 average thermal energy usage by 11.8% 

and to increase the average electrical energy usage by 13.1%. 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 likely 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. 

 

46 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 
 142

Table 1.5-14.47

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 65% 70% 70% 70% 

Membrane Separation 3% 5% 5% 5% 

Energy Reduction from Base Process (Thermal) 

Raw Starch Hydrolysis 16% 16.7% 17% 17% 

Corn Fractionation 17.6% 17.6% 17.6% 17.6% 

Corn Oil Extraction 5.4% 5.4% 5.4% 5.4% 

Membrane Separation 15.7% 15.7% 15.7% 15.7% 

Weighted Average Savings (Thermal) 10.3% 11.8% 13.0% 14.9% 

Energy Reduction from Base Process (Electrical) 

Raw Starch Hydrolysis 0% 0% 0% 0% 

Corn Fractionation -29% -29% -29% -29% 

Corn Oil Extraction -9.9% -9.9% -9.9% -9.9% 

Membrane Separation -7.6% -7.6% -7.6% -7.6% 

Weighted Average Savings (Electrical) -11.8% -13.1% -14.3% -16.0% 

Another factor that plays a significant role in determining the energy usage of ethanol 

plants is the treatment of the main co-product of the dry mill ethanol production process, 

distillers grains and solubles (DGS). The DGS, which is most often sold as feed for cattle, 

poultry, or swine, can be sold either dry or wet. Wet DGS can often only be sold locally, as it is 

difficult to transport and is susceptible to spoilage. Drying the DGS avoids these problems and 

allows the DGS to be sold in a much wider market; however drying the DGS is an energy 

intensive process. USDA models suggest that 40.4% of the thermal energy used in an ethanol 

plant that produces dry DGS is used in the drying process. Plants that do not dry their DGS, or 

dry only a portion of it, could experience energy savings up to 40.4%. According to a recent 

industry survey, 37% of all DGS produced by the dry mill ethanol industry is sold wet. We have 

assumed that this percentage remains constant through 2022 for our energy use projections. 

Combining the impacts of these four factors (primary fuel sources, energy savings from 

efficiency improvements, new technology and process changes, and DGS drying rates) allows us 

to project the average energy usage of a dry mill ethanol plant in 2022. Table 1.5-15 below 

outlines the projected average energy usage of dry mill ethanol plants in 2022. The first two 

lines take into account the projected primary fuel types and energy efficiency improvements. 

The next two lines adjust the totals to include new technologies and process changes. Finally, 

the total is calculated by weighting the values for dry and wet DGS according to the production 

ratio we expect in 2022 (63% dry DGS, 37% wet DGS)48. 

 

47 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 

48 An Excel spreadsheet has been added to the docket showing the energy impact calculations of the technology 

improvements (EPA-HQ-OAR-2005-0161-2729 
 143

Table 1.5-15 

2022 Dry Mill Ethanol Plant Average Energy Usage 

 Thermal Energy Electrical Energy 

Dry DGS, includes efficiency 

improvements 28,977 BTU/Gal 1,515 BTU/Gal 

Wet DGS, includes efficiency 

improvements 17,271 BTU/Gal 1,515 BTU/Gal 

Dry DGS, includes process changes 25,570 BTU/Gal 1,714 BTU/Gal 

Wet DGS, includes process changes 16,255 BTU/Gal 1,714 BTU/Gal 

2022 Average Energy Usage 22,123 BTU/Gal 1,714 BTU/Gal 

 In addition to projecting the average energy usage of a dry mill ethanol plant in 2022 we 

have also projected the energy usage of a “best case scenario” plant. This plant was defined as a 

plant that used the combination of all the technologies considered that resulted in the lowest 

overall energy usage, as well as all the energy efficiency improvements discussed above. The 

technologies used by the best case scenario plant were CHP, dry fractionation, membrane 

separation, and raw starch hydrolysis. Corn oil extraction was not considered as plants would 

have either corn oil extraction or dry fractionation but not both, and dry fractionation resulted in 

greater energy savings. Best case scenario energy usage numbers were calculated for both 

natural gas and coal/biomass fired plants producing both dry and wet DGS. The results are 

shown below. 

Table 1.5-16 

2022 Best Case Natural Gas Dry Mill Plant Energy Usage 

 2022 Best Case Scenario (Dry DGS) 

 Thermal Electrical 

2022 Base Plant 28,660 BTU/Gal 2,251 BTU/Gal 

2022 Best Case Scenario 16,568 BTU/Gal 1,682 BTU/Gal 

 2022 Best Case Scenario (Wet DGS) 

2022 Base Plant 17,081 BTU/Gal 2,251 BTU/Gal 

2022 Best Case Scenario 9,932 BTU/Gal 1,682 BTU/Gal 

1.5.1.4 Projected Grandfathered Corn Ethanol Volume 

 As explained in the Section II.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 

emissions in order to generate RINs under the proposed RFS2 program.49 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. 

 

49 In accordance with Section 211(o)(2)(A)(i) of the Clean Air Act as amended by EISA. 
 144

 The volume of ethanol that is grandfathered under today’s RFS2 rule will be determined 

based on information received during the expanded registration process (refer to Section II.C of 

the preamble). However, as part of this final rulemaking, we analyzed the volume of corn 

ethanol that could potentially be grandfathered under the RFS2 rule based on our knowledge of 

the industry. 

 To do so, we started with our assessment of corn ethanol plants that were operational, 

idled or under construction at the time of our November 2009 assessment. As shown in Table 

1.5-7, excluding the planned facilities, this amounts to about 14.8 billion gallons of ethanol 

production capacity. Provided all the plants meet the definition of “commence construction” 

under §80.1403, the potentially grandfathered volume of ethanol falls just shy of meeting the 15 

billion gallon conventional biofuel standard. However, actual baseline volumes established 

during registration could easily exceed 15 billion gallons. Furthermore, by allowing a 5% 

tolerance on the baseline volume to account for minor changes during ongoing maintenance of 

the facilities under §80.1403(a)(1), these plants could readily exceed 15 billion gallons of 

production. 

 Further examination suggests that all of today’s corn ethanol plants will likely be 

grandfathered under the RFS2 program because they’re either fired with natural gas, biomass or 

a combination thereof and commenced construction prior to December 31, 2009 or they burn 

coal but commenced construction prior to December 19, 2007. A summary of grandfathering 

assessment logis we applied is found in Figure 1.5-1 and the 20 coal-fired plants we considered 

is presented in Table 1.5-17. 
145 

Figure 1.5-1. 

Potential Grandfathered Volume of Corn Ethanol Under RFS2 

Is plant fired with natural gas, biomass, or any 

combination thereof and commenced 

construction by December 31, 2009?

Grandfathered or deemed compliant 

under RFS2 rule.

Yes No, plant burns coal

Not grandfathered under 

the RFS2 rule.

No

Was the corn ethanol plant (or expansion 

project) existing, idled or under construction 

as of November 2009 industry assessment?

14.8 

Bgal

0 

Bgal

12.4 

Bgal

2.4 

Bgal

2.4 

Bgal

0 

Bgal

Did the facility commence construction 

by December 19, 2007?

Yes

Yes

14.8 

Bgal

Would need to meet 

the 20% threshold 

requirement

0.2 

Bgal

No
146 

Table 1.5-17. 

Coal-Fired Corn Ethanol Plants

Plant/Company Location

Capacity

MGY

On-Line 

Date

Ag Processing Inc. Hastings, NE 52 1992

Archer Daniels Midland (ADM)a Cedar Rapids, IA 250 1981

Archer Daniels Midland (ADM)a Cedar Rapids, IA 275 Aug-10

Archer Daniels Midland (ADM)a Clinton, IA 190 1981

Archer Daniels Midland (ADM)a Columbus, NE 275 Aug-10

Archer Daniels Midland (ADM)a Columbus, NE 95 1994

Archer Daniels Midland (ADM)a Decatur, IL 290 1976

Archer Daniels Midland (ADM) Marshall, MN 40 1988

Archer Daniels Midland (ADM) Peoria, IL 210 1980

Archer Daniels Midland (ADM) Walhalla, ND 25 1990

Aventine Renewable Energyb Pekin, IL 100 1981

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 Biofuelsd Canton, IL 38 Oct-08

Southwest Iowa Renewable Energy Council Bluffs, IA 110 Feb-09

Tate & Lyle Loudon, TN 126 1982

Total Coal-Fired Capacity 2,358 a

Permitted to burn biomass, tires, petroleum coke, and wood waste in addition to coal 

b

Recently filed for bankruptcy protection.

c

Burns a combination of coal and biomass.

d

Formerly Central Illinois Energy

As shown above, most of the coal-fired ethanol plants were built well before 2007 and 

thus should have little problem qualifying as grandfathered under the RFS2 rule. There are 

essentially four plants that could potentially pose a challenge with respect to the construction 

cutoff date set by EISA. These facilities, bolded in Table 1.5-17 above, include two dry-mill 

ADM plant expansion projects currently underway in Cedar Rapids, IA and Columbus, NE as 

well as Riverland Biofuels in Canton, IL and Southwest Iowa Renewable Energy in Council 

Bluffs, IA. However, communications with these companies suggest that these plants 

commenced construction prior to December 19, 2007 and thus should be grandfathered and 

exempt from the 20% threshold requirement under RFS2. 

1.5.2 Imported Ethanol 
 147

 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 

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 Historic/Current Imports and Exports 

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. 

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 

1.5-6, 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. The EU, 

Caribbean, and U.S. have continued to be major importers of Brazilian ethanol in recent years. 
 148

Figure 1.5-6. Brazil Ethanol Exports (Includes all types of ethanol).252,253,254

0

200

400

600

800

1000

1200

1400

2005 2006 2007 2008 2009*

Million Gallons

Others

Venezuela

Japan

India

Mexico

Nigeria

South Korea

Caribbean

EU

U.S.

*January 2009-October 2009 

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.255 While hydrous ethanol is used in Brazil directly in Otto-cycle motors 

(100%), anhydrous ethanol is mixed with 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.256 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 85% of vehicles sold during January 2009 to 

October 2009.257 Hydrous ethanol accounted for 65% of ethanol produced in Brazil in 2008, and 

73% of ethanol produced as of December 1, 2009. Figure 1.5-7 shows the historical production 

of hydrous and anhydrous ethanol in Brazil. 
 149

Figure 1.5-7. 

Historical Ethanol Production of Hydrous and Anhydrous Ethanol in Brazil.258 

0

1,000

2,000

3,000

4,000

5,000

6,000

1997199819992000200120022003200420052006200720082009

Million Gallons

Hydrous Ethanol

Anhydrous Ethanol

*2009 data is up to date as of 12/01/2009 

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 have been designed to use hydrous ethanol, or E100 (100% ethanol) for the 

conditions in Brazil, 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.259 Estimates of future ethanol production in 

Brazil range greatly. See Figure 1.5-8. Brazil’s government has adopted plans to meet global 

demand by tripling production by 2020.260 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.261 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. 
 150

Figure 1.5-8. Estimated Brazilian Ethanol Production Volumes262

0

5,000

10,000

15,000

20,000

25,000

2000 2010 2020 2030 2040

Million Gallons

FAPRI 2007

Agricultural Outlook

OECD-FAO

Agricultural Outlook

Bioenergia (2007)

Rothkopf (2006)

EPE (2007)

Unica

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.263,264 Brazil’s state-owned 

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.265 Some estimate even more, where investments in 

sugarcane processing factories are expected to top $23 billion over the next four years.266 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.267 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 

sugarcane 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.”268 

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.269 Railroad infrastructure and use of a waterway system is 

lacking, as well as very low availability of multi-mode terminals. Logistics represent 

approximately 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.270 
 151

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.271 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.272 

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 

will need to invest $1 billion each year for the next 15 years in infrastructure to keep pace with 

capacity expansion and export demand.273

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.274 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%.275 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.276 

At some point in the future, Brazil’s light vehicle fleet may become saturated with FFVs 

in preference to gasoline. As such, the rate in domestic demand for ethanol is expected to begin 

to slow.277 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-

9 shows various estimates for future Brazilian ethanol domestic consumption. 

 
 152

Figure 1.5-9. Estimated Brazilian Ethanol Consumption Volumes 278

0

5,000

10,000

15,000

20,000

25,000

2000 2010 2020 2030 2040

Million Gallons

Canaplan, Director

Carvalho

FAPRI 2007

Agricultural Outlook

EPE (2007)

Unica

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 1.5-10. 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 2025.279
 153

Figure 1.5-10. Estimated Brazilian Export Volumes

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2010 2012 2014 2016 2018 2020 2022

Million Gallons

EPE (2007)

Unica

FAPRI 2007

Agricultural Outlook

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).280 

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.281 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 2030.282 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 2022.50,283 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.284,285 

 

50 Assuming energy contents 115,000 Btu/gal for gasoline and 77,930 Btu/gal for denatured ethanol and 164 gge in 

2022 
 154

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.286 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 (754 million gallons in 2008).287 Germany, Spain, France, Poland, 

and Hungary represent almost 80% of the production in 2008. 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 September 9, 2009, the installed capacity of the EU ethanol industry is 1.7 billion 

gallons, while 0.6 billion gallons are under construction and another 3 billion gallons has been 

announced.288,289 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. 

Japan 

Historically, Japan has not produced much ethanol (24,000 gallons in 2008) and has 

imported the majority of its consumption.290,291 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.292 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.293 

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 

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).294 While the use of 

greater than E3 blends in Japan may be unlikely, the Japanese government has mandated that all 

gasoline powered vehicles are able to run on E-10 blends by 2030 and will also enact legislation 

to require all new vehicles to be E-10 compatible by 2012.295,296
 155

The prospect for large domestic production of ethanol in Japan appears to be small due to 

limitations on feedstock. In fact, Japan’s first biomass plan, “Biomass Nippon Strategy” 

unveiled in December 2002 and updated in 2008 reveals that the Government of Japan’s (GOJ’s) 

current thinking, given limited agricultural resources, is to focus on cellulosic biofuel as the 

future for Japan’s biofuel production.297 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.298 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 1.5-18 details recent ethanol plants in Japan. The total capacity is much lower than 

the 132.1 million gallons of ethanol goal and further supports the argument that Japan could 

likely be heavily dependent on imports. 

Table 1.5-18. Upcoming/Recent Plants in Japan299

Plant Capacity Feedstock 

Three from 

Agriculture Ministry 

~4 million 

gallons/year 

Local crops: rice, low-quality 

wheat, sugarbeet, sugarcane 

Hokkaido 

Prefectural Union of 

Agricultural 

Cooperatives 

3.96 million 

gallons/year 

Sugarbeets that aren’t 

targeted for domestic sugar 

and substandard wheat 

unusable for food 

Nippon Steel Plant 104.89 gallons 

daily (38,285 

gallons/year) 

Food waste from: 

supermarkets, restaurants, 

schools, hospitals. (10 tons 

annually) 

Mitsui Engineering 

& Shipbuilding Co. 

 Agricultural wastes: felled 

oil palm trunks, empty fruit 

bunches, fibrous fruit wastes, 

kernel shells 

Japan has relied on nations such as Brazil to supply 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 

process of analyzing 40 projects evaluated at $8 billion for building 40 new processing plants 

which produce alcohol and sugar from sugarcane. According to Paulo Roberto Costa, head of 

Petrobras’ supply division, “Our target is to produce ethanol to be exported only to Japan.” 
 156

Petrobras plans 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 convince Japan that 

Petrobras has adequate ethanol supplies it was noted that their processing facilities will not be 

able to produce sugar, only alcohol.300 With this amount (264 million gallons) slated for Japan 

only, other countries may have to either develop their own contracts with Brazil to ensure a 

stable 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.301 

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.302 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.303 Imports of ETBE were roughly 1.7 

million gallons in 2008.304

India 

India has the potential to increase its ethanol production due to its long agricultural 

tradition. However, it is still in the very young stages of raising its biofuel industry, which leaves 

some analysts doubting this program’s stability.305 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. 

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.306 The 
 157

original plan was a minimum of 10% blend of ethanol by October 2008; however, this 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).307 

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. 

In the past, India’s largest sugar and ethanol manufacturing company (Bajaj Hindusthan) 

has tried to acquire ethanol production plants in other countries with large sugarcane outputs (i.e. 

Brazil). This way, the company can increase its ethanol production. Yet after several months, 

the company was unable to come to any concrete agreements.308 

Some oil companies are instead pushing for imports of ethanol. However, there is still an 

import duty of 198.96% on the cif value for denatured and 59.08% for undenatured ethanol.309 

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. 

 

China 

China began mandating fuel ethanol blended into gasoline since June 2002.310 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 

2020.51,311

 

51 Assuming a conversion of 1 million tonnes of ethanol equals 330 million gallons. 
 158

In 2008, China was the world’s fourth largest fuel ethanol producer, producing 502 

million gallons.312 The majority of fuel ethanol made in China is from corn.313 However, 

concerns in China about the security of their food supply and the inflationary impact of biofuels 

which use grains as feedstock could influence the feedstocks used in the future. 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.314 

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.315 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).316,317 These 

plants were established after 2000 to address a surplus of grains in China at the time. Plans for 

ethanol plant expansions were expected to reach up to approximately 550 million gallons of 

ethanol. These companies, as well as announced expansions are listed in the following Table 

1.5-19. 

Table 1.5-19. Current and Future Fuel Ethanol Production in China318

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.319 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.320 

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.321 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.322 Another study, 

the “World Biofuels: FAPRI 2007 Agricultural Outlook” also indicates that China would be a net 
 159

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.323 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. 

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 the past.324 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 1.5-20. This list is not meant to be allinclusive, but rather to give idea of the biofuel outlook in other countries. 
 160

Table 1.5-20 

Potential Mandates and Goals for Various Countries325,326,327,328,329,330 

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. 

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 1.5-21 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. As discussed above, 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 countries in the future. Therefore, it is 
 161

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. We briefly discuss the potential for imported cellulosic feedstocks or biofuels in 

Section 1.1.2.6. 

Table 1.5-21. Potential Import Demand: 

EU, Japan, India, and China by 2020/2022 (billion gallons).52

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

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 1.5-11. There is a trend 

over the past 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. 

 

52 Ranges are calculated assuming the potential values for production and consumption 
 162

Figure 1.5-11. 

U.S. Ethanol Exports (includes hydrous, dehydrated, and denatured volumes).331

0

20

40

60

80

100

120

140

2001 2002 2003 2004 2005

Million Gallons

Others

Mexico

India

Canada

Japan

EU

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.53 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 

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.332

 

53 Prior to the 2008 Farm Bill, the tax incentive was set at 54 cents per gallon 
 163

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 sugarcane production in some CBI nations, there has been 

insufficient economic potential to spur sugarcane planting for ethanol production.333 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).334 Thus far, Costa Rica, El Salvador, Jamaica, Trinidad and 

Tobago, and the U.S. Virgin Islands (since 2007) are the only countries that have 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.335 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.336 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).337,338 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.”339 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.340 

 

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 

the previous year). The fill rate, or percent of the TRQ used, has ranged from 22-77% between 

1990 and 2008. See Figure 1.5-12. Thus, there is still considerable room for growth in CBI 

imported ethanol. 
 164

Figure 1.5-12. U.S. Fuel Ethanol CBERA TRQ, 1990-2008

0

50

100

150

200

250

300

350

400

450

500

1990199219941996199820002002200420062008

Million Gallons

TRQ Used TRQ Available

*TRQ Used data for 2009 is not yet available, TRQ Available is 621.5 million gallons. 

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.341 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.

342,343 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.344 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. 

• Costa Rica- LAICA (cane co-op) has a plant currently dehydrating ethanol at 38 million 

gallons.345
 165

• 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.346 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.347

• 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 2007.348 The cost to build the plant is estimated at 

$20 million.349 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".350 Another company, 

Angostura Ltd., started processing ethanol in 2005.351 The plant has an overall capacity 

of 100 million gallons per year, with 50 million gallons per year in the first phase.352 

• 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).353 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 2008.354 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.355

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.356 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.357 CBI countries also need to compete for Brazilian ethanol. For example, 

Angostura’s ethanol subsidiary, Trinidad Bulk Traders Ltd., was not profitable in 2006 because it 

could not get enough fuel from Brazil.358 

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.359 

In addition, increasing significantly beyond the 7% limit may be challenging. Few 

Caribbean countries are in a position to produce ethanol from domestic feedstocks such as 

sugarcane. Currently, all three plants exist in Central America (CATSA in Costa Rica, Pantleon 
 166

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.360 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.361 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 19.2 Bgal (under the primary control case), then approximately 1.21 Bgal of 

ethanol could enter the U.S. through CBI countries.54 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. As shown in Table 1.5-22, 1.03 billion gallons would need to come 

directly from Brazil to get to 2.24 billion gallons of imported ethanol – the volume projected 

under our primary control case to meet the RFS2 standard in 2022. 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. 

Table 1.5-22. 

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 

1.21 1.03 2.24 

 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. 

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 or other 

countries increase biofuels production significantly, there may be a limited supply for imported 

ethanol to satisfy all foreign country mandates and goals. 

1.5.3 Cellulosic Biofuel 

 The majority of the biofuel currently produced in the United States comes from plants 

processing first-generation feedstocks like corn, plant oils, sugarcane, etc. Non-edible cellulosic 

 

54 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). 
 167

feedstocks have the potential to greatly expand biofuel production, both volumetrically and 

geographically. Research and development on cellulosic biofuel technologies has exploded over 

the last few years, and plants to commercialize a number of these technologies are already 

beginning to materialize. The $1.01/gallon tax credit for cellulosic biofuel that was introduced in 

the 2008 Farm Bill and recently became effective, is also offering much incentive to this 

developing industry. In addition to today’s RFS2 program which sets aggressive goals for 

cellulosic biofuel production, the Department of Energy (DOE), Department of Agriculture 

(USDA), Department of Defense (DOD) and state agencies are helping to spur industry growth. 

 

1.5.3.1 Current State of the Industry

 There are a growing number of biofuel producers, biotechnology companies, universities 

and research institutes, start-up companies as well as refiners investigating cellulosic biofuel 

production. The industry is currently pursuing a wide range of feedstocks, conversion 

technologies and fuels. There is much optimism surrounding the long-term viability of cellulosic 

ethanol and other alcohols for gasoline blending. There is also great promise and growing 

interest in synthetic hydrocarbons like gasoline, diesel and jet fuel as “drop in” petroleum 

replacements. Some companies intend to start by processing corn or sugarcane and then 

transition to cellulosic feedstocks while others are focusing entirely on cellulosic materials. 

Regardless, cellulosic biofuel production is beginning to materialize. 

 We are currently aware of 36 small cellulosic biofuel plants operating in North America. 

This includes process development units with fuel production capabilities, pilot plants, 

demonstration plants, as well as commercial demonstration plants. These facilities are 

summarized by fuel type in Tables 1.5-23 and 1.5-24 below. The lists below do not include 

plants currently processing grains or sugars with plans to transition to cellulosic feedstocks in the 

future, e.g., Amyris, Gevo/ICM, and Virent. However, we will continue to track these 

companies for future cellulosic biofuel assessments. 

 Regardless of their size, the main focus at these facilities is research and development, 

not commercial production. As shown below, most of the plants are rated at less than 250,000 

gallons of cellulosic biofuel per year and that’s if they were operated at capacity. However, most 

only operate intermittently for the purpose of demonstrating that the technologies can be used to 

produce transportation fuels. As such, some don’t even report production capacities. The 

industry as a whole is still working to increase efficiency, improve yields, reduce costs and prove 

to the public, as well as investors, that cellulosic biofuel is both technologically and 

economically feasible. 

 
 168

Table 1.5-23. Current Cellulosic Alcohol Plants 

AR EC W UW

Abengoa Bioenergy Corporationd York, NE Pilot 0.02 Sep-07 Ethanol Bio X X

CoskataCornell University Biofuels Research Laboratory Ithaca, NY Pilot N/A Jan-09 Ethanol Bio X XCobalt Biofuels Mountainview, CA Pilot 0.01 N/A Butanol Bio X XClearFuels / Hawaii Natural Energy Institute Honolulu, HI Pilot N/A 2004 Ethanol Thermo XChemrec & Weyerhaeuser New Bern, NC Pilot N/A 1996 Ethanol Thermo XAuburn University / Masada Auburn, AL Pilot N/A 1995 Ethanol Bio XArkenol Technology Center Orange, CA Pilot N/A 1994 Ethanol Bio XAE Biofuels Butte, MT Demo 0.15 Aug-08 Ethanol Bio X X

e Warrenville, IL Pilot N/A Mar-08 Ethanol Thermo X

Coskatae Madison, PA Demo 0.04 Oct-09 Ethanol Thermo X X X XFiberightEnerkem Sherbrooke (CAN) Pilot N/A 2003 Ethanol Thermo X XDOE National Renewable Energy Laboratory Golden, CO Pilot N/A 2001 Ethanol Bio X

f Lawrenceville, VA Demo (C) N/A 2005 Ethanol Bio X

INEOS Bio (formerly BRI)Gulf Coast Energy Livingston, AL Demo 0.20 Sep-08 Ethanol Thermo XFulcrum Bioenergy - Turning Point Ethanol Plant Durham, NC Demo N/A Mar-09 Ethanol Thermo X

e Fayetteville, AR Pilot 0.04 1998 Ethanol Thermo X X X

POET Project BellPearson Technologies Inc. Aberdeen, MS Pilot N/A 2001 Ethanol Thermo X XPan Gen Global (formerly Colusa Biomass) Colusa County, CA Pilot N/A 1995 Ethanol Bio XMascoma Corporation Rome, NY Pilot 0.20 Dec-08 Ethanol Bio XLignol Energy Burnaby, BC (CAN) Pilot N/A Jun-09 Ethanol Bio X XKL Energy Corp / WBE Upton, WY Demo (C) 1.50 Sep-07 Ethanol Bio XIogen Corporation Ottawa (CAN) Demo (C) 0.50 2004 Ethanol Bio XIogen Corporation Ottawa (CAN) Pilot N/A 1985 Ethanol Bio X X

d Scotland, SD Pilot 0.02 Nov-08 Ethanol Bio X

PureVision Technology, Inc.f Fort Lupton, CO PDU N/A Mar-09 Ethanol Bio X XVerenium Jennings, LA Demo 1.40 Feb-09 Ethanol Bio X X XVerenium Jennings, LA Pilot 0.05 2006 Ethanol Bio XSunOpta BioProcess Inc. Norval (CAN) Pilot N/A 2003 Ethanol Bio XRange Fuels K2A Optimization Plant Broomfield, CO Pilot N/A Mar-09 Ethanol Thermo X

Cell. Feedstocksc

PDU = Process development unit, Pilot = pilot-scale plant, Demo = demonstration-level plant, Demo (C) = Commercial demonstratio

a

Company/Plant Name

n plant.

bConversion technology. Bio = Biochemical, Thermo = Thermochemical.cFeedstocks. AR = Ag residues, EC = Energy crops, W = Wood waste, chips, mill waste, etc., UW = Urban waste including sorted MSW and C&D debris.

fPlant is not currently operational and/or producing fuel.ePlant also processes non-cellulosic/renewable feedstocks, e.g., natural gas, coal.dCellulosic ethanol plant is co-located with an existing corn ethanol plant.

Cell. 

Tech.b

Online

Date

Max Cap 

(MGY) Type

Plant 

a Plant Location

Cell. 

Biofuel
 169

Table 1.5-24. Current Cellulosic Hydrocarbon Fuel & Pyrolysis Oil Plants 

AR EC W UW

Cello Energyd Fort Stewart, GA Pilot 0.01 Dec-08 Diesel Bio X X

Cello Energyd Bay Minette, AL Demo (C) 20.00 Dec-08 Diesel Cat X XClearfuels / Renteche Commerce City, CO PDU N/A 2008 Diesel, Jet Thermo X X

PDU = Process development unit, Pilot = pilot-scale plant, Demo = demonstration-level plant, Demo (C) = Commercial demonstratio

a

ThermoChem Recovery International (TRI) Durham, NC Pilot 0.02 Jun-09 Diesel Thermo X X XTerrabon Advanced Biofuels Research Center Bryan, TX Pilot 0.13 Apr-09 Gasoline Bio X X XDynamotive / Evolution Biofuels Guelph (CAN) Demo (C) 5.46 Sep-07 Py Oil Thermo XDynamotive West Lorne (CAN) Demo (C) 3.55 N/A Py Oil Thermo XCompany/Plant Name

n plant.

bConversion technology. Bio = Biochemical, Thermo = Thermochemical.cFeedstocks. AR = Ag residues, EC = Energy crops, W = Wood waste, chips, mill waste, etc., UW = Urban waste including sorted MSW and C&D debris.dPlant is not currently operational and/or producing fuel.eCurrently in the process of expanding natural-gas based PDU to a pilot plant that can process biomass feedstocks.

Cell. 

Tech.b

Online

Date

M ax Cap 

(MGY) Type

Plant 

a Plant Location

Cell. 

Biofuel

Cell. Feedstocksc
170

 As shown in Tables 1.5-23 and 1.5-24, today’s cellulosic biofuel plants are run by a 

combination of academic, government, and private organizations. Some of the privately-owned 

companies are existing biofuel producers, but many are start-up companies entering the industry 

for the first time. The following companies were awarded federal funding to help build their 

small plants and/or facilitate cellulosic research – Bell Bioenergy ($1.1 million from the 

Department of Defense), Clearfuels / Rentech ($2.5 million from the DOE) and Verenium ($10 

million from the DOE). 

 

 As indicated above, a variety of feedstocks are being investigated for cellulosic biofuel 

production. There is a great deal of interest in urban waste (MSW and C&D debris) because it is 

virtually free and abundant in many parts of the country, including large metropolitan areas 

where the bulk of fuel is consumed. There is also a lot of interest in agricultural residues (corn 

stover, rice and other cereal straws) and wood (forest thinnings, pulp and paper mill waste, wood 

chips, and yard waste). However, researchers are still working to find viable harvesting and 

storage solutions. Others are investigating the possibility of growing dedicated energy crops for 

cellulosic biofuel production, e.g., switchgrass, energy cane, sorghum, poplar, miscanthus and 

other fast-growing trees. While these crops have tremendous potential, many are starting with 

the feedstocks that are available today with the mentality that once the industry has proven itself, 

it will be easier to secure growing contracts and start producing energy crops. For more 

information on cellulosic feedstock availability, refer to Section 1.1.2. 

 The industry is also pursuing a number of different cellulosic conversion technologies 

and biofuels. Most of the technologies fall into one of two categories: biochemical or 

thermochemical. Biochemical conversion involves the use of acids and/or enzymes to hydrolyze 

cellulosic materials into fermentable sugars and lignin. Thermochemical conversion involves the 

use of heat to convert biomass into synthesis gas or pyrolysis oil for upgrading. A third 

technology pathway is emerging that involves the use of catalysts to depolymerize or reform the 

feedstocks into fuel. The technologies currently being considered are capable of producing 

cellulosic alcohols or hydrocarbons for the transportation fuel market. Many companies are also 

researching the potential of co-firing biomass to produce plant energy in addition to biofuels. 

For a more in-depth discussion on cellulosic conversion technologies, refer to Section 1.4.3. 

1.5.3.2 Setting the 2010 Standard 

 The Energy Independence and Security Act (EISA) set aggressive cellulosic biofuel 

targets beginning with 100 million gallons in 2010. However, EISA also supplied EPA with 

cellulosic biofuel waiver authority. For any calendar year in which the projected cellulosic 

biofuel production is less than the minimum applicable volume, EPA can reduce the standard 

based on the volume expected to be available that year. EPA is required to set the annual 

cellulosic standard by November 30th each year and should consider the annual estimate made by 

EIA by October 31st of each year. We are setting the 2010 standard as part of this final rule. 

 Setting the cellulosic biofuel standard for 2010 represents a unique challenge. As 

discussed above, the industry is currently characterized by a wide range of companies mostly 

focused on research, development, demonstration, and financing their developing technologies. 

In addition, while we are finalizing a requirement that producers and importers of renewable fuel 
 

171

provide us with production outlook reports detailing future supply estimates (refer to §80.1449), 

we do not have the benefit of this valuable cellulosic supply information for setting the 2010 

standard. Finally, since today’s cellulosic biofuel production potential is relatively small, and the 

number of actual potential producers few (as described in more detail below), the overall volume 

for 2010 can be heavily influenced by new developments, either positive or negative associated 

with even a single company, which can be very difficult to predict. This is evidenced by the 

magnitude in the changes in cellulosic biofuel projections and the potential suppliers of these 

fuels since the proposal. 

 In the proposal, we did a preliminary assessment of the cellulosic biofuel industry to 

arrive at the conclusion that it was possible to uphold the 100 million gallon standard in 2010 

based on anticipated production. At the time of our April 2009 NPRM assessment, we were 

aware of a handful of small pilot and demonstration plants that could help meet the 2010 

standard, but the largest volume contributions were expected to come from Cello Energy and 

Range Fuels. 

 Cello Energy had just started up a 20 million gallon per year (MGY) cellulosic diesel 

plant in Bay Minette, AL. EPA staff visited the facility twice in 2009 to confirm that the first-ofits-kind commercial plant was mechanically complete and poised to produce cellulosic biofuel. 

It was assumed that start-up operations would go as planned and that the facility would be 

operating at full capacity by the end of 2009 and that three more 50 MGY cellulosic diesel plants 

planned for the Southeast could be brought online by the end of 2010. 

At the time of our assessment, we were also anticipating cellulosic biofuel production 

from Range Fuels’ first commercial-scale plant in Soperton, GA. The company received a $76 

million grant from DOE to help build a 40 MGY wood-based ethanol plant and they broke 

ground in November 2007. In January 2009, Range was awarded an $80 million loan guarantee 

from USDA. With the addition of this latest capital, the company seemed well on its way to 

complete construction of its first 10 MGY phase by the end of 2009 and begin production in 

2010. 

 Since our April 2009 industry assessment there have been a number of changes and 

delays in production plans due to technological, contractual, financial and other reasons. Cello 

Energy and Range Fuels have delayed or reduced their production plans for 2010. Some of the 

small plants expected to come online in 2010 have pushed back production to the 2011-2012 

timeframe, e.g., Clearfuels Technology, Fulcrum River Biofuels, and ZeaChem. Alltech/Ecofin 

and RSE Pulp & Chemical, two companies that were awarded DOE funding back in 2008 to 

build small-scale biorefineries appear to be permanently on hold or off the table. In addition, 

Bell Bioenergy, a company that received DOD funding has since abandoned plans to build 

additional cellulosic diesel plants at U.S. military bases.55 

 At the same time, there has also been an explosion of new companies, new business 

relationships, and new advances in the cellulosic biofuel industry. Keeping track of them all is a 

challenge in and of itself as the situation can change on a daily basis. EIA recently provided 

EPA with their first cellulosic biofuel supply estimate required under CAA section 

 

55 Bell Bioenergy is currently investigating MSW generated by the State of California. 
172

211(o)(7)(D)(i). In a letter to the Administrator dated October 29, 2009, they arrived at a 5.04 

million gallon estimate for 2010 based on publicly available information and assumptions made 

with respect production capacity utilization.56 A summary of the plants they considered is shown 

below in Table 1.5-25. 

Table 1.5-25. 

EIA’s Projected Cellulosic Biofuel Plant Production Capacities for 2010 

 In addition to receiving EIA’s information and coordinating with them and other offices 

in DOE, we have initiated meetings and conversations with over 30 up-and-coming advanced 

biofuel companies to verify publicly available information, obtain confidential information, and 

better assess the near-term cellulosic biofuel production potential for use in setting the 2010 

standard. What we have found is that the cellulosic biofuel landscape has continued to evolve. 

Based on information obtained, not only do we project significantly different production 

volumes on a company-by-company basis, but the list of potential producers of cellulosic biofuel 

for 2010 is also significantly different than that identified by EIA. 

 Overall, our industry assessment suggests that it is difficult to rely on commercial 

production from small pilot or demonstration level plants. The primary purpose of these 

facilities is to prove that a technology works and demonstrate to investors that the process is 

capable of being scaled up to support a larger commercial plant. Small plants are cheaper to 

build to demonstrate the technology than large commercial plants, but the operating costs ($/gal) 

are high due to their small scale. As a result, it’s not economical for most of these facilities to 

operate continuously. Most of these plants are regularly shut down and restarted as needed as 

part of the research and development process. Due to their intermittent nature, most of these 

plants operate at a fraction of their rated capacity, some less than the 10% assumed by EIA. In 

addition, few companies plan on making their biofuel available for commercial sale. 

 However, there are at least two cellulosic biofuel companies currently operating 

demonstration plants in the U.S. and Canada that could produce fuel commercially in 2010. The 

first is KL Energy Corporation, a company we considered for the NPRM with a 1.5 MGY 

 

56 October 29, 2009 letter from Richard Newell, EIA Administrator to Lisa Jackson, EPA Administrator 
 

173

cellulosic ethanol plant in Upton, WY. This plant was considered by EIA and is included in their 

final plant summary presented in Table 1.5-25. The second is Iogen’s cellulosic ethanol plant in 

Ottawa, Canada with a 0.5 MGY capacity. Iogen’s commercial demonstration plant was 

referenced by EIA as a potential foreign source for cellulosic biofuel but was not included in 

their final table. In addition to these online demonstration plants, there are three additional 

companies not on EIA’s list that are currently building demonstration-level cellulosic biofuel 

plants that are scheduled to come online in 2010. This includes DuPont Danisco Cellulosic 

Ethanol and Fiberight, companies currently building demonstration plants in the U.S. and 

Enerkem, a company building a demonstration plant in Canada. Cello Energy’s Bay Minette, 

AL plant continues to offer additional potential for cellulosic biofuel in 2010. And finally, 

Dynamotive, a company that currently has two biomass-based pyrolysis oil production plants in 

Canada is another potential source of cellulosic biofuel in 2010. All seven aforementioned 

companies are discussed in greater detail below along with Range Fuels. 

KL Energy Corporation (KL Energy), through its majority-owned Western Biomass 

Energy, LLC (WBE) located in Upton, WY, is designed to convert wood products and wood 

waste products into ethanol. Since the end of construction in September 2007, equipment 

commissioning and process revisions continued until the October 2009 startup. The plant was 

built as a 1.5 MGY demonstration plant and was designed to both facilitate research and operate 

commercially. It is KL Energy’s intent that WBE’s future use will involve the production and 

sale of small but commercial-quality volumes of ethanol and lignin co-product. The company’s 

current 2010 production goal is for WBE to generate RINs under the RFS2 program. 

 Iogen is responsible for opening the first commercial demonstration cellulosic ethanol 

plant in North America. Iogen’s plant located in Ottawa, Canada has been producing cellulosic 

ethanol from wheat straw since 2004. Like KL Energy, Iogen has slowly been ramping up 

production at its 0.5 MGY plant. According to the company’s website, they produced 

approximately 24,000 gallons in 2004 and 34,000 gallons in 2005. Production dropped 

dramatically in 2006 and 2007 but came back strong with 55,000 gallons in 2008. To date, Iogen 

has produced over 127,000 gallons of ethanol from the demonstration plant in 2009. Iogen also 

recently became the first cellulosic ethanol producer to sell its advanced biofuel at a retail service 

station in Canada. Their cellulosic ethanol was blended to make E10 available for sale to the 

consumers at an Ottawa Shell station. Iogen also recently announced plans to build its first 

commercial scale plant in Prince Albert, Saskatchewan in the 2011/2012 timeframe. Based on 

the company’s location and operating status, Iogen certainly has the potential to participate in the 

RFS2 program. However, at this time, we are not expecting them to import any cellulosic 

ethanol into the U.S. in 2010.57 

 DuPont Danisco Cellulosic Ethanol, LLC (DDCE), a joint venture between Dupont and 

Danisco, is another potential source for cellulosic biofuel in 2010. DDCE received funding from 

the State of Tennessee and the University of Tennessee to build a small 0.25 MGY 

demonstration plant in Vonore, TN to pursue switchgrass-to-ethanol production. According to 

DDCE, construction commenced in October 2008 and the plant is now mechanically complete 

and currently undergoing start-up operations. The facility is scheduled to come online in January 

 

57 Based on comments submitted in response to our proposal and a recent follow-up discussion with company 

officials. 
174

and the company hopes to operate at or around 50% of production capacity in 2010. According 

to the DDCE, the objective in Vonore is to validate processes and data for commercial scaleup, not to make profits. However, the company does plan to sell the cellulosic ethanol it 

produces. 

 Enerkem is another company pursuing cellulosic ethanol production. The Canadianbased company was recently announced as a recipient of a $50 million grant from DOE to build 

a 10 MGY woody biomass-to-ethanol plant in Pontotoc, MS. The U.S. plant is not scheduled to 

come online until 2012, but Enerkem is currently building a 1.3 MGY demonstration plant in 

Westbury, Quebec. According to the company, plant construction in Westbury started in 

October 2007 and the facility is currently scheduled to come online around the middle of 2010. 

While it’s unclear at this time whether the cellulosic ethanol produced will be exported to the 

United States, Enerkem has expressed interest in selling its fuel commercially. 

 Additional cellulosic biofuel could come from Fiberight, LLC (Fiberight) in 2010. We 

recently became aware of this start-up company and contacted them to learn more about their 

process and cellulosic biofuel production plans. According to Fiberight, they have been 

operating a pilot-scale facility in Lawrenceville, VA for three years. They have developed a 

proprietary process that not only fractionates MSW but biologically converts the non-recyclable 

portion into cellulosic ethanol and biochemicals. Fiberight recently purchased a shut down corn 

ethanol plant in Blairstown, IA and plans to convert it to become MSW-to-ethanol capable. 

According to the company, construction is currently underway and the goal is to bring the 2 

MGY demo plant online by February or March, 2010. If the plant starts up according to plan, 

the company intends on making cellulosic ethanol commercially available in 2010 and 

generating RINS under the RFS2 program. Fiberight’s long-term goal is to expand the 

Blairstown plant to a 5-8 MGY capacity and build other small commercial plants around the 

country that could convert MSW into fuel. 

Cello Energy, a company considered in the proposal, continues to be another viable 

source for cellulosic biofuel in 2010. Despite recent legal issues which have constrained the 

company’s capital, Cello Energy is still pursuing cellulosic diesel production. According to the 

company, they are currently working to resolve materials handling and processing issues that 

surfaced when they attempted to scale up production to 20 MGY from a previously operated 

demonstration plant. As of November 2009, they were waiting for new equipment to be ordered 

and installed which they hoped would allow for operations to be restarted as early as February or 

March, 2010. Cello’s other planned commercial facilities are currently on hold until the Bay 

Minette facility is operational. 

 

 Another potential supplier of cellulosic biofuel is Dynamotive Energy Systems 

(Dynamotive) headquartered in Vancouver, Canada. As shown in Table 1.5-24, Dynamotive 

currently has two plants in West Lorne and Guelph, Ontario that produce biomass-based 

pyrolysis oil (also known as “BioOil”) for industrial applications. The BioOil production 

capacity between the two plants is estimated at around 9 MGY, but both plants are currently 

operating at a fraction of their rated capacity.58 However, according to a recent press release, 

 

58 According to Dynamotive’s website, the Guelph plant has a capacity to convert 200 tonnes of biomass into BioOil 

per day. If all modules are fully operational, the plant has the ability to process 66,000 dry tons of biomass per year 
 

175

Dynamotive has contracts in place to supply a U.S.-based client with at least nine shipments of 

BioOil in 2010. If Dynamotive’s BioOil is used as heating oil or upgraded to transportation fuel, 

it could potentially count towards meeting the cellulosic biofuel standard in 2010. 

 As for the Range Fuels plant, construction of phase one in Soperton, GA is about 85% 

complete, with start-up planned for mid-2010. However, there have been some changes to the 

scope of the project that will limit the amount of cellulosic biofuel that can be produced in 2010. 

The initial capacity has been reduced from 10 to 4 million gallons per year. In addition, since 

they plan to start up the plant using a methanol catalyst they are not expected to produce 

qualifying renewable fuel in 2010. During phase two of their project, currently slated for mid2012, Range plans to expand production at the Soperton plant and transition from a methanol to 

a mixed alcohol catalyst. This will allow for a greater alcohol production potential as well as a 

greater cellulosic biofuel production potential. 

 

Overall, our most recent industry assessment suggests that there are six companies that 

could potentially produce cellulosic biofuel next year. Together these seven plants, summarized 

in Table 1.5-26, could have over 30 MGY of cellulosic biofuel plant capacity online by the end 

of 2010. However, the actual volume of cellulosic biofuel realized under the RFS2 program will 

likely be much lower, as explained in more detail below. 

 with an energy output equivalent to 130,000 barrels of oil. The West Lorne plant has a capacity to convert 130 

tonnes of biomass into BioOil per day (which, if proportional to the Guelph plant, translates to an energy-equivalent 

of 84,500 barrels of oil. According to a November 3, 2009 press release, Dynamotive has contracts in place to 

supply a U.S.-based client with at least nine shipments of BioOil in 2010. 
176

Table 1.5-26 

EPA’s Cellulosic Biofuel Plant Assessment – Projected Capacity Online by End of 2010 

KL Energy Corp / WBE Upton, WY Demo (C) 1.50 On-Line Ethanol Wood chipsFiberight Blairstown, IA Demo (C) 2.00 Under Construction Mar-10 Ethanol Sorted MSWEnerkem Westbury, Quebec (CAN) Demo 1.30 Under Construction Jun-10 Ethanol Treated woodDynamotive Guelph, Ontario (CAN) Demo (C) 5.46 On-Line Py Oil Waste wood, wood chipsDynamotive West Lorne, Ontario (CAN) Demo (C) 3.55 On-Line Py Oil Waste woodDuPont Dansico (DDCE) Vonore, TN Demo 0.25 Undergoing Start-Up Jan-10 Ethanol Corn cobs then switchgrassCello Energy Bay Minette, AL Demo (C) 20.00 Currently Off-Line Mar-09 Diesel Wood chips, hayCompany/Plant Name

Max Cap

(MGY) Type Cellulosic Feedstocks

Plant Cell

Biofuel Plant Location Status

Operational Proj. Op. 

Date
 

177

Since most of the plants in Table 1.5-26 are still under construction today, the amount of 

cellulosic biofuel produced in 2010 will be contingent upon when and if these plants come online 

and whether the projects get delayed due to funding or other reasons. In addition, based on our 

discussions with the developing industry, it is clear that we cannot count on demonstration plants 

to produce at or near capacity in 2010, or in their first few years of operation for that matter. The 

amount of cellulosic biofuel actually realized will depend on whether the process works, the 

efficiency of the process, and how regularly the plant is run. As mentioned earlier, most small 

plants, including commercial demonstration plants, are not operated continuously. As such, we 

cannot base the standard on these plants running at capacity - at least until the industry develops 

further and proves that such rates are achievable. We currently estimate that production from 

first-of-it’s kind plants could be somewhere in the 25-50% range in 2010. Together, the 

implementation timelines and anticipated production levels of the plants described above brings 

the cellulosic biofuel supply estimate to somewhere in the 6-13 million gallon range for 2010. 

In addition, it is unclear how much was can rely on Canadian plants for cellulosic biofuel 

in 2010. Although we currently receive some conventional biofuels imports from Canada and 

many of the aforementioned Canadian companies have U.S. markets in mind, the country also 

has its own renewable fuel initiatives that could keep much of the cellulosic biofuel produced 

from coming to the United States, e.g., Iogen. Finally, it’s unclear whether all fuel produced by 

these facilities will qualify as cellulosic biofuel under the RFS2 program. Several of the 

companies are producing fuels or using feedstocks which may not in fact qualify as cellulosic 

biofuel once we receive their detailed registration information. Factoring in these considerations, 

the cellulosic biofuel potential from the six more likely companies described above could result 

in several different production scenarios in the neighborhood of the recent EIA estimate. We 

believe this estimate of 5 million gallons or 6.5 ethanol-equivalent million gallons represents a 

reasonable yet achievable level for the cellulosic biofuel standard in 2010 considering the degree 

of uncertainty involved with setting the standard for the first year. As mentioned earlier, we 

believe standard setting will be easier in future years once the industry matures, we start 

receiving production outlook reports and there is less uncertainty regarding feasibility of 

cellulosic biofuel production. 

1.5.3.3 Current Outlook for 2011 and Beyond 

 Since the proposal, we have also learned about a number of other cellulosic biofuel 

projects in addition to those described above. This includes commercial U.S. production plans 

by Coskata, Enerkem and Vercipia. However, production isn’t slated to begin until 2011 or later 

and the same is true for most of the other larger plants we’re aware of that are currently under 

development. Nonetheless, while cellulosic biofuel production in 2010 may be limited, it is 

remarkable how much progress the industry has made in such a short time, and there is a 

tremendous growth opportunity for cellulosic biofuels over the next several years. 

 Most of the cellulosic biofuel companies we’ve talked to are in different stages of 

proving their technologies. Regardless of where they are at, many have fallen behind their 

original commercialization schedules. As with any new technology, there have been delays 

associated with scaling up capacity, i.e., bugs to work out going from pilot to demonstration to 

commercialization. However, most are saying it’s not the technologies that are delaying 
178

commercialization, it is lack of available funding. Obtaining capital has been very challenging 

given the current recession and the banking sector's financial difficulties. This is especially true 

for start-up companies that do not have access to capital through existing investors, plant profits, 

etc. From what we understand, banks are looking for cellulosic companies to be able to show 

that their plants are easily “scalable” or expandable to commercial size. Many are only 

considering companies that have built plants to one-tenth of commercial scale and have logged 

many hours of continuous operation. 

 The government is currently trying to help in this area. To date, the Department of 

Energy (DOE) has allocated over $680 million in federal funding to help build pilot and 

demonstration-scale biorefineries employing advanced technologies across the United States.59 

The largest installment from Recovery Act funding was recently announced on December 4, 

2009 and includes funding for a series of larger commercial demonstration plants including 

cellulosic ethanol projects by Enerkem and INEOS New Planet BioEnergy, LLC. DOE has also 

issued grants and loan guarantees to help fund some of the first commercial cellulosic biofuel 

plants. Current recipients include Abengoa Bioenergy), BlueFire Ethanol and POET Biorefining 

in addition to previously-mentioned Range Fuels. The Food, Conservation, and Energy Act of 

2008 (also known as the “2008 Farm Bill”) is also helping to support the up-and-coming 

cellulosic biofuels industry. 

 The 2008 Farm Bill assists the cellulosic biofuel industry in many ways. First, it 

modified the $0.51/gal alcohol blender credit to give preference to ethanol and other biofuels 

produced from cellulosic feedstocks. Effective January 1, 2009, corn ethanol receives a reduced 

tax credit of $0.45/gal while cellulosic biofuel earns a credit of $1.01/gal.60 In addition, the Farm 

Bill contains provisions that enable USDA to assist with the commercialization of secondgeneration biofuels, explained in more detail below. 

 Section 9003, also known as the Biorefinery Assistance Program, promotes the 

development of new and emerging technologies for the production of advanced biofuels - 

defined as fuels that are not produced from food sources. The program provides loan guarantees 

to develop, construct and retrofit viable commercial-scale biorefineries producing advanced 

biofuels. The maximum loan guarantee is $250 million per project. The program is designed to 

create energy-related jobs and economic development in rural America. On January 16, 2009, the 

USDA Rural Development approved its first ever loan guarantee to Range Fuels. As mentioned 

earlier, Range received an $80 million loan from USDA to help build its Soperton, GA plant.61 

Section 9004 of the 2008 Farm Bill 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, 

 

59 On January 29, 2008 DOE announced that it would provide $114 million to fund 4 small scale biorefineries. On 

April 18, 2008, DOE announced that it would provide another $86 million to help fund three additional small-scale 

plants. And recently, on December 4, 2009, DOE announced that up to $483 million would be made available to 

fund 14 pilot-scale and 4 demonstration-scale biorefineries across the country. For more on these projects, refer top 

Section 1.5.3 of the RIA. 

60 Refer to Part II, Subparts A and B (Sections 15321 and 15331). 61 USDA also recently issues a $54.5 million loan guarantee to Sapphire Energy to help demonstrate an integrated 

algal biorefinery process in Columbus, NM. For more information on Sapphire and other algae-based biodiesel 

projects, refer to Section 1.5.4.3 of the RIA. 
 

179

contracts and financial assistance to enable eligible entities to carry out research, development, 

and demonstration of biofuels and biomass-based based products. 

 In addition to helping fund a series of small-scale cellulosic biofuel plants, the DOE and 

USDA are helping to fund critical research to help make cellulosic biofuel production more 

commercially viable. In March 2007, DOE awarded $23 million in grants to four companies and 

one university to develop more efficient microbes for ethanol refining.ccclxii 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.ccclxiii 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.ccclxiv 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.ccclxv 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.ccclxvi On 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.ccclxvii And, as mentioned above, on December 4, 2009, DOE announced that it would 

provide $564 million in stimulus funding to 19 projects aimed at turning biomass into fuels 

chemicals and power. 

 Numerous states are also offering grants and tax incentives to help encourage biofuel 

production. Most of the efforts are currently centered on expanding existing production and 

developing sustainable, second-generation feedstocks, technologies and fuels. According to a 

recent assessment of DOE’s Energy Efficiency and Renewable Energy (EERE) website, over 20 

states currently offer some form of production incentive for advanced biofuels, including but not 

limited to those made from cellulosic materials. The incentives range from grants, loan 

guarantees and tax breaks for advanced biofuel producers to support for technology development 

to support for feedstock development. 

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 Governors Association (MGA). States that have signed on to the MGA goals include 

Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Missouri, Ohio, South Dakota and 

Wisconsin. In 2007, the MGA adopted the Midwest Energy Security and Climate Stewardship 

Platform.ccclxviii 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. In 2009, the MGA approved a follow-up 

infrastructure initiative called the Midwestern Energy Infrastructure which includes the 

governors support for building out a bio refueling system throughout the region. 
180

 The refining industry is also helping to further cellulosic biofuel R&D efforts and fund 

some of the first commercial plants. Many of the major oil companies have invested in advanced 

second-generation biofuels over the past 12-18 months. A few refiners (e.g., BP and Shell) have 

even entered into joint ventures to become cellulosic biofuel producers. General Motors and 

other vehicle/engine manufacturers are also providing financial support to help with research and 

development. 

 A summary of some of the cellulosic biofuel companies with near-term 

commercialization plans in North America is provided in 1.5-27. The capacities presented 

represent maximum annual average throughput based on each company’s current production 

plans. However, as noted, capacity does not necessarily translate to production. Actual 

production of cellulosic biofuel will likely be well below capacity, especially in the early years 

of production. We will continue to track these companies and the cellulosic biofuel industry as a 

whole throughout the duration of the RFS2 program. In addition, we will continue to collaborate 

with EIA in annual standard setting. A more detailed description of the new (commercial 

demonstration and larger) plants corresponding to these company estimates is provided in Tables 

1.5-28 and 1.5-29.
181

Table 1.5-27. Potential Growth in Cellulosic Biofuel Capacity by Company and Year* 

Today Dec-10 Dec-11 Dec-12 Dec-13 2014+

Abengoa Ethanol 0.02 0.02 0.02 16.02 16.02 16.02

AE Biofuels Ethanol 0.15 0.15 15.15 20.15 20.15 20.15

BlueFire Ethanol Ethanol - - - - - 21.90

Cello Energy Diesel - 20.00 20.00 20.00 20.00 120.00

CMEC / SunOpta Ethanol - - - - - 10.00Coskata Ethanol 0.04 0.04 0.04 50.04 50.04 100.04

Dynamotivea BioOil 9.00 9.00 9.00 9.00 9.00 9.00

Enerkem Ethanol - 1.30 11.30 21.30 21.30 41.30Fiberight Ethanol - 2.00 6.50 6.50 6.50 6.50

Flambeau River Biofuels Diesel - - - 8.00 8.00 8.00

Fulcrum Bioenergy Ethanol - - - 10.50 10.50 10.50Inbicon / Great River Energy Ethanol - - - - 20.00 20.00

INEOS Bio / New Planet Energy Ethanol - - 8.00 8.00 8.00 8.00Iogen Ethanol 0.50 0.50 0.50 23.50 23.50 23.50

KL Energy Ethanol 1.50 1.50 1.50 1.50 1.50 6.50

Mascoma Corporation Ethanol 0.20 0.20 0.20 2.20 20.20 80.20

New Page Diesel - - - 2.50 2.50 2.50Ohio River Clean Fuels / Baardb Diesel, Naphtha - - - - - 17.00

POET Biorefining Ethanol 0.02 0.02 25.02 25.02 25.02 25.02

Range Fuels Methanol, Ethanol - 4.00 4.00 30.00 30.00 100.00Rentechc Diesel - - 0.15 7.15 7.15 7.15

Vercipia (Verenium/BP JV) Ethanol 1.40 1.40 1.40 37.40 37.40 37.40

Maximum Plant Capacity (MGY) 12.83 40.13 102.78 298.78 336.78 690.68

Capacity Expansion Plans (MGY)

Biofuel(s)

Plant will co-process biomass and coal. It is unclear at this time how much fuel would come from biomass and potentially quali bCapacity has been estimated. a

Cellulosic Company

fy as 

c

cellulosic biofuel.

Includes Clearfuels demo plant and Silvagas commercial plant.

*Capacity, not actual production
182

Table 1.5-28. 

Promising New Cellulosic Alcohol Plants 

Cap

(MGY)

Op

Date

Cap

(MGY) Date A

Op

R EC W UW

Abengoa Bioenergy Corporationac Hugoton, KS 16.00 2012 Ethanol Bio X X

AE Advanced Fuels - Keyesc,d Keyes, CA 15.00 2011 20.00 2012 Ethanol Bio X XCentral Minnesota Cellulosic Ethanol PartnersBlueFire Ethanol Fulton, MS 18.00 TBD Ethanol Bio XBlueFire Ethanol Lancaster, CA 3.90 TBD Ethanol Bio X X

c Little Falls, MN 10.00 TBD Butanol Bio X

POET Project LibertyMascoma Corporation / Frontier Resources Kinross, MI 2.00 2012 20.00 2013 Ethanol Bio XKL Energy Corp Kremmling, CO 5.00 TBD Ethanol Bio XIogen Corporation Prince Albert (CAN) 23.00 2012 Ethanol Bio XINEOS Bio / New Planet Bioenergy, LLC Vero Beach, FL 8.00 End-2011 Ethanol Thermo X XInbicon / Great River Energy Spiritwood, ND 20.00 2013 Ethanol Bio XFulcrum Bioenergy - Sierra BioFuels Plant McCarran, NV 10.50 Mid-2012 Ethanol Thermo XFiberight (former Xethanol plant) Blairstown, IA 2.00 End-2010 6.50 2011 Ethanol Bio XEnerkem GreenField Alberta Biofuels (EGAB) Edmonton (CAN) 10.00 2011 20.00 TBD Ethanol Thermo XEnerkem Pontotoc, MS 10.00 2012 20.00 2015 Ethanol Thermo X XCoskata / U.S. Sugar Corp. Clewston, FL 50.00 2012 100.00 TBD Ethanol Thermo X

c Emmetsburg, IA 25.00 End-2011 Ethanol Bio X

Range Fuelse Soperton, GA 30.00 2012 100.00 TBD Methanol Thermo X X

Cell. Feedstocksb

Cell. 

Biofuel

Cell. 

Tech.a

b

Conversion technology. Bio = Biochemical, Thermo = Thermochemical. aFeedstocks. AR = Ag residues, EC = Energy crops, W = Wood waste, chips, mill waste, etc., UW = Urban waste including sorted MSW and C&D debris.Will start off producing methanol and then switch catalysts and shift to producing a mix of methanol and ethanol. e

Will start off processing corn and then transition to cellulosic feedstocks. d

Cellulosic ethanol plant will be co-located with an existing corn ethanol plant. c

Company/Plant Name

Production Goal Current Plan

Plant Location
183

Table 1.5-29 

Promising New Cellulosic Hydrocarbon Plants 

Cap

(MGY) Date

Op Cap

(MGY) Date AR EC W UW

Op

Flambeau River BiofuelsCello Energy Alabama (TBA) 50.00 TBD Diesel Cat X XCello Energy Georgia (TBA) 50.00 TBD Diesel Cat X X

c Park Falls, WI 8.00 2012 Diesel Thermo X

New Page - Project Independencec Wisconsin Rapids, WI 2.50 Early-2012 Diesel Thermo XOhio River Clean Fuels, LLC / Baardd Wellsville, OH 17.00 2014 Diesel, Naphtha Thermo X XRentech / Rialto Renewable Energy Center Rialto, CA 7.00 End-2012 Diesel Thermo X

Cell. Feedstocksb

Cell.

Biofuel

Cell. 

Tech.a

b

Conversion technology. Bio = Biochemical, Thermo = Thermochemical. aFeedstocks. AR = Ag residues, EC = Energy crops, W = Wood waste, chips, mill waste, etc., UW = Urban waste including sorted MSW and C&D debris.

d

Capacities excludes heavy distillate/wax production. c

Plant will co-process biomass and coal. It is unclear at this time how much fuel would come from biomass and potentially qualify as cellulosic biofuel.

Company/Plant Name

Production Goal Current Plan

Plant Location
184

1.5.3.4 Construction Feasibility for Cellulosic Biofuel Industry

 Start-up of cellulosic biofuel plants (alcohol or hydrocarbon) 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 biofuel 

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 1.5-13 depicts these construction trends. 

Figure 1.5-13. 

Historic and projected plant starts and projection capacity 2001-2022.a

0

5

10

15

20

25

30

2002

2004

2006

2008

2010

2012

2014

2016

2018

2020

2022

Plant starts/yr

0

5

10

15

20

25

30

35

Bgal capacity/yr

Starch Plant Starts Cellulosic Plant Starts Total Biofuel Capacity

2009 and later data are projected

a Volumes do not include biodiesel or renewable diesel. 

 Historical plant build rates for starch ethanol were derived from information in 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. 
 

185

 For cellulosic biofuel 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 volume of cellulosic biofuel projected, 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 1.2-30 shows a summary of the figures used in the analysis. 

Table 1.5-30. 

Summary of figures used in the biofuel plant construction rate analysis 2001-2022.a

Build Avg Plant Capacity Industry Build Avg Plant Capacity Industry

Rate b Capacity c Change Capacity Rate b Capacity c Change Capacity

Year Starts/yr Mgal/yr Bgal/yr Bgal/yr Starts/yr Mgal/yr Bgal/yr Bgal/yr

2001 1.7

2002 6 50 0.3 2.0

2003 14 50 0.7 2.7

2004 12 50 0.6 3.3

2005 10 50 0.5 3.8

2006 16 50 0.8 4.6

2007 17 100 1.7 6.3

2008 26 100 2.6 8.9

2009 13 100 1.3 10.2

2010 10 100 1.0 11.2 2 40 0.1 0.1

2011 9 100 0.9 12.1 3 40 0.1 0.2

2012 7 100 0.7 12.8 4 40 0.2 0.4

2013 6 100 0.6 13.4 9 40 0.4 0.7

2014 14.0 7 80 0.5 1.3

2015 15.0 11 80 0.9 2.1

2016 15.0 11 80 0.9 3.0

2017 15.0 11 80 0.9 3.9

2018 15.0 11 100 1.1 5.0

2019 15.0 11 100 1.1 6.1

2020 15.0 14 100 1.4 7.5

2021 15.0 21 100 2.1 9.7

2022 15.0 18 100 1.8 11.4

Starch Ethanol Cellulosic Biofuel

a

 Figures for 2009 and later are projected; volumes do not include biodiesel or renewable diesel. 

b

 Build rate is an approximate figure, derived from other figures used in this analysis. 

c

 Average plant capacity is an approximate figure based on historical ethanol industry trends. 

 This analysis suggests that it is feasible to construct plants quickly enough to meet the 

cellulosic standard if plant starts can reach a rate similar to that of starch ethanol plants in recent 

years. Given that cellulosic biofuel technology is still developing, some types of plants may be 

considerably more complex and expensive to construct than starch ethanol plants. Therefore, we 

believe the market will need to react even more enthusiastically with capital funding, design and 

construction resources. 
186

1.5.4 Biodiesel & Renewable Diesel

1.5.4.1 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 

rapidly, going from a sparse network of small businesses selling locally to one with large 

companies selling internationally in less than a decade. As of November 2009, the aggregate 

production capacity of biodiesel plants in the U.S. was estimated at 2.8 billion gallons per year 

across approximately 191 facilities, with a mean size of 16 million gallons per year and a median 

size of just 6 million gallons per year.369 Table 1.5-31 shows historical aggregate capacity, sales 

volumes, and other information related to biodiesel production and use. 

Table 1.5-31. Recent biodiesel industry production and use trends.

370

Year Domestic 

production 

capacity 

Domestic 

total 

production 

Apparent 

capacity 

utilization 

Net domestic 

biodiesel use 

Net domestic use 

as percent of 

production 

2004 245 28 11% 27 96% 

2005 395 91 23% 91 100% 

2006 792 250 32% 261 104% 

2007 1,809 490 27% 358 73% 

2008 2,610 776 30% 413 53% 

2009 2,806 448 (est.) 16% 233 (est.) 55% 

 The average capacity utilization had been steady around 30% during 2006-2008 due to 

continued expansion of on-line capacity despite apparently adequate existing capacity. Reasons 

for this include various state incentives to build plants, along with state and federal incentives to 

blend and sell biodiesel, which have given rise to an optimistic industry outlook over the past 

several years. However, in 2009 we expect utilization to be about half this level, due to a steep 

decline in exports as a result of European trade barriers enacted early in the year, as well as a 

drop in U.S. diesel prices which has made biodiesel relatively more expensive. 

 We can speculate that sustained low capacity utilization has been feasible for this 

industry because of the relatively low capital cost (typically 5-10% of total per-gallon production 

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 plants may also 

produce 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 apparent feasibility of sustained over-capacity and the variety of 

useable feedstocks. In the absence of other information, we made the assumption that the 
 

187

demand for biodiesel would stabilize at the level of the standard (1.67 billion gallons in 2022), 

which seemed reasonable given the relatively high cost for biodiesel feedstocks as well as the 

perennially uncertain status of the 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 of existing plants, and capabilities for 

handling multiple feedstock types. This information was gathered from a database of member 

plants maintained by the National Biodiesel Board, and a summary of tax incentives from the 

Department of Energy website. 371 Existing plants with affirmative status for more of these 

factors were expected to be more likely to survive over those that had fewer. We also 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. 

 We project that between now and 2022 the number of plants will decline by about 30%, 

pushing capacity utilization above 80%. It is expected that plants will continue to operate in 44 

states. During this period most plants will have added the pre-treatment and feedstock 

segregation capacity to process any mix of feedstock types available in their area. 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 re-sale. Table 1.5-32 summarizes key parameters of the 

industry as it is currently and in the 2022 forecast. 

Table 1.5-32. Summary of current biodiesel industry and forecast.372

 2008 2022 

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

Number of operating plants 176 121 

Median plant size (million gal/yr) 5 5 

Total biodiesel production (million gal) 776 1,670 

Average plant utilization 0.30 0.85 

1.5.4.2 Renewable Diesel 

 For a period of time in 2007 and 2008, ConocoPhilips produced small quantities (300-

500 bbl/day) of renewable diesel at their Borger, Texas, refinery from beef tallow generated by 

Tyson Foods, Inc. in Amarillo, Texas. 373 This operation was stopped primarily due to changes 

in tax law that reduced the subsidy for renewable diesel products being coprocessed with 

petroleum at refineries. 

 In fall of 2008, Dynamic Fuels, LLC (a joint venture of Syntroleum Corp. and Tyson 

Foods, Inc.) announced construction of a 75 million gallon per year plant (5,000 bbl/day) in 

Geismar, Louisiana, that will use Tyson meat processing byproducts as feedstock to 

Syntroleum’s Bio-Synfining 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. 

374 The Geismar 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.375 
188

However, it is not co-located with existing petroleum production, and therefore would be 

considered a stand-alone facility in our analyses. 

 Our industry projection is based on the expectation of that Dynamic Fuels, LLC, will 

construct and operate two facilities like the one underway in Geismar, LA, during our analysis 

period. 376 It is conceivable that more facilities will be built by Dyanmic Fuels or other 

companies (such as Neste), but we felt there was too much uncertainty to project volumes, given 

the large capacity for biodiesel production already on-line. Also, considering tax subsidy and 

RIN incentives putting co-processed renewable diesel at a disadvantage, we’ve chosen to assume 

all renewable diesel is produced in stand-alone facilities. 

1.5.4.3 Algae-Based Biofuel 

Recently, there has been a renewed interest in the production of algae-based biofuels and 

a growth in number of technology providers. To give a sense of the size of the industry, we’ve 

developed a list of over 70 companies from various locations around the world and summarized 

a basic description of their technologies for algae production. See Table 1.5-33. This list is 

current as of November 2, 2009 and is based mainly on biofuel magazines and articles that are 

supplemented with company websites. As new information is available on a near daily basis, it 

is possible that we have not included newly formed companies or those not highly publicized. 

Companies that have announced timelines for algae-based biofuel production include: 

Sapphire Energy for 135 MMgal by 2018 and 1 Bgal by 2025, Petrosun for 30 MMgal/yr facility 

in Arizona, Solazyme for 100 MMgal by 2012/13 and US Biofuels for 4 MMgal by 2010, 50 

MMgal by full scale. It is important to realize that future projections are highly uncertain, and 

we have taken into account the best information we could acquire at the time. For more 

information on algae as a feedstock for biofuel, refer to Section 1.1.3.4. 

Table 1.5-33. Companies Developing Algae Production TechnologiesJJJ

Company Name Technology 

Headquarters & 

Facilities 

A2BE Carbon Capture 

Closed PBR algae system 

recycling CO2 from industries. Boulder, Colorado 

Advanced Lab Group 

Polyethylene film for closed 

PBRs, wants to reduce costs 

for harvesting and dewatering, 

heat venting for closed 

systems, and reduce oil 

extraction and process costs. Santa Monica, California 

Alfa Laval 

Algae/water separability tests 

using different centrifuge test 

units. Headquarters in Sweden 

Algae Venture Systems 

Develops harvesting, 

dewatering, and drying of Marysville, Ohio 

 

JJJ Although we provide this summary here, we caveat that we have not confirmed the statements made on the 

company websites or on the data collected from news magazine/articles. For latest information please refer to the 

company’s website or contact the company’s representatives. Blanks occur where information was not available or 

found. 
 

189

algae technology. 

AlgaeLink 

Uses photobioreactor (PBR) 

technology and has expertise 

in extracting oil and biomass. 

Offers algae production 

capacity for a farm of 250 ton 

dry algae per day. 

Dutch-based, plant in the 

Netherlands 

Algenol Biofuels 

Direct to ethanol process, 

using algae, sunlight, CO2, 

and seawater. Produces 

ethanol at rate of 6,000 

gallons per acre per year, 

targeting 10,000 gallons per 

acre per year. Ethanol is 

produced inside each algae 

cell. Uses hybrid algae in 

sealed, clear plastic 

photobioreactors. 

Plans first US plant in 

Florida or Texas. One in 

development in Sonora, 

Mexico with company 

called BioFields. 

Corporate headquarters in 

Naples, Florida. Goal is to 

have 4 sites in US by 

2010, target Florida, 

Texas, Arizona, New 

Mexico. Announced on 

June 29, 2009, demo 

plans of 3,100 bioreactors 

on a 24-acre site at Dow's 

Freeport, Texas site. 

Aquaflow Bionomic Corporation 

Produce biofuel from wild 

algae harvested from open air 

environments, clean-up algaeinfested polluted water 

systems. New Zealand 

Aquatic Energy 

Proprietary strain of algae for 

continuous outdoor growth, 

filed patents for growth and 

harvesting techniques. 

Interested in developing, 

constructing, and operating 

open pond algae farms. 

Headquarters in Lake 

Charles, Louisiana; 

Couple of acre pilot facility 

in Lake Charles 

Aurora Biofuels 

Use genetically-modified 

algae to generate oil for 

production of biodiesel. Uses 

seawater-fed, open ponds. 

Has produced slightly under 

1,000 gallons oil per year from 

1/8th acre surface area. The 

company estimates that will 

translate into 6,000 

gallons/yr/acre at commercial 

size. The company uses 

waste water technology and a 

wet extraction process instead 

of the traditional process of 

centrifugation and drying. On 

August 18, 2009 announced 

that it had optimized particular 

algae strains to more than 

double their uptake of carbon 

dioxide. 

Headquarters in Alameda, 

California ;Developed at 

the University of California 

at Berkeley; Pilot-Scale 

facility in Florida 
190

AXI LLC 

Developing various strains of 

algae for the production of 

biofuels. Quincy, Massachusetts 

BARD, LLC 

BARD's closed loop photobioreactor technology can 

produce 66 million gallon of 

algae oil in 7 acres of land, 

which is 8,571,428 gallon of 

algae oil per acre. The pilot 

facility will begin by producing 

43,070 gallons of algae oil / 

biodiesel per annum using 

only six modules of photobioreactors covering 84 

square feet. 

Commercial scale algae 

system pilot facility located 

in the Commonwealth of 

Pennsylvania also plans 

for plant in Ohio. 

Bellona 

Supports algae in 

photobioreactors which can 

deliver food, fodder and fuel. Norway 

Bio Algene 

Use algae to generate oil for 

production of biodiesel and 

extract oil by breaking cell 

wall. Algae cultivation to 

remediate pollution, produce 

fuel and other bioproducts. 

Company has developed 

methods to accelerate algae 

growth and is investigating 

different harvesting methods. Headquarters near Seattle 

Biocentric Energy 

Manufactures and sells closed 

loop algae bioreactor systems 

for commercialization. California 

Biofuel Systems Group Limited 

Use phytoplankton to produce 

biodiesel. Design and build 

biodiesel processing systems. England 

Biolight Harvesting 

Develop renewable fuels and 

chemicals from blue-green 

algae. Biolight is focused on 

brackish water and agricultural 

runoff as a long-term medium 

for cultivation. 

California; 40-acre pilot 

facility in California's 

Imperial Valley 

Bionavitas 

High-volume production of 

algae using biofactories and 

fiber-optic lights in algaculture 

system. Claims to have a 

cost-efficient way to deliver 

light to biomass. Light 

Immersion Technology (LIT). Redmond, Washington 

BioProcess Algae LLC 

Photobioreactor systems 

coupled next to an ethanol 

facility which provides water, 

heat, and CO2. 

Pilot project anticipated to 

be in Shenandoah, Iowa 
 

191

Blue Marble Energy 

Convert algal biomass to 

energy by creating, 

centralizing, and harvesting 

wild algae blooms. BME’s 

proprietary AGATE (Acid, 

Gas, and Ammonia Targeted 

Extraction) system processes 

nearly any organic feedstock, 

utilizing cultured strains of 

bacteria to perform 

fermentation (like brewing 

beer) to produce a wide 

variety of biochemicals; can 

utilize wet biomass, bypassing 

energy-intensive drying Seattle, Washington 

Bodega Algae LLC 

Developer of scalable algae 

photobioreactors. Developing 

proprietary light technology to 

enhance growth of algae. 

Headquarters in Boston, 

Massachusetts 

Canadian Pacific Algae Inc. 

Grower and producer of 

phytoplankton (marine 

microalgae), current research 

center uses 8 - 1 million liter 

tanks. Nanaimo, British Columbia 

Carbon Capture Corp. 

Operates open algae ponds. 

In the business of processing 

algal-derived renewable 

diesel, butanol, biomethane 

and jet fuel propellant. 

La Jolla, California; 40-

acre Algae Research 

Center, part of a 326-acre 

R&D facility in Imperial 

Valley, California 

Cellena 

Open pond and PBR 

technology. Developing 

process for extracting algae oil 

without chemical use, drying 

or an oil press. Kona facility 

will grow only non-modified, 

marine microalgae in a hybrid 

system. 

Hawaii; Building an openpond demo facility in 

Hawaii - Kona Pilot Facility 

on Big Island began on 

January 16, 2008. 

Circle Biodiesel and Ethanol 

Corporation 

Have manufactured an algae 

photobioreactor for the 

production of algae. Also has 

an algae harvesting system 

for the extraction of algae oil 

for algae biodiesel or algae 

biofuel. Algae harvesting 

system retails for $195,000 

US dollars, can process one 

gallon of algae oil per minute. 

Headquarters in San 

Marcos, California 

Desert Sweet Biofuels 

Using a combination of 

gasification and pyrolysis in 

such a way as to produce 

biochar, a byproduct is 

electricity. One low cost algae 

production system currently 

being developed is vectoring 

algae through Daphnia. Gila Bend, Arizona 
192

Diversified Energy Corp. 

Has licensed technology from 

XL Renewables under the 

name Simgae for simple 

algae. Gilbert, Arizona 

Dynamic Biogenics Utilizes photobioreactors. 

Headquarters in 

Sacramento, California 

ENN Hebei Province, China 

General Atomics 

Developing improved 

processes for growing and 

extracting oil from algae in 

open ponds. San Diego, California 

Genifuel 

Licensed method to convert 

algae into renewable natural 

gas. Uses wet biomass like 

algae in a gasifier - Catalytic 

Hydrothermal Gasifier (CHG). 

The gasifier was developed by 

PNNL. Focus on outdoor 

ponds or inexpensive troughs. 

Global Green Solutions Inc. 

Focused initially on biodiesel 

feedstock. Developed 

Vertigro, self-contained algae 

growing system. 

Vancouver, British 

Colombia 

Green Plains 

Fourth largest ethanol 

producer in North America. 

Focus on photobioreactor 

systems. The pilot plant is 

planned to be used for animal 

feed, at least initially. 

Shenandoah, Iowa; pilot 

project expected to be 

operational by July 2009 

Green Star Products 

Developed formulas to 

increase algae growth rates, 

Montana Micronutrient 

Booster (MMB). Developed 

wet-algae stripping 

technology. 

Headquarters in San 

Diego, California. Had 

plans to move algae 

facility to Utah. 

GreenShift 

Has license agreement with 

Ohio University for bioreactor. 

Corporate offices in New 

York, New York; 

Engineering located in 

Alpharetta, Georgia 

HeroBX (formerly Lake Erie 

Biofuels) 

Investigating algae as a 

feedstock, conducting a 

vetting process with PBRs. Erie, Pennsylvania 

HR Biopetroleum Inc. 

Focus on earth-marine 

microalgae plants to produce 

biofuel feedstocks and animal 

nutrition products. The 

company offers algae 

products, such as algae oil, 

biodiesel, and animal feed 

proteins; carbohydrates for the 

production of ethanol and 

petroleum-based products; 

and military jet fuel. The 

technology is focused on Hawaii
 

193

coupling PBRs with open 

pond systems. 

Infinifuel Biodiesel 

Focusing on algae for 

biodiesel using algae ponds. 

Headquarters in Dayton, 

Nevada 

Ingrepro 

Focused on open-pond 

systems. Suggests that best 

business model will remediate 

waters, integrate heat, and 

produce multiple products. 

Netherlands; Plans to 

build algae facilities in 

Malaysia 

International Energy Inc. PBR Washington, DC 

Inventure Chemical Technology 

Patent-pending algae-to-jet 

fuel product. The company 

provides expertise in both 

process conversion and plant 

design and construction. Gig Harbor, Washington 

Kai BioEnergy 

Continuous, open pond 

system that produces bio 

crude oil from microalgae. 

Technology claims to 

overcome risk of algae 

contamination and allows for 

high yield growth of a 

dominant species. 

Del Mar, California and 

Hawaii 

Kelco Harvests natural kelp beds. San Diego, California 

Kent BioEnergy 

Develops open pond algae 

farm, experience in 

aquaculture. 

San Diego, California; 

160-acre process 

development/production 

facility south of Palm 

Springs 

Live Fuels Inc. 

Open-pond algae bioreactors 

to create green crude, not 

ethanol or biodiesel. Up to 

20,000 gallons per acre 

predicted for algae yield. The 

company grows a mix of 

native algae species in 45 

acres of open saltwater 

ponds. To harvest the algae, 

the company uses “algae 

grazers” such as filter-feeding 

fish species and other aquatic 

herbivores. The fish, including 

those from the Tilapia or 

sardine families, collect and 

clean the algae through 

structures in their mouths, 

according to the company. 

They swallow it and the algae 

is digested and concentrated 

in the fish’s flesh. To extract 

the oil, the fish are cooked 

and pressure is applied, 

resulting in Omega-3 fatty 

Headquarters in Menlo 

Park, California; Original 

plans to grow algae in 

ponds at the Salton Sea, 

an inland saline lake in 

Southern California, but 

has shifted to Texas. Will 

begin pilot operations at 

its test facility in 

Brownsville, Texas. The 

results of the pilot project 

will be used to 

commercialize the process 

along the coast of 

Louisiana. 
194

acids and other oils used as 

feedstocks for renewable 

fuels. 

Martek Biosciences Corporation 

Martek currently produces 

algae in a closed, dark system 

where the algae are fed 

sugars in a fermentation 

process similar to yeast 

growing on corn sugar, in 

contrast to the photosynthetic 

processes being developed by 

others in the algae-to-fuel 

race. The sugar-to-biodiesel 

pathway will use advanced 

biological science to convert 

sugars derived from biomass 

into lipids which are then 

converted into fuel molecules 

through chemical or 

thermocatalytic processes. Maryland 

MBD Energy 

Algae grown in waste water 

with high concentration of 

CO2 from a nearby power 

plant. Algae are harvested to 

produce algae oil and algae 

meal. East Melbourne, Australia 

Neptune Industries 

Has a patented system to use 

fish waste for the growth of 

algae for biofuels and 

methane gas. Boca Raton, Florida 

Odyssey Oil and Energy Inc. 

Company focuses on carbon 

sequestration and generation 

of renewable energy. PBR 

technology, ALG Bio Oil Ltd. Pretoria, South Africa 

OriginOil 

The company's bioreactor 

attempts to speed the growth 

of algae in a tank by blending 

light emitted from a rotating 

shaft with nutrients. The 

process does not require 

chemicals, initial dewatering, 

or high capex for heavy 

machinery. The company’s 

technology combines 

electromagnetism and pH 

modification to break down 

cell walls, releasing algal oil 

within the cells. The oil rises to 

the top for skimming and 

refining, while the remaining 

biomass settles to the bottom 

for further processing as fuel 

and other valuable products. Los Angeles, California 
 

195

Petroalgae 

Developing a commercialized 

system of technologies to 

grow and harvest oil from 

algae. Certain initial alga 

strains originated at the 

National Renewable Energy 

Lab (“NREL”). Selected and 

utilizes strains of algae to 

optimize growth and harvest 

characteristics for different 

applications and different 

geographic environments. 

Based in Melbourne, FL; 

Pilot plant in Fellsmere; 

Plans to complete a 20-

acre demo algae farm by 

end of 2009. 

PetroSun 

Scottsdale, Arizona, 

factory in Rio Honda, 

Texas 

Phycal 

Aims to harvest oil from algae 

without killing it, by bathing in 

solvents that remove the oil. 

Olexal non-destructive 

extraction "milking" process. 

Highland Heights, Ohio; 

Pilot by end of 2009. Subpilot scale in Ohio and 

R&D lab in St. Louis. Pilot 

facility in Hawaii planned 

to begin operations in 

2010. 

Plankton Power 

Closed ponds and integrated 

PBR, continuous process with 

low energy algal separation, 

oil extraction. Wellfeet, Massachusetts 

Primafuel 

Grown in shallow ponds with 

sunlight and fertilizers as 

inputs; Fertilizers are grass 

clippings and wood biomass. 

Signal Hill, CA 

Lund, Sweden 

Renewed World Energies 

Reportedly, the only fully 

automated and modular 

photo-bioreactor currently 

available, yields algae oil and 

cake. Captures nitrogen 

oxides and CO2 from flue 

gases. 

Georgetown, South 

Carolina 

SAIC 

Focus on creation of algaebased jet fuel 

Headquarters in McLean, 

Virginia; locations in 150 

cities worldwide 

Sapphire Energy 

Plans to grow algae in open 

ponds of unusable water. 

Algae-based based fuels 

developed include gasoline, 

diesel, and aviation fuels. 

San Diego, California; 

Demo in Las Cruces, 

California 

SCIPIO Biofuels 

Continuously circulating 

photobioreactors and 

continuous algae harvester. 

The company says it will 

target whatever fuel is 

demanded, be it jet fuel, 

ethanol, biodiesel, or 

biobutanol. 

Headquarters in Laguna 

Hills, California 

Plans for facility in 

Greensburg, Kansas 
196

Seambiotic 

Produces marine algae for a 

variety of applications, health 

foods, chemicals, medical 

products, and biofuels. Uses 

raceway/paddle-wheel openpond algae cultivation. Ashkelon, Israel 

Solazyme 

Grows algae in the dark using 

standard industrial 

bioproduction equipment, 

where the algae are fed a 

variety of non-food and waste 

biomass materials including 

cellulosic biomass and lowgrade glycerol. Headquarters in San 

Francisco, California 

Solena Group 

Plasma technology to gasify 

algae and other organics into 

energy outputs. Algae would 

be grown in big plastic 

containers and fed sunlight 

and sodium bicarbonate. 

Biomass is converted to 

syngas to produce electricity. 

Headquarters in 

Washington D.C.; 

European Office in 

Madrid, Spain 

Solix Biofuels 

Harvest oil, uses PBR; After 

oil is extracted the rest can be 

used as animal feed and 

ethanol. Claims to use less 

water than other processes. 

Headquarters in Fort 

Collins, Colorado. 

Announced in 2008 that it 

will build its first large 

scale facility at nearby 

New Belgian Brewery, 

where CO2 produced will 

be used to feed the algae. 

Plans for a Coyote Gulch 

Demonstration Facility, 

which will be operational 

by late summer 2009. The 

Utes chipped in more than 

$20 million and the land 

for the project in 

Southwest Colorado. 

StellarWind Bioenergy 

The company is using its 

proprietary PhycoGenic 

Reactor and PhycoProcessor 

systems as well as a 

RecyCO2Tron system for 

CO2 recovery. The 

PhycoProcessor is an oil 

recovery system. Their 

resource recovery system 

coverts algae biomass into 

methane, charcoal, fertilizer, 

or syngas. Indianapolis, Indiana 

SunEco Energy 

Harvesting and growth of 

native algae species in open 

ponds, claims to can produce 

at least 33,000 gallons of 

biocrude per acre-foot per 

year. 

Headquarters in Chino, 

California; Operations in 

Niland, California 
 

197

Synthetic Genomics 

Synthetic is collaborating with 

Exxon Mobil to research and 

develop the most advanced 

algae. In the future hope to 

mass farm the oil from algae. La Jolla, California 

Texas Clean Fuels 

Developing photobioreactors 

and equipment for algae 

farms. Their product line, 

known as MOPS (Micro 

Organism Production System) 

Headquarters in Rockwall, 

Texas 

Univenture 

Algae harvesting system that 

could reduce energy cost due 

to harvesting, dewatering, and 

drying of algae using a novel 

absorbent moving belt 

harvester. 

Operations in Ohio, 

Ireland, China 

US Biofuels PBR 

Negotiating with Co-op 

Greenhouse regarding 

locations in Fresno, the 

Imperial Valley, and 

Palmdale. 

Valcent Products Inc. 

Creates, designs, and 

develops patents e.g. vertical 

bioreactors in a closed loop. 

Headquarters in El Paso, 

Texas 

Vertigro Energy 

Closed-loop vertical algae 

growth system. 

San Diego, California; 

commercial-scale 

bioreactor pilot project in 

El Paso, Texas 

W2 Energy Inc. 

SunFilter technology: a tubular 

algae bioreactor; Inside the 

bioreactor, low-power 

ultraviolet lights, in 

combination with the gases, 

feed the algae so it grows and 

fills the tubes with blooms. 

When the blooms have 

reached an appropriate 

density, a set of magnetic 

rings inside the tubes scrapes 

the blooms clean and pushes 

the algae to the upper 

manifold, where compressed 

air pushes it out. The algae is 

then compressed, dried and 

then either gasified or fed into 

a biodiesel reactor to produce 

biodiesel. W2 also has 

developed a multi-fuel reactor 

to produce ultra-low sulfur 

diesel, a blend of JP8 jet fuel 

or gasoline; a plasma-assisted 

gasifier; a SteamRay rotary 

system engine that converts 

energy from steam or fuel 

combustion into a rotary force; 

small energy generating 

Carson City, NV; Plans for 

bioreactor running in 

Guelph, Ontario in midSept 2009 
198

systems; and the NonThermal Plasmatron. 

XL Renewables (formerly XL 

Dairy Group) 

Patent-pending hybrid algae 

system that can operate as a 

closed or open system. 

Focuses on creating 

renewable energy using dairy 

waste streams. Wants to 

produce algae biomass for 

animal feeds (high omega-oil 

content). Their Super Trough 

System design is expected to 

provide annual algae yield of 

300 dry tons/acre. 

Phoenix, Arizona; 

Developing a 400-acre 

integrated biorefinery 

located in Vicksburg, 

Arizona. Algae 

Development Center in 

Cas Grande, Arizona. 
 

 199

1.6 Biofuel Distribution 

1.6.1 Biofuel Distribution Overview

The current motor fuel distribution infrastructure has been optimized to facilitate the 

movement of petroleum-based fuels. Consequently, there are very efficient pipeline-terminal 

networks that move large volumes of petroleum-based fuels from production/import centers on 

the Gulf Coast and the Northeast into the heartland of the country. In contrast, the most biofuel 

volumes are produced in the heartland of the country and need to be shipped to the coasts, 

flowing roughly in the opposite direction of petroleum-based fuels. The location of renewable 

fuel production plants is 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.KKK

To varying degrees, the physical/chemical nature of some biofuels also limit the extent to 

which they can be shipped/stored fungibly with petroleum-based fuels. The vast majority of 

biofuels are currently shipped by rail, barge and tank truck to petroleum terminals. All biofuels 

currently are blended with petroleum-based fuels prior to use. Most biofuel blends can be used 

in conventional vehicles. However, E85 can only be used in flex-fuel vehicles, requires 

specially-constructed retail dispensing/storage equipment, and may require special blendstocks at 

terminals. These factors limit the ability of biofuels to utilize the existing petroleum fuel 

distribution infrastructure. Hence, the distribution of renewable fuels raises unique concerns and 

in many instances requires the addition of new transportation, storage, blending, and retail 

equipment. 

 Significant challenges must be faced in reconfiguring the distribution system to 

accommodate the large volumes of biofuels that we project would be used to meet the proposed 

standards. 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 volumes of 

biofuels required by the RFS2 standards.LLL EPA will continue to participate in or monitor these 

efforts as appropriate. 

Considerations related to the distribution of ethanol, cellulosic distillate fuel, renewable 

diesel fuel, and biodiesel 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 that we project 

would be 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 RIA. The 

importation of ethanol into the U.S. is discussed in Section 1.5.2 of this RIA. 

 

KKK A discussion of the projected locations of ethanol production facilities can be found in Chapter 1.5 of this RIA. LLL For example, the “Biomass Research and Development Board”, an inter-governmental group co-chaired by 

USDA and DOE., includes a group that is focused on evaluating biofuels distribution infrastructure issues. 

http://www.usbiomassboard.gov/distribution_infrastructure.htm 
 200

1.6.2 Biofuel Shipment to Petroleum Terminals

 Pipelines are the preferred method of shipping large volumes of petroleum products over 

long distances because of the relative low cost and reliability. Ethanol currently is not 

commonly shipped by pipeline because it can cause stress corrosion cracking in pipeline walls 

and its affinity for water and solvency can result in product contamination concerns.377 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.MMM We 

believe that it is currently not possible to re-process this mixture in the way that diesel-gasoline 

mixtures resulting from pipeline shipment are currently handled.NNN The Pipeline Research 

Council International (PRCI) in coordination with the Pipeline and Hazardous Materials Safety 

Administration (PHMSA), and the Association of Oil Pipelines (AOPL) are conducting research 

to address the safety and technical challenges to pipeline transportation of ethanol.378 A short 

gasoline pipeline in Florida is currently shipping batches of ethanol and other more extensive 

pipeline systems have feasibility studies underway.379 Thus, existing petroleum pipelines in 

some areas of the country may play an increasing role in the shipment of ethanol. Evaluations 

are also currently underway regarding the feasibility of constructing a new dedicated ethanol 

pipeline from the Midwest to the East coast.380 Substantial issues would need to be addressed 

before construction on such a pipeline could proceed, including those associated with securing 

new rights-of-ways and establishing sufficient surety regarding the return on the several billion 

dollar investment. 

We expect that cellulosic distillate fuels and renewable diesel fuel will not have materials 

compatibility issues with the existing petroleum fuel distribution infrastructure. Thus, there may 

be more opportunity for these biofuels to be shipped by pipeline. However, the location of 

ethanol and cellulosic distillate/renewable diesel production facilities relative to the origination 

points for existing petroleum pipelines will be a limiting factor regarding the extent to which 

pipelines can be used. 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 has 

been discussed by industry. This approach might also be considered for cellulosic distillate fuel 

when such plants are constructed. However, the additional handling steps to bring the ethanol or 

cellulosic distillate fuel to the pipeline origin points in this manner could negate the potential 

benefit of shipment by existing petroleum pipelines compared to direct shipment by rail. 

Biodiesel is currently not widely shipped by pipeline due to concerns that it may 

contaminate jet fuel that is shipped on the same pipeline and potential incompatibility with 

pipeline gaskets and seals. Segments of Kinder Morgan’s Plantation pipeline are currently 

shipping B5 blends, and its Oregon Pipeline that runs from Portland to Eugene is currently 

shipping B2 blends.381 These systems do not handle jet fuel. The shipment of biodiesel by 

 

MMM Different grades of gasoline and diesel fuel are typically shipped in multi-product pipelines in batches that abut 

each other. To the extent possible, products are sequenced in a way to allow the interface mixture between batches 

to be cut into one of the adjoining products. In cases where diesel fuel abuts gasoline in the pipeline, the resulting 

mixture must typically be reprocessed into its component parts by distillation for resale as gasoline and diesel fuel. 

NNN We believe that it is 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. 
 

 201

pipeline may become more widespread and might be expanded to systems that handle jet fuel. 

However, the relatively small production volumes from individual biodiesel plants and the 

widespread location of such production facilities may tend to limit the extent to which biodiesel 

may be shipped by pipeline. Rail cars, barges, and tank trucks that transport biodiesel over long 

distances will need to be heated/insulated in cold climates to prevent gelling. 

Due to the uncertainties regarding the extent to which pipelines might participate in the 

transportation of biofuels in the future, we assumed that biofuels will continue to be transported 

by rail, barge, and truck to petroleum terminals as the vast majority of biofuel volumes are today. 

To the extent that pipelines do play an increasing role in the distribution of ethanol, this may 

improve reliability in supply and reduce distribution costs. 

Apart from increased shipment by pipeline, biofuel distribution, and in particular ethanol 

distribution, can be further optimized primarily through the expanded use of unit trains. Unit 

trains are composed entirely of 70-100 ethanol tank cars, and are dedicated to shuttle back and 

forth to large hub terminals. In the future, unit trains might also be used for the shipment of 

cellulosic distillate fuel. Unit trains can be assembled at a single 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 fuel from a number of producers. The Manly Terminal in Iowa, accepts 

ethanol from a number of nearby smaller 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. 

We anticipate that the vast majority of new ethanol and cellulosic distillate facilities will be sized 

to facilitate unit train service. We do not expect that biodiesel facilities will be of sufficient size 

to justify shipment by unit train. In the NPRM, we projected that unit train receipt facilities 

would be located at petroleum terminals and existing rail terminals. Based on industry input 

regarding the logistical hurdles in citing unit train receipt facilities at petroleum/existing rail 

terminals, we expect that such facilities will be constructed on dedicated property with rail 

access that is as close to petroleum terminals as practicable.OOO

Shipment of biofuels by manifest rail to existing rail terminals will continue to be an 

important means of supplying biofuels to distant markets where the volume of the production 

facility and/or the local demand is not sufficient to justify shipment by unit train. Manifest rail 

shipment refers to the shipment of biofuel in rail tanks cars that are incorporated into trains 

which are composed of a variety of other commodities. Shipments by barge will also play an 

important role in those instances where production and demand centers have water access and in 

some cases as the final link from a unit train receipt facility to a petroleum terminal. Direct 

shipment by tank truck from production facilities to petroleum terminals will also continue for 

shipment over distances shorter than 200 miles. 

 

OOO Existing unit train receipt facilities have primarily followed this model. See the US Development Group’s 

interactive map of their ethanol unit train receipt facilities at http://www.us-dev.com/terminals.htm 
 202

We project that most biofuel volumes shipped by rail will be delivered to petroleum 

terminals by tank truck.PPP We expect that this will always be the case for manifest rail 

shipments. In the NPRM we projected that trans-loading of biofuels from rail cars to tank trucks 

would be an interim measure until biofuel storage tanks were constructed.QQQ Based on industry 

input, we now expect trans-loading will be a long-term means of transferring manifest rail car 

shipments of biofuels received at existing rail terminals to tank trucks for delivery to petroleum 

terminals. We also anticipate that trans-loading will be used at some unit train receipt facilities, 

although we expect that most of these facilities will install biofuel storage tanks from which tank 

trucks will be filled for delivery to petroleum terminals. Imported biofuels will typically be 

received and be further distributed by tank truck from petroleum terminals that already have 

receipt facilities for waterborne fuel shipments. 

Our analysis of the shipment of ethanol and cellulosic distillate fuels to petroleum 

terminals is based on the Oakridge National Laboratory (ORNL) analysis of ethanol 

transportation activity under the EISA that was conducted for EPA.382 The ORNL analysis 

contains detailed projections of which transportation modes and combination of modes (e.g. unit 

train to barge) are best suited for delivery of ethanol to specific markets considering ethanol 

source and end use locations, the current configuration and projected evolution of the distribution 

system, and cost considerations for the different transportation modes. The NPRM analysis 

assumed that all biofuel volumes other than biodiesel would be ethanol. For this FRM, we 

analyzed three scenarios under which varying volumes of cellulosic distillate fuel would take the 

place of ethanol production volumes to satisfy the RFS2 requirements. However, due to the 

timing of the various analyses for the FRM, the NPRM projections of the location of ethanol 

production facilities and end use areas contained in the NPRM had to be used as the inputs into 

the ORNL analysis. Our use of the ORNL analysis to evaluate the distribution impacts for the 

final rule assumes that cellulosic distillate production plants would take the place of some of the 

ethanol production plants projected in the NPRM. It further assumes that cellulosic distillate fuel 

use would coincide with the ethanol end-use areas projected in the NPRM. 

The extent to which new cellulosic distillate fuel and cellulosic ethanol production 

facilities are more dispersed than projected in the NPRM, distribution for ethanol from new 

production facilities and from all cellulosic distillate facilities might be simplified as the fuel has 

more opportunity to be used locally. Cellulosic distillate fuel distribution may also be further 

simplified to the extent that in the future it is blended with petroleum-based diesel fuel in higher 

blend-ratios than the 20% blends currently registered by EPA. An increased blend ratio for 

cellulosic distillate fuel would tend to enhance the ability for its use close to the place of 

manufacture rather than having to be spread more widely over a larger petroleum diesel pool. 

 We projected the volumes of biodiesel that would be used on a State-by-State basis to 

meet anticipated State biodiesel mandates/incentives and the estimated demand for biodiesel as a 

blending component in heating oil. Using the estimated locations of biodiesel production 

 

PPP At least one current ethanol unit train receipt facility has a pipeline link to a nearby terminal. To the extent that 

additional unit train receipt facilities could accomplish the final link to petroleum terminals by pipeline, this would 

significantly reduce the need for shipment by tank truck. 

QQQ Trans-loading refers to the direct transfer of the contents of a rail car to a tank truck without the intervening 

delivery into a storage tank. 
 

 203

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 from these production facilities that was needed to meet the RFS2 mandated volumes 

was assumed to be used in the same State where it was produced up to the point where the 

State’s entire diesel fuel pool contained 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 a 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 case where biodiesel is shipped by manifest rail, it was 

assumed that it would be trans-loaded at a rail terminal for further shipment by tank truck to a 

petroleum terminal. Additional discussion of our estimate of how increased biodiesel volumes 

used to comply with the RFS2 standards would be transported to petroleum terminals can be 

found in Section 4.2 of this RIA on biodiesel freight costs. 

We anticipate that the deployment of the necessary distribution infrastructure to 

accommodate the shipment of biofuels to petroleum terminals is achievable. We believe that 

construction of the requisite rail cars, barges, tank trucks, tank truck and rail/barge/truck receipt 

facilities is within the reach of the corresponding construction firms. Although shipment of 

biofuels by rail represents a major fraction of all biofuel ton-miles, it is projected to account for 

approximately 0.4% of all rail freight by 2022.RRR Many improvements to the freight rail system 

will be required in the next 15 years to keep pace with the large increase in the overall freight 

demand. Given the broad importance to the U.S. economy of meeting the anticipated increase in 

freight rail demand, and the substantial resources that seem likely to be focused on this cause, we 

believe that overall freight rail capacity would not be a limiting factor to the successful 

implementation of the biofuel requirements under EISA. 

1.6.3 Changes in Freight Tonnage Movements Due to RFS2

In order to estimate the freight rail system impacts associated with biofuels transport 

under RFS2, we commissioned an analysis by Oak Ridge National Laboratories (ORNL) to 

examine fuel ethanol transportation, activity, and potential distribution constraints for the North 

American freight rail system.383 The analysis found that biofuels transport is expected to 

constitute approximately 0.4% of the total freight tonnage for all commodities transported by the 

freight rail system through 2022. The results suggest that it should be feasible for the freight rail 

system to accommodate the additional biofuels freight associated with the RFS2. 

 

RRR See Section 1.6.3. of this RIA for a discussion of the increase in freight traffic due to the transport of the biofuels 

needed to comply with the RFS2 standards 
 204

For the analysis, we provided the estimated location of ethanol production facilities, 

sources of ethanol imports, and state-level consumption for the annual volumes of ethanol that 

we estimated would be consumed in response to the EISA.SSS We also provided the projected 

volumes of biodiesel and non-co-processed renewable diesel fuel that would be used. Due to the 

uncertainty associated with non-ethanol biofuels, biodiesel and non-co-processed renewable 

diesel fuel volumes were assumed to originate from the ethanol production facilities and follow 

projected ethanol use patterns in the analysis. This assumption seems reasonable, given the 

relatively small volumes of these non-ethanol biofuels relative to ethanol. 

Rail traffic information from the 2006 Surface Transportation Board Carload waybill 

sample was incorporated into ORNL’s North American Transportation Infrastructure Network 

Model to provide a baseline approximation of the current day freight rail system unstressed by 

the transport of EISA-mandated biofuels volumes. Freight rail activity for the unstressed 

baseline model was projected for 2012, 2014, and 2022 using information from the Commodity 

Origin-Destination Database of DOT’s Freight Analysis Framework version 2 (FAF2) to identify 

potential distribution constraints for the North American freight rail system. FAF2 integrates 

data from a variety of sources to estimate commodity flows by different modes of transportation 

and related freight transportation activity among states, regions, and major international 

gateways. FAF2 provides freight transportation forecasts through 2035. 

To estimate potential future constraints of the freight rail system, EISA-mandated 

biofuels volumes were superimposed onto the unstressed Infrastructure Network model for 2012, 

2012, and 2022. For each forecast year, total biofuels demand includes biodiesel and non-coprocessed renewable diesel fuel demand. As such, total biofuel demand for the forecast years 

were assumed to be 14.6, 17.5, and 35.1 billion gallons, respectively. See the ORNL report for 

additional assumptions and modeling details. 

On average, 84% of the nation’s freight rail system will not be affected by biofuels 

shipments under the RFS2 scenarios considered, according to the ORNL analysis. The 16% 

which will be impacted will see a 2.5% increase in freight rail traffic associated with biofuels 

shipments, on average.TTT Approximately 85% of all ethanol shipments are expected to originate 

in the Midwest, with approximately 24%, 15%, 13%, 8% and 6% of all unit train shipments of 

ethanol originating from Iowa, Nebraska, Illinois, Minnesota, and Indiana, respectively. The 

balance is expected to originate from the surrounding Midwestern states. 

As such, the 16% of the freight rail system that is expected to see an increase in biofuels 

shipments under RFS2 will see it concentrated along rail corridors radiating out of the Midwest. 

Most high-volume ethanol movements are estimated to occur from the Midwest producing 

regions to high-demand regions, such as the northeast, west, and south. For instance, Midwest 

ethanol shipments destined for the west constitute about 19% of all ethanol shipments. 

Shipments destined from the Midwest to the Northeast constitute about 10% of all ethanol 

shipped while shipments to the southeast constitute another 10%. Shipments to the southwest 

constitute 7% of overall ethanol shipments as do shipments to the south. Interstate shipments 

account for 17% of all ethanol shipped. Shipments originating and terminating in the Midwest 

 

SSS These inputs are summarized in the ORNL final report. TTT The overall increase in freight tonnage is 0.4% (2.5% x 16%) 
 

 205

constitute approximately 31% of all ethanol unit train shipments. For all scenarios, the EISArelated transport impacts on the freight rail system were negligible. 

 The results of the analysis suggest that any additional stress placed upon the North 

American freight rail system by biofuels transport under EISA would have minimal impacts on 

transportation infrastructure overall since freight associated with biofuels constitutes only a small 

portion of the total freight tonnage for all commodities. 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. 

1.6.4 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 the need for increased biofuel transport 

under the EISA. The modifications required to satisfy the increase in demand include upgrading 

tracks to allow the use of heavier trains at faster speeds, the modernization of train braking 

systems to allow for increased traffic on rail lines, the installation of rail sidings to facilitate train 

staging and passage through bottlenecks. 

 Some industry groupsUUU 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 without the implementation 

of the RFS2 standards. A 27% overall increase in rail fright traffic is projected by 2022 without 

considering the potential impact of compliance with the RFS2 program. 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 

 

UUU 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.
 206

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.384 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) ProgramVVV, 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 

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.385 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) estimates386 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. 

 

VVV 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. 
 

 207

 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.WWW 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.XXX

 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 biofuels 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 final rule, several biofuel-specific modifications will be needed. Additional unit train 

and manifest rail receipt facilities will be needed to handle the volumes of ethanol and cellulosic 

distillate fuel that we project will be used to comply with the RFS2 standards. In the NPRM, we 

projected that unit train receipt facilities would be located at petroleum terminals and existing 

rail terminals. Based on industry input regarding the logistical hurdles in citing unit train receipt 

 

WWW 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). 

XXX 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, 2007).
 208

facilities at petroleum/existing rail terminals, we expect that such facilities will be constructed on 

dedicated property with rail access that is as close to petroleum terminals as practicable.YYY We 

assumed that under the primary mid-ethanol and the low-ethanol control scenarios that all unit 

train and manifest rail receipt facilities would be capable of handling the receipt of both ethanol 

and cellulosic distillate fuel. There is no cellulosic distillate fuel under the high-ethanol scenario, 

thus all unit train receipt facilities would be dedicated to handling ethanol under the high-ethanol 

control scenario. 

In the NPRM, we assumed that some new manifest rail receipt facilities for biofuels 

would be located at petroleum terminals. Since the NPRM we received industry input that it is 

unlikely that additional manifest rail receipt facilities could be located at petroleum terminals due 

to a lack of reasonable access to a rail line. Consequently, we are now assuming that additional 

manifest rail receipt facilities for biofuels would be placed at exiting rail terminals. We are 

assuming that biofuels will continue to be trans-loaded directly from rail cars to tank trucks at 

rail terminals for shipment to petroleum terminals as is the case today, thereby obviating the need 

for biofuel storage at rail terminals.ZZZ Some manifest rail receipt facilities would also handle 

biodiesel as well as ethanol, and cellulosic distillate fuel/renewable diesel fuel. 

As part of Oakridge National Laboratory’s study for EPA on the projected patterns of 

ethanol distribution from producer to terminal under the EISA, ORNL estimated the number of 

unit train receipt facilities.387 The ORNL study used our NPRM estimate that all biofuel used to 

comply with the EISA (other than biodiesel) would be ethanol. Because unit train receipt 

facilities would handle both ethanol and cellulosic distillate fuel, the number of these facilities 

that would be needed is driven by the combined volume of these fuels that we project would 

used. Therefore, the ORNL estimate of the number of unit train receipt facilities for the NPRM 

control case is still very useful in estimating the number of such facilities under the control cases 

examined in this final rule. The NPRM control scenario assumed the use of 34.14 BGal/yr of 

ethanol by 2022. Under the high-ethanol control scenario in this final rule (FRM), we estimate 

that 33.24 BGal/yr of ethanol would be used by 2022. Given their similarity, we assumed that 

the ORNL results for the NPRM would be applicable to the FRM high-ethanol scenario for 

estimating the number of unit train receipt facilities required. 

Based on our analysis of a spreadsheet used in the ORNL analysis, we determined that 

ORNL estimated that there would be approximately 210 unit train receipt facilities under the 

NPRM control case.388 The ORNL estimate was based on an assumption by ORNL regarding 

the minimum annual throughput needed to justify the construction of a unit train facility (~20 

MGal/yr) which we now believe to understate the throughput needed. Since the completion of 

the ORNL study, we received input from industry experts who are familiar with the construction 

of ethanol unit train receipt facilities that the minimum annual throughput for such a facility is 

approximately 230 million gallons per year. This minimum throughput volume assumes a 

fortuitous grouping of circumstances including low cost of the land needed, and ease of 

 

YYY Existing unit train receipt facilities have primarily followed this model. ZZZ In the NPRM, we assumed that trans-loading would only continue only until biofuel storage tanks could be 

constructed at rail terminals. Input from industry indicates that trans-loading will continue to be employed in the 

future. This input also indicates that construction of biofuel storage tanks at rail terminals is unlikely due to space 

and other constraints. 
 

 209

construction of the rail spur to the facility to a rail line. To provide a more realistic estimate 

under varied conditions, we assumed a minimum throughput volume of 280 MGal/yr. 

We evaluated the location and annual throughput volumes of the unit train receipt 

facilities projected by ORNL. Volumes from the smaller facilities were consolidated regionally 

to satisfy a minimum throughput volume of 280 MGal/yr while maintaining a reasonable 

trucking distance (<200 miles) from unit train facilities to petroleum terminals. Based on this 

analysis, we arrived at an estimate of 40 unit train receipt facilities to support the volumes of 

ethanol and cellulosic distillate fuel that we project would be used under the EISA. We 

estimated the additional transport by tank truck from these unit train facilities to petroleum 

terminals that would be needed to compensate for the reduced number of unit train receipt 

facilities compared to the ORNL study.AAAA 

We assumed that 40 unit train facilities would be needed under each of the 3 control 

scenarios that we evaluated. This may somewhat overstate the number needed under the primary 

mid-ethanol and the low ethanol scenarios since the total volume of ethanol and cellulosic 

distillate fuel is somewhat lower under these scenarios relative to the high-ethanol scenario. 

However, we believe that this is an appropriate approach since it provides some margin to 

compensate for the potential that there may be some instances where a unit train receipt facility 

may only handle ethanol or cellulosic distillate fuel (potentially increasing the overall number of 

unit train facilities needed slightly). We estimate that there would be 9 unit train receipt facilities 

to support the transport of biofuels under the AEO reference case and 3 under the RFS1 

reference case. For the AEO reference case, this includes those unit train receipt facilities 

currently in place and those under construction. To estimate the number unit train facilities 

under the RFS1 reference case, we evaluated how many of these type of facilities were in place 

or under construction when historic ethanol consumption levels were consistent with the RFS1 

case. Under the RFS1 reference case, we attributed the need for 37 additional biofuel unit train 

receipt facilities (40-3) to the implementation of the EISA. Under the AEO reference case, we 

attributed 31 additional unit train receipt facilities (40-9) to the EISA. 

The construction of each of these unit train receipt facilities would require: the 

acquisition of land near a rail line and within trucking distance of the petroleum terminals that 

would be served, the construction of a rail spur and internal tracks to handle unit trains, facilities 

for the high-speed unloading of rail cars and loading of tank trucks, biofuel storage tanks and/or 

pipelines to ship biofuel to nearby petroleum terminals, and other miscellaneous biofuel handling 

equipment. For our analysis, we assumed that all unit train rail receipt facilities would construct 

biofuel storage tanks. Biofuels would be unloaded from unit trains into these storage tanks 

before being loaded into tank trucks for shipment to petroleum terminals. To the extent that 

some facilities are able to link to nearby petroleum terminals by pipeline or employ transloading, there would be less need for storage tanks at unit train receipt facilities. 

 

AAAA See Section 1.6.6 for a discussion of the tanker trucks needed to support the distribution of biofuels under the 

EISA. For a discussion of our estimation of ethanol and cellulosic distillate freight costs, see Sections 4.2.1.2 and 

4.2.2.2 respectively in this RIA. The attribution of the costs of unit train facilities to the volumes of ethanol and 

cellulosic distillate fuel is discussed in Sections 4.2.1.1.2 and 4.2.2.1.3 
 210

A spreadsheet used in the ORNL analysis indicates that ORNL estimated that there 

would be 56 manifest rail receipt facilities for biofuels under the NPRM control case.389 To 

provide some margin to compensate for the potential need for additional manifest rail receipt 

facilities beyond that indicated by the ORNL analysis, we used the estimate of 56 manifest rail 

facilities for each of the 3 FRM control scenarios relative to the RFS1 reference case.BBBB We 

estimated that an additional 43 manifest rail receipt facilities would be needed to support the 

transport of biofuels for the three FRM control cases relative to the AEO reference case. We 

arrived at this estimate by subtracting the number of manifest rail receipt facilities that could be 

attributed to the incremental increase in biofuel shipment volumes in going from the RFS1 to the 

AEO reference case from the number of facilities attributed to the EISA under the RFS1 

reference case (56-13).CCCC The construction of a new manifest rail receipt facilities at a rail 

terminal would involve the acquisition of a mobile trans-loading platform including fuel and fuel 

vapor transfer hoses, the preparation of spill containment for the area where trans-loading would 

take place, accommodations for recordkeeping and the preparation of bills of lading, and the 

installation of other miscellaneous equipment to support the trans-loading process. 

A substantial number of additional rail cars would be needed to transport the volumes of 

ethanol, cellulosic distillate fuel, renewable fuel, and biodiesel that are projected to be used in 

response to the RFS2 standards. Biodiesel rail cars typically have a deliverable volume of 

25,600 gallons, whereas the deliverable volume for ethanol rail cars is typically 29,000. We 

assumed that rail cars similar to those used for the transport of ethanol would be used to handle 

cellulosic distillate and renewable diesel fuels. Our estimation of the rail cars needed to transport 

ethanol and cellulosic distillate fuel under the 3 control scenarios is based on an interpolation of 

the results from the ORNL analysis for the NPRM control case (34.14 BG/yr of ethanol by 2022) 

and AEO reference case (13.18 BG/yr of ethanol by 2022). The underlying assumption in this 

approach is that the overall number of rail cars needed varies by the total volume of biofuel 

projected to be used under a given control scenario. Based on this approach, we estimate that 

40,400 rail cars would be needed to transport the volumes of ethanol and cellulosic distillate 

fuel/renewable diesel fuel under the high-ethanol scenario, 36,200 under the primary mid-ethanol 

scenario, and 34,400 under the low-ethanol scenario. We subtracted the number of rail cars 

needed under the two reference cases to determine the incremental number of rail cars attributed 

to compliance with the EISA (see Table 1.6.4-1). 

 

BBBB No deduction to the number of manifest rail receipt facilities attributed to the EISA was made based on the 

number of such facilities that would have been in place to support the transport of the volumes of biofuels 

corresponding to the RFS1 reference case. 

CCCC The number of manifest rail receipt facilities attributed to the incremental increase in biofuel shipment volumes 

in going from the RFS1 to the AEO reference case was calculated by volume weighting. 
 

 211

Table 1.6.4-1. 

Additional Rail Cars Needed by 2022 for Shipment of the Incremental RFS2 Volumes of 

Ethanol, and Cellulosic Distillate Fuel/Renewable Diesel Fuel 

Number of Rail Cars 

Reference Case used for Comparison 

 RFS1 AEO 2007 

Low-Ethanol Scenario 24,600 12,600 

Mid-Ethanol Scenario 20,400 8,300 

High Ethanol Scenario 18,500 6,500 

 We estimated the number of rail cars that would be needed to transport biodiesel using 

the projected volume of biodiesel that we expect would be shipped by manifest rail and the 

assumed rail car volume and cycle time. We assumed a cycle time of one month for shipment by 

manifest rail car. We believe this is a conservatively high estimate given current industry 

experience and the potential for improvement in the future. We estimate that 1,370 rail cars 

would be needed by 2022 to transport the volume of biodiesel that we project will be used to 

satisfy the RFS2 standards. We estimate that 250 rail cars would be needed by 2022 to transport 

the volume of biodiesel projected under the RFS1 reference case and 310 rail cars under the 

AEO reference case. Consequently, we attribute the construction of an additional 1,130 

biodiesel rail cars to the implementation of the EISA under the RFS1 reference case and 1,060 

under the AEO reference case. The total additional number of rail cars for the transport of 

ethanol, cellulosic distillate fuel/renewable diesel fuel, and biodiesel that we attribute to the 

implementation of the EISA is presented in Table 1.6.4-2. 

Table 1.6.4-2. 

Additional Rail Cars Needed by 2022 for Shipment of 

All Incremental RFS2 Biofuel Volumes 

Number of Rail Cars 

Reference Case used for Comparison 

 RFS1 AEO 2007 

Low-Ethanol Scenario 25,800 13,700 

Mid-Ethanol Scenario 21,500 9,400 

High Ethanol Scenario 19,700 7,500 

Our analysis of ethanol, biodiesel cellulosic distillate, and renewable diesel fuel 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 
 212

producers converted existing boxcar production facilities to tank production facilities and 

brought on additional work shifts to adjust to rapidly changing to market conditions. 

With the recent economic downturn, the backlog for railcars has decreased significantly. For 

example, the backlog for railcars of a major producer was approximately 7,000 railcars in 2009, 

but dropped to approximately 1,200 railcars scheduled for delivery in 2010. This has led to the 

closure of several railcar production facilities. We believe that the excess railcar production 

capacity will allow the industry to rapidly respond to potential increases in railcar demand due to 

ethanol, biodiesel, cellulosic distillate, and renewable diesel fuels, when the need arises.

1.6.5 Marine Transportation System Accommodations 

 The American Waterway’s Association 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 biofuels will be transported via these arteries. Thus, we do not believe that the ability 

to ship biofuels by inland marine will represent a serious barrier to the 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 biofuels 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. Our estimation of the barges needed to transport ethanol and cellulosic distillate fuel 

under the 3 control scenarios is based on an interpolation of the results from the ORNL analysis 

for the NPRM control case (34.14 BG/yr of ethanol by 2022) and AEO reference case (13.18 

BG/yr of ethanol by 2022). The underlying assumption in this approach is that the over all 

number of barges needed varies by the total volume of ethanol and cellulosic distillate fuel 

projected to be used under a given control scenario. Based on this approach, we estimate that 

167 barges would be needed to transport the volumes of ethanol and cellulosic distillate 

fuel/renewable diesel fuel under the high-ethanol scenario, 150 under the primary mid-ethanol 

scenario, and 143 under the low-ethanol scenario. We subtracted the number of barges needed 

under the two reference cases to determine the incremental number of rail cars attributed to 

compliance with the EISA (see Table 1.6.5-1). 
 

 213

Table 1.6.5-1. 

Additional Barges Needed by 2022 for Shipment of the Incremental RFS2 Volumes of 

Ethanol, and Cellulosic Distillate Fuel/Renewable Diesel Fuel 

Number of Barges 

Reference Case used for Comparison 

 RFS1 AEO 2007 

Low-Ethanol Scenario 95 45 

Mid-Ethanol Scenario 78 28 

High Ethanol Scenario 71 21 

We estimated the number of barges that would be needed to transport biodiesel using the 

projected volume of biodiesel that we expect would be shipped by barge and the assumed barge 

volume and cycle time. We assumed a 2 week barge cycle time, which we understand to be 

typical given the markets where we expect most barge shipments would occur.DDDD We estimate 

that 41 barges would be needed by 2022 to transport the volume of biodiesel that we project will 

be used to satisfy the RFS2 standards. We estimate that 7 barges would be needed by 2022 to 

transport the volume of biodiesel projected under the RFS1 reference case and 9 barges under the 

AEO reference case. Consequently, we attribute the construction of an additional 34 biodiesel 

barges to the implementation of the EISA under the RFS1 reference case and 32 under the AEO 

reference case. The total additional number of barges for the transport of ethanol, cellulosic 

distillate fuel/renewable diesel fuel, and biodiesel that we attribute to the implementation of the 

EISA is presented in Table 1.6.4-2. 

Table 1.6.5-2. 

Additional Barges Needed by 2022 for Shipment of All Incremental RFS2 Biofuel Volumes 

Number of Barges 

Reference Case used for Comparison 

 RFS1 AEO 2007 

Low-Ethanol Scenario 129 67 

Mid-Ethanol Scenario 112 60 

High Ethanol Scenario 105 53 

The U.S. tank barge fleet currently numbers 3,600.390 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 

 

DDDD 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. 
 214

biofuels by barge over time, we believe that the addition to the fleet of the barges estimated to be 

needed to transport biofuels can be accommodated by the industry. 

 

 As discussed in Section 1.5.2. of this RIA, we are projecting significant imports of 

ethanol by 2022. 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 

CountiesEEEE according to company-level historical fuel import data from the Energy 

Information Administration (EIA).391 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 30 ports would receive imported ethanol by 

2022. The list of ethanol import ports was provided to ORNL as an input to the ethanol 

transportation analysis that they conducted for EPA.392 Under the high-ethanol option, we 

estimate that the 18 ports which did not 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 project that under the primary mid-ethanol scenario that 15 new 

ethanol import locations would be added and that under the low ethanol scenario there would be 

14 new ethanol import locations. We used these estimates relative to both the RFS1 and AEO 

reference cases since we expect that the increase in ethanol imports would most appropriately be 

attributed to the incremental increase in ethanol use levels above those reflected under both the 

AEO and RFS1 reference cases. We believe that all the ports where ethanol would be imported 

would be incorporated into existing 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. 

As part of Oakridge National Laboratory’s study for EPA on the projected patterns of 

ethanol distribution from producer to terminal under the EISA, ORNL estimated the number of 

barge receipt facilities that would be needed to support biofuel shipments within the U.S.393 

Based on our analysis of a spreadsheet used in the ORNL analysis, we determined that ORNL 

estimated that there would be approximately 57 barge facilities under the NPRM control case.394 

Since the NPRM control case has a somewhat higher total biofuel volume than under the FRM 

high-ethanol control scenario, we believe that the ORNL estimate of the number of barge receipt 

facilities needed for the NPRM control scenario provides a reasonable (although perhaps 

conservatively high) estimate of the number of such facilities that would be needed under the 

high-ethanol scenario. 

We assumed that all biofuel barge receipt facilities would handle ethanol and cellulosic 

distillate fuel and that some of these facilities would handle biodiesel. To compensate for the 

potential that there may be some instances where a manifest rail receipt facility might handle 

ethanol but not cellulosic distillate fuel or vice-versa (perhaps increasing the number of unit train 

facilities slightly), we assumed that 57 manifest rail receipt facilities would also be needed under 

the mid-ethanol and low-ethanol scenarios. Our analysis of the aforementioned ORNL 

 

EEEE Caribbean Basin Initiative countries receive special exemptions from U.S. ethanol import tariffs (See Section 

1.5 of this RIA regarding the source of ethanol imports and for additional discussion regarding how we estimated 

where ethanol imports would enter the U.S.. 
 

 215

spreadsheet indicates that ORNL estimated there would be approximately 4 barge receipt 

facilities under the RFS1 reference case. Therefore, we estimate that an additional 53 barge 

receipt facilities would need to be configured to receive biofuels in order to facilitate compliance 

with the RFS2 program relative to the RFS1 reference case. By interpolating between the ORNL 

results for the RFS1 reference case and the NPRM control case, we estimated that 16 barge 

receipt facilities would be needed under the AEO reference case. Therefore, we estimate that an 

additional 41barge receipt facilities would need to be configured to receive biofuels in order to 

facilitate compliance with the RFS2 program relative to the AEO reference case 

We believe that barge receipt facilities that receive shipments of biofuels would be those 

that already handle the receipt of petroleum-based fuels and which are incorporated into 

petroleum terminals or would be linked to unit train receipt facilities. Such facilities would need 

to install/modify piping, pumps, vapor handling systems. The need for biofuel storage tanks and 

other facilities to handle the storage and transfer of biofuels to other means of distribution at such 

is addressed within the context of the additional facilities needed at petroleum terminals and unit 

train facilities. 

1.6.6 Road Transportation System Accommodations 

A substantial number of tank trucks would be needed to distribute the additional volume 

of biofuels that we project would be used to meet the RFS2 volumes. In all cases, a tank truck 

capacity of 8,000 gallons was assumed. Larger tank trucks are permitted in some areas, so this 

assumption will tend to overestimate of the number of tank trucks needed. We assumed that tank 

trucks similar to those used for the transport of ethanol would be used to handle cellulosic 

distillate and renewable diesel fuels. 

Our estimation of the tank trucks needed to transport ethanol and cellulosic distillate fuel 

under the 3 control scenarios is based on an interpolation of the results from the ORNL analysis 

for the NPRM control case (34.14 BG/yr of ethanol by 2022) and AEO reference case (13.18 

BG/yr of ethanol by 2022). The underlying assumption in this approach is that the overall 

number of tank trucks needed varies by the total volume of ethanol and cellulosic distillate fuel 

projected to be used under a given control scenario. We increased the estimated number of tank 

trucks needed from that which we arrived at from this interpolation to compensate for our 

reduction in the number of unit train facilities that would be constructed from the estimate in the 

ORNL study. 

The volume of biofuels shipped to the unit train facilities under the ORNL analysis which 

we consolidated into larger unit train receipt facilities represents 41% of the total volume shipped 

to unit train facilities (12.6 BG/yr out of 21.4 BG/yr in 2022 under the NPRM control case). We 

compared the location of the 170 unit train facilities that we consolidated into the remaining 40 

such facilities from the ORNL analysis to the location of the petroleum terminals that these 

facilities were intended to service. Based on this comparison, we estimated that 41% of the 

volume of biofuels shipped by unit train would need to be shipped 3 times farther on average to 

reach the petroleum terminals serviced than under the ORNL analysis. We assumed that this 

would result in a 3 fold increase in the number of trucks needed to take this volume from the unit 
 216

train facility to the petroleum terminal.FFFF The majority of the number tank trucks which ORNL 

estimated would be needed are attributed to the transport of biofuels from rail receipt facilities to 

petroleum terminals. Consequently, we believe that a reasonable (albeit conservatively high) 

estimate of the increase in the number of tank trucks that would be needed due to our decrease in 

the number of unit train facilities can be arrived at by multiplying the fraction of biofuels shipped 

by unit train that is attributed to consolidated unit train terminals (41% of the total volume 

shipped by unit train) by the average increase in shipping distance for the affected volume (factor 

of 3). By so doing, we arrived at an estimate that the reduction in the number of unit train receipt 

facilities would result in a 23% increase in the number of tank trucks needed compared to that 

indicated by interpolation of the results from the ORNL study 

Based on this approach, we estimate that 1,940 tank trucks would be needed to transport 

the volumes of ethanol and cellulosic distillate fuel/renewable diesel fuel under the high-ethanol 

scenario, 1,720 under the primary mid-ethanol scenario, and 1,620 under the low-ethanol 

scenario. We subtracted the number of tank trucks which ORNL estimated would be needed 

under the two reference cases to determine the incremental number of tank trucks attributed to 

compliance with the EISA (see Table 1.6.6-1). 

Table 1.6.6-1. 

Additional Tank Trucks Needed by 2022 for Shipment of the Incremental RFS2 Volumes 

of Ethanol, and Cellulosic Distillate Fuel/Renewable Diesel Fuel 

Number of Biofuel Tank Trucks 

Reference Case used for Comparison 

 RFS1 AEO 2007 

Low-Ethanol Scenario 1,490 1,080 

Mid-Ethanol Scenario 1,230 820 

High Ethanol Scenario 1,120 710 

 

To estimate the number of tank trucks needed to transport biodiesel to petroleum 

terminals we assumed 6 shipments per day per truck from production facilities to terminals. We 

believe that a short shipping distance for tank truck transport from biodiesel production facilities 

is justified based on the widespread dispersion and the fact that some would be located at 

petroleum terminals. We estimate that 150 tank trucks would be needed by 2022 to transport the 

volume of biodiesel that we project will be used to satisfy the RFS2 standards. We estimate that 

30 tank trucks would be needed by 2022 to transport the volume of biodiesel projected under the 

RFS1 reference case and 35 tank trucks under the AEO reference case. Consequently, we 

attribute the construction of an additional 130 biodiesel tank trucks to the implementation of the 

EISA under the RFS1 reference case and 120 under the AEO reference case. The total additional 

 

FFFF This may somewhat overstate the number of additional tank trucks needed given that the tank truck 

loading/unloading time remains constant. ORNL assumed a relatively short shipping distance from rail receipt 

facility to petroleum terminal. 
 

 217

number of tank trucks for the transport of ethanol, cellulosic distillate fuel/renewable diesel fuel, 

and biodiesel that we attribute to the implementation of the EISA is presented in Table 1.6.6-2. 

Table 1.6.6-2. 

Additional Tank Trucks Needed by 2022 for Shipment 

of All RFS2 Incremental Biofuel Volumes 

Number of Biofuel Tank Trucks 

Reference Case used for Comparison 

 RFS1 AEO 2007 

Low-Ethanol Scenario 1,610 1,200 

Mid-Ethanol Scenario 1,350 940 

High Ethanol Scenario 1,240 830 

In Section 1.6.8 of this RIA we discuss our estimation of the number of tank trucks than 

might potentially be needed to transport butane to terminals for E85 blending. The results of this 

analysis are presented in Table 1.6.6-3. 

Table 1.6.6-3. 

Estimated Number of Tank Trucks Needed for Shipment of Butanea

Number of Tank Trucks Needed to Transport Butane 

 Low-Ethanol 

Scenario 

Primary 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Tank Truck (8,200 gallons) 2,165 3,280 5,530 a

 If a solution to the current difficulty in blending E85 to meet minimum volatility specifications can not be arrived 

upon by ASTM International to allow the use of commonly available gasoline blendstocks. 

Concerns have been raised in the trade press regarding the ability of the trucking industry 

to attract a sufficient number of drivers to keep pace with demand. We used estimates of the 

number of truck drivers required to transport biofuels from the ORNL report as a basis for our 

estimate of the number of truck drivers that would be needed to transport the additional volume 

of biofuels attributed to the RFS2 program. Given the volume of butane required for blending 

into E85, typical travel distances, etc., we estimated that the number of truck drivers required to 

transport butane was approximately 1,500. Similar inputs were used to estimate the number of 

truck drivers required to transport non-ethanol biofuels; this number was approximately 300. 

When combined with the estimates from ORNL, the number of truck drivers required to 

transport biofuel feedstocks and finished product is approximately 5,300 drivers.GGGG

 

GGGG This is the maximum number of drivers that would be needed under any control scenario. Somewhat fewer 

drivers would be needed under the mid-ethanol and low-ethanol scenarios. 
 218

 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 

2014.395 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 

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 

5,300 additional trucks drivers for the transport of biofuel feedstocks and finished products. 

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. Discussions with transport industry officials 

support this conclusion. 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.HHHH 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. Distant truck 

traffic associated with the plant will be diffuse. Hence, we expect that impacts associated with 

such distant traffic are negligible. Routes in close proximity to plants may require repaving as a 

result of construction traffic associated with the facility. As such, the repaved routes would be 

more capable of handling additional truck traffic associated with production at the plants. The 

improved routes can also be expected to provide benefits for communities in close proximity to 

the production plant as well as lower maintenance costs. 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 

 

HHHH 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. 
 

 219

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 RIA. 

1.6.7 Petroleum Terminal Accommodations

 Petroleum terminals will need to install additional storage capacity to accommodate the 

volume of ethanol, cellulosic distillate fuel/renewable diesel fuel, and biodiesel that we anticipate 

will be used in response to the RFS2 standards. We estimate that it would be necessary to 

maintain an inventory level of 15% of the annual consumption of a given biofuel 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 biofuel 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 in our analysis as opposed to use of pipelines for the shipment 

of petroleum-based fuels. The need for additional biofuel storage volume at terminals to provide 

a buffer for interruptions in delivery may be reduced somewhat to the extent that pipelines play a 

role in the distribution of biofuels. We further estimate that an additional 30% of storage 

capacity would be needed as working space to accommodate biofuel deliveries.IIII Our estimates 

of the biofuel storage capacity needed at petroleum terminals by 2022 to facilitate the 

distribution of the volume of biofuels that we project would be used to meet the RFS2 volumes 

are based on the application of these working inventory and working space estimates. These 

estimates are presented in Table 1.6.7-1. 

Table 1.6.7-1. 

Total Biofuel Storage Capacity needed at Petroleum Terminals by 2022 

to Handle the RFS2 Volumes 

Biofuel Tankage (Mbbl) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Ethanol 81.2 103.9 149.7 

Cellulosic Distillate Fuel/ 

Renewable Diesel Fuel 

43.0 30.3 NA 

Biodiesel 7.2 7.2 7.2 

 To estimate of the additional biofuel storage tank capacity that should be attributed to the 

incremental RFS2 biofuel volumes relative to the 2 reference cases, we subtracted the volume 

which would have been in place regardless of the RFS2 program under the 2 reference cases. 

The same working inventory and working space estimates were used to estimate the volume of 

biofuel storage under the reference cases. 

 

 

IIII 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. 
 220

 Overall demand for the gasoline motor vehicle fuel is expected to remain relatively 

constant through 2022 whereas demand for compression ignition vehicle fuel is anticipated to 

increase by over 10% over the same time period.396 We expect that much of the demand for new 

ethanol storage capacity 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 might potentially be accommodated by modifying existing gasoline tanks for ethanol 

service. Likewise, we anticipate that much of the demand for cellulosic distillate fuel/renewable 

diesel fuel storage capacity might be satisfied by dedicating storage tanks that would have been 

constructed to store petroleum-based diesel fuel to instead store these biofuels. Due to the 

anticipated lower energy density of cellulosic distillate fuel relative to petroleum-based diesel 

fuel (~90% of petroleum-based diesel fuel), we project that only 90% of the demand for new 

cellulosic distillate/renewable diesel fuel storage might potentially be accommodated by 

modifying existing gasoline tanks for cellulosic distillate/renewable diesel fuel service. To 

provide some margin to compensate for the need for a greater degree of new tank construction 

than that indicated by the above analysis, we assumed that 5% of the tanks which might have 

been rededicated tanks previously used for petroleum-based fuels would instead be new 

construction. The rededication to ethanol service of storage tanks previously used to store 

gasoline involves lining the tank and other miscellaneous modifications to ensure the tank is 

compatible with ethanol. We assume that no changes would be needed to petroleum-based 

diesel fuel storage tanks to allow them to be used to store cellulosic distillate fuel/renewable 

diesel fuel. Since biodiesel storage tanks need to be insulated and heated under cold conditions, 

we assumed that all of the need for additional biodiesel storage capacity would be satisfied 

through new construction. 

The volume of new biofuel storage capacity that we project would be needed as a result 

of the implementation of the EISA under the 2 reference cases is presented in Tables 1.6.7-2 and 

1.6.7-3. 
 

 221

Table 1.6.7-2. 

Additional Biofuel Storage Capacity at Petroleum Terminals by 2022 

to Meet the EISA Volumes Relative to the RFS1 Reference Casea

Biofuel Tankage (Mbbl) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Ethanol, Total 48.5 70.2 116.9 

Ethanol, New Construction 17.6 25.5 42.5 

Ethanol, Retrofitted Tanks 30.9 44.7 74.4 

Cellulosic Distillate Fuel/Renewable 

Diesel Fuel, Total 

43.0 30.3 NA 

Cellulosic Distillate Fuel/Renewable 

Diesel Fuel, New Construction 

6.2 4.4 NA 

Cellulosic Distillate Fuel/Renewable 

Diesel Fuel, Rededicated Tanks 

36.8 25.9 NA 

Biodiesel, New Construction 5.9 5.9 5.9 

All Biofuels, New Construction 29.7 35.8 48.4 

All Biofuels, Retrofitted Tanks 30.9 44.7 74.4 

All Biofuels, Redicated Tanks 36.8 25.9 0 

a “Retrofitted” refers to tanks that need significant changes to be made suitable for biofuel storage. 

“Rededicated” refers to tanks that need essentially no changes to be made suitable for biofuel storage. 

Table 1.6.7-3. 

Additional Biofuel Storage Capacity at Petroleum Terminals by 2022 

to Meet the EISA Volumes Relative to the AEO Reference Casea

Biofuel Tankage (Mbbl) 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

Ethanol, Total 20.0 41.7 88.5 

Ethanol, New Construction 12.7 26.5 56.3 

Ethanol, Retrofitted Tanks 7.3 15.2 32.2 

Cellulosic Distillate Fuel/Renewable 

Diesel Fuel, Total 

43.0 30.3 NA 

Cellulosic Distillate Fuel/Renewable 

Diesel Fuel, New Construction 

6.2 4.4 NA 

Cellulosic Distillate Fuel/Renewable 

Diesel Fuel, Rededicated Tanks 

36.8 25.9 NA 

Biodiesel, New Construction 5.5 5.5 5.5 

All Biofuels, New Construction 24.4 36.4 61.8 

All Biofuels, Retrofitted Tanks 7.3 15.2 32.2 

All Biofuels, Rededicated Tanks 36.8 25.9 0 

a“Retrofitted” refers to tanks that need significant changes to be made suitable for biofuel storage. “Rededicated” 

refers to tanks that need essentially no changes to be made suitable for biofuel storage. 
 222

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.397 We acknowledge that it may not be possible for some terminals that have 

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 biofuel storage could 

receive truck shipments of ethanol from terminals with more substantial biofuel storage capacity. 

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 biofuel 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. We estimate that approximately 

91% 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 would have some opportunity to 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 have 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, 

cellulosic distillate fuel/renewable diesel fuel, and biodiesel into petroleum-based fuels. In the 

case of ethanol other miscellaneous upgrades to piping, pumps, seals, and vapor recovery 

systems would also be needed to ensure ethanol compatibility. In the case of biodiesel, piping 

and blending systems would need to be heated/insulated under cold conditions. All terminals 

with biofuel blending capability would need to provide facilities for receipt of biofuels via tank 

truck. 

There are currently 1,063 petroleum terminals that carry gasoline.398 We project that 899 

of these terminals (85% of the total) would install E10 blending equipment absent the 

implementation of the RFS2 requirements in order to support the consumption of 13.18 BGY of 

ethanol by 2022 under the AEO 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 2022.399 We project that 

essentially all gasoline would be either E10 or E85 by 2022 under the RFS2 standards. Thus, we 
 

 223

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 blending capability absent the RFS2 standards 

under AEO reference case, we estimate that 164 terminals would need to install ethanol blending 

equipment to meet the RFS2 volumes relative to the AEO reference case. 

The estimated number of terminals that would need to install ethanol blending capability 

as a result of the RFS2 standards relative to the RFS1 reference case is based on an extrapolation 

of the estimate for the AEO reference case. The volume of ethanol projected to be used under 

the RFS1 reference case is 53% of the volume projected to be used under the AEO reference 

case. We estimated that the number of terminals that blend ethanol under the RFS1 reference 

case is 53% of the number under the AEO reference case (899 x 53% = 481). Based on this, we 

estimate that an additional 582 terminals would install ethanol blending capability to meet the 

RFS2 volumes under the RFS1 reference case. 

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 RFS2 standards 

under the high-ethanol scenario.JJJJ 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 

under the high-ethanol scenario. The remaining terminals (132 out of a total of 1,063) would 

only have E10 blending capability in 2022 under the high-ethanol scenario. 

Under the primary mid-ethanol scenario, we estimate that 60% of the nation would need 

to have reasonable access to E85 in order to support the use of the projected volume of E85 

needed to comply with the RFS2 standards. Our estimate of the number of terminals that would 

need to install E85 blending capability under the mid-ethanol scenario is based on the ratio of the 

percent of the country which would need to have reasonable access to E85 under the mid-ethanol 

scenario relative to the high-ethanol scenario. By multiplying our 90% estimate of the number of 

terminals that would need to install E85 under the high-ethanol scenario by 60%/70%, we 

arrived at an estimate of 77% of all gasoline terminals (820) having E85 access under the midethanol scenario. Under the low-ethanol scenario, we estimate that 40% of the nation would 

need to have reasonable access to E85 in order to support the use of the projected volume of E85 

needed to comply with the RFS2 standards. We used the same approach outlined above to 

estimate that 51% of all gasoline terminals (547) would install E85 blending capability under the 

low-ethanol scenario. 

We estimate that the terminals which would have installed E10 blending capability absent 

the RFS2 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.KKKK 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 

 

JJJJ A discussion of our E85 use projections is contained in chapter 1.7 of this RIA. KKKK Additional ethanol storage and modifications to terminal piping would also be needed to supply additional 

quantity of ethanol needed to blend E85. 
 224

gasoline. The potential need to provide special blendstocks at petroleum terminals for the 

manufacture of E85 is discussed in Section 1.6.8 of this RIA. 

 Our estimate of the number of terminals that would install biodiesel blending capability 

under the RFS2 standards is based on an extrapolation of the analysis conducted for the NPRM. 

We estimate that 853 terminals handle diesel fuel.400 We estimate that approximately 62.5 

billion gallons of diesel fuel would be used in 2022.LLLL Thus, the average diesel throughput per 

terminal would be approximately 73.2 MGY. In the NPRM analysis, 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 assumed to be used by 2022 under the RFS2 standards in the 

NPRM. 

We estimated the number of terminals that would need to blend biodiesel for our FRM 

analysis by increasing the NPRM estimate in proportion to volume of biodiesel that we project 

would be used in the FRM by 2022 relative to that projected in the NPRM (1,671 Mgal/yr / 810 

Mgal/yr). By so doing, we estimate that 777 terminals will be needed to blend biodiesel by 2022 

to support the use of the biodiesel volume projected to be used in this FRM. 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 

380 MGY 2022 baseline. Thus, we project that 637 additional terminals would blend biodiesel 

as a result of the RFS2 standards under the RFS1 reference case and 600 under the AEO 

reference case. 

 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.401 Based on this concern, in a presentation at the 

recent 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. 402 We believe that given the time over which biofuel 

volumes ramp up under the RFS2 standards, it should be feasible for terminals to adapt 

sufficiently within the time frame established by the EISA. 

1.6.8 Potential Need for Special Blendstocks at Petroleum Terminals for E85 

 ASTM International is considering a proposal to lower the minimum ethanol 

concentration in E85 to facilitate meeting ASTM minimum volatility specifications in cold 

 

LLLL 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 RIA. 
 

 225

climates and when only low vapor pressure gasoline is available at terminals.MMMM Commenters 

on the ASTM proposal have stated that the current proposal to lower the minimum ethanol 

concentration to 68 volume percent may not be sufficient for this purpose. ASTM International 

may consider an additional proposal to further decrease the minimum ethanol concentration. 

Absent such an adjustment, a high-vapor pressure petroleum-based blendstock such as butane 

would need to be supplied to most petroleum terminals to produce E85 that meets minimum 

volatility specifications. In such a case, butane would need to be transported by tank truck from 

petroleum refineries to terminals and storage and blending equipment would be needed at 

petroleum terminals. 

Automated inline butane blending systems located at terminals can be used to blend 

butane into gasoline before it is blended with denatured ethanol. Such systems consist of inline 

RVP analyzers which sample gasoline being transferred from storage tanks to loading racks 

where it is to be mixed with ethanol to produce E85. 

The analyzers determine the RVP of the incoming gasoline stream and use this 

information to determine the volume of butane which must be blended with the gasoline down 

stream of the analyzer required to meet the volatility specification for the finished product. The 

analyzer, variable frequency butane pump, and supporting equipment are self-contained on a 

skid-mounted unit, and requires at least one 60,000 gallon butane storage tank. 

 We estimated the number of automated inline butane blending systems, butane storage 

tanks, tanks trucks, railcars, trans-loading facilities, and other facility changes needed for butane 

blending as follows. Of the existing 1,063 terminals, two-thirds (709 terminals) are assumed to 

require butane in order to blend E85 that is complaint with ASTM International volatility 

specifications. All 709 terminals are assumed to require new butane blending equipment. Of 

these terminals, twenty-five percent (177) are assumed to receive butane via railcar and seventyfive percent (532) are assumed to receive butane via tank truck. Of the 177 terminals that 

receive butane via railcar, fifty-percent are assumed to have butane directly off-loaded to tank 

storage. In the case of the other fifty-percent of the terminals, butane is assumed to be transloaded from railcars to tank trucks for final delivery to terminals. This requires that each 

terminal have a skid-mounted inline butane blending system and two 60,000 gallon butane tanks. 

Usable tank volumes are assumed to be 51,000 gallons per tank. Tank trucks are assumed to 

carry 8,200 gallons of butane. Railcars are assumed to carry 31,500 gallons of butane. 

Our estimates of the number of tank trucks and railcars required to deliver butane varies 

by control scenario (see Table 1.6.8-1). 

 

MMMM Minimum volatility specifications were established by ASTM to address safety and vehicle driveability 

considerations. 
 226

Table 1.6.8-1. 

Estimated Number of Tank Trucks and Rail Cars Needed for Shipment of Butane 

Number of Tank Trucks and Rail Cars Needed to 

Transport Butane 

 Low Case Medium Case High Case 

Tank Truck (8,200 gallons) 2,165 3,280 5,530 

Railcar (31,500 gallons) 236 358 602 

 Instead of lowering the minimum ethanol concentration of E85, some stakeholders are 

discussing establishing a new high-ethanol blend for use in flex-fuel vehicles. Such a fuel would 

have a minimum ethanol concentration that would be sufficient to allow minimum volatility 

specifications to be satisfied while using finished gasoline that is already available at petroleum 

terminals.NNNN E85 would continue to be marketed in addition to this new fuel for use in flexfuel vehicles when E85 minimum volatility considerations could be satisfied. 

 We believe that industry will resolve the concerns over the ability to meet the minimum 

volatility needed for high-ethanol blends used in flex-fuel vehicles in a manner that will not 

necessitate the use of high-vapor pressure blendstocks in their manufacture. Nevertheless, 

petroleum terminals may find it advantageous to blend butane into E85 because of the low cost 

of butane relative to gasoline provided that the cost benefit outweighs the associated butane 

distribution costs.OOOO

1.6.9 Need for Additional E85 Retail Facilities 

 The number of additional E85 retail facilities needed to consume the volume of ethanol 

used under EISA varies substantially depending on the control case. As discussed in Section 

1.7.1.2 of this RIA, we estimate that end-users would need to have reasonable access to E85 in 

70% of the nation by 2022 under the high-ethanol scenario given our projections regarding the 

population of flexible fuel vehicles (FFVs) and E85 refueling frequencies.403 Under the primary 

mid-ethanol scenario we estimate that reasonable access would be needed in 60% of the nation, 

and 40% under the low-ethanol scenario. 

We define reasonable access as one in four gasoline retail facilities offering E85 in a 

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 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. 

 

NNNN Such a new fuel might have a lower ethanol concentration of 60% and a maximum ethanol concentration of 

85%. 

OOOO EPA may consider reevaluating its policies regarding the blendstocks used in the manufacture of E85 to 

facilitate this practice. 
 

 227

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.404 The National Association of 

Convenience Stores (NACS) reported that in 2006, 36.6% of the respondents to their survey 

offered diesel fuel.405 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 or alternative fuel 

vehicles that can only be fueled on the alternative fuel, flex fuel vehicles can refuel on gasoline 

as well as E85. Thus, we believe that fewer E85 stations should be necessary than were provided 

for diesel fuel.PPPP

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 2000.406 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. 

The National Petroleum News (NPN) estimates that there were a total of 161,768 

gasoline retail facilities in the United States in 2008.407 We multiplied the one-in-four 

reasonable access assumption by the percentage of the retail market that would need to have 

reasonable access to E85 and the total number of retail facilities to arrive at our estimate of the 

number of E85 retail facilities needed under a given RFS2 control scenario. Under the highethanol scenario, we estimate that a total of 28,309 E85 refueling facilities would be needed. 

Under the primary mid-ethanol scenario, we estimate that 24,265 facilities would be needed, and 

that 16,177 facilities would be needed under the low-ethanol scenario. 

In order to provide for sufficient E85 throughput while maintaining timely access of 

customers to an E85 dispenser, we estimated that all E85 retail facilities would have 3 E85 

dispensers under the high-ethanol scenario.QQQQ Under the primary mid-ethanol scenario, we 

estimate that half of E85 retail facilities would have a single dispenser and the other half would 

 

PPPP Particularly since we do not assume that flex-fuel vehicles would refuel on E85 all the time. A discussion of 

E85 refueling rates is contained in Section 1.7.1.2.4 of this RIA. 

QQQQ Each dispenser has two E85 refueling positions. 
 228

have 2 dispensers. Under the low-ethanol scenario, we estimate that all E85 retail facilities 

would have a single dispenser. These estimates are based on ensuring that E85 throughput per 

refueling position is consistent with historical data for gasoline throughput per refueling position. 

We believe that this approach provides an estimate consistent with ensuring that consumers have 

reasonable access to a E85 refueling position while providing the retailer with sufficient 

throughput to justify their investment in installing E85 refueling facilities. 

The National Association of Convenience Stores (NACS) reports throughput per 

refueling position.408 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 

choose 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).RRRR 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 

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.SSSS

The National Ethanol Vehicle Coalition (NEVC) estimates there are currently 2,095 E85 

refueling facilities.409 However, the NEVC estimate includes E85 refueling facilities that are not 

open to the general public. “NEAR85” estimates that there are currently 1,293 E85 retail 

facilities.410 The Near85 estimate includes only retail facilities. Based on these data, we are 

assuming that there are approximately 1,300 E85 retail facilities currently in service. By 

increasing the number of E85 retail facilities by the same proportion as the growth in ethanol use 

under the AEO reference from now until 2022, we estimate that 4,500 E85 refueling facilities 

would be in place by 2022 absent the RFS2 standards. We estimate that there would be 1,210 

E85 refueling facilities under the RFS1 reference case. We arrived at this estimate by a review 

of historical data regarding the number of E85 retail facilities that were in place when ethanol 

use levels matched those under the RFS1 reference case. We assume that all E85 retail facilities 

 

RRRR In many cases, we expect that the “other” fuel is kerosene. 

SSSS The year 2003 had the highest average throughput per refueling position over the years 2001- 2006. 
 

 229

under the REFS1 and AEO reference cases would have a single E85 dispenser (with 2 refueling 

positions). 

To estimate the E85 refueling facility changes which that may be needed to reach the 

RFS2 volumes, we compared the changes needed to support the use of the total volume of E85 

projected to be used under the 3 control scenarios to the E85 refueling facilities needed under the 

2 reference cases. Our estimates of the of the E85 facility changes that will take place to reach 

the RFS2 volumes are contained in Tables 1.6.9-1 and 1.6.9-2 

Table 1.6.9-1. 

Additional E85 Retail Facilities Needed by 2022 to Reach the RFS2 Volumes Relative to the 

RFS1 Reference Case 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

New E85 Installation with 1 Dispenser 15,000 10,900 0 

New E85 Installation with 2 Dispensers 0 12,100 0 

New E85 Installation with 3 Dispensers 0 0 27,100 

Addition of 2 Dispensers to Retail 

Facility that had 1 Dispenser 

0 0 1,200 

Table 1.6.9-2. 

Additional E85 Retail Facilities Needed by 2022 to Reach the RFS2 Volumes Relative to the 

AEO Reference Case 

 Low-Ethanol 

Scenario 

Mid-Ethanol 

Scenario 

High-Ethanol 

Scenario 

New E85 Installation with 1 Dispenser 11,700 7,600 0 

New E85 Installation with 2 Dispensers 0 12,100 0 

New E85 Installation with 3 Dispensers 0 0 23,800 

Addition of 2 Dispensers to Retail 

Facility that had 1 Dispenser 

0 0 4,500 

On average, approximately 1,520 additional E85 facilities will be needed each year from 

2010 through 2022 under our primary scenario relative to the AEO reference case. Under the 

high and low-ethanol scenarios, an additional 1,820 and 900 E85 retail facilities per year would 

be needed respectively. Under the high-ethanol scenario, 4,500 facilities would also need to be 

upgraded to provide 3 E85 dispensers rather than a single dispenser. Under the high ethanol case 

and to a lesser extent under the primary case, this represents an aggressive timeline for the 

addition of new E85 facilities given that the small number of E85 retail facilities in service 

today. Nevertheless, we believe the addition of these numbers of new E85 facilities may be 

possible for the industries that manufacture and install E85 retail equipment. Underwriters 

Laboratories requires that E85 refueling dispenser systems must be certified as complete 

units.TTTT To date, no complete E85 dispenser systems have been certified by UL. We 

 

TTTT See http://ulstandardsinfonet.ul.com/outscope/0087A.html 
 230

understand that all the fuel dispenser components with the exception of the hoses that connect to 

the refueling nozzle have successfully passed the necessary testing. There does not appear to be 

a technical difficulty in finding hoses that can pass the required testing. Therefore, we anticipate 

this situation will be resolved once the demand for new E85 facilities is demonstrated. Hence, 

we believe that the current lack of a UL certification for complete E85 dispenser systems will not 

impede the installation of the additional E85 facilities that we projected will be needed. 

Petroleum retailers expressed concerns about their ability to bear the cost of installing the 

needed E85 refueling equipment given that most retailers are small businesses and have limited 

capital resources. They also expressed concern regarding their ability to discount the price of 

E85 relative to E10 sufficiently to persuade flexible fuel vehicle owners to choose E85 given the 

lower energy density of ethanol. Today’s rule does not contain a requirement for retailers to 

carry E85. We understand that retailers will only install E85 facilities if they can be assured of 

sufficient E85 throughput to recover their capital costs and that this could become an issue. 

However, if obligated parties are going to comply with the RFS2 standards, they will have to 

find a way to get the appropriate incentives to retailers. In addition, the projections regarding the 

future cost of gasoline relative to ethanol indicate that as crude oil prices rise it may be possible 

to price E85 more profitably. While the $3 billion total cost for E85 refueling facilities is a 

substantial sum under our primary E85 facility scenario, it equates to 3 cents per gallon of E85 

throughput.UUUU We expect that larger fuel retailers would be most likely to install new E85 

refueling facilities. Therefore, the smallest retailers would not need to install E85 facilities. 

Government incentives are also available to help defer the cost of installing E85 retail equipment 

and expansions of these incentives are under consideration.VVVV Given the projections regarding 

ethanol pricing relative to gasoline and other factors that may tend to encourage ethanol 

consumption, we believe that it may be possible for retailers to price E85 in such a way as to 

facilitate the sale of the E85 volumes that we estimate would be used to facilitate meeting the 

RFS2 volumes.WWWW 

1.6.10 Fuel Distribution Accommodations to Support the Introduction of E15 Should a 

Waiver be Granted 

We evaluated the changes to the fuel distribution system that might be needed to support 

the introduction of E15 if a waiver is granted by EPA in order to provide the basis for a 

preliminary cost analysis regarding such changes. Our nation’s system of gasoline fuel 

regulation, fuel production, fuel distribution, and fuel use is built around gasoline with ethanol 

concentrations limited to E10. As a result, while a waiver may legalize the use of mid-level 

ethanol blends under the CAA, there are a number of other actions that would have to occur to 

bring mid-level blends to retail. This discussion focuses on the changes which may impact the 

costs associated with the introduction of E15. A number of changes/accommodations would also 

be needed to federal, state, and local regulations. 

 

UUUU 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 RIA. E85 retail 

costs were amortized over 15 years at a 7% cost of capital. 

VVVV See Section 1.7.1.2.3 of this RIA for a discussion of government incentives to install E85 retail refueling 

equipment. 

WWWW This issue is discussed in Section 1.7.1.2.5 of this RIA. 
 

 231

The CAA provides a 1 pound RVP waiver for ethanol blends of 10 volume percent or 

less. This waiver was granted at a time when ethanol use was not widespread. Thus, the 

environmental considerations at the time were relatively minor. Now that the nation is moving 

to E10 nationwide, the 1 psi waiver may have significant environmental implications for all 

conventional gasoline. Lacking a similar RVP waiver, a special low-RVP gasoline blendstock 

would be needed at terminals to allow the formulation of mid-level ethanol blends that are 

compliant with EPA RVP requirements. Providing such a separate gasoline blendstock would 

present significant logistical challenges and costs to the fuel distribution system. It should be 

possible for refiners to formulate a gasoline blendstock that would be suitable for manufacturing 

both mid-level ethanol blends and E10 at the terminal. While this would avoid the logistical 

problems associated with maintaining separate blendstocks, there could be additional refining 

costs. 

Assuming that refiners develop a common gasoline blendstock for both E10 and E15, the 

accommodations that would be needed to the fuel distribution infrastructure to facilitate the 

introduction of a mid-level ethanol blend would primarily be limited to vehicle refueling 

facilities. Some terminal operators may need to modify their ethanol blending facilities to allow 

the in line blending of a mid-level ethanol blend. However, in most if not all cases this would 

only involve a modification to the software for the blending system to allow a mid-level as well 

as an E10 or E0 blend rate rather than necessitating a physical change to the system. Terminal 

operators would also need to provide for the receipt and storage of the greater volumes of ethanol 

needed to manufacture a mid-level ethanol blend.XXXX

Fuel retailers would need to ensure that the equipment used to store and dispense E15 is 

suitable for this purpose. EPA’s Office of Underground Storage Tanks (OUST) requires that 

underground storage tank (UST) systems must be compatible with the substance stored in the 

system. A number of authorities require that fuel retailers use equipment that has been certified 

as compatible with the fuel being sold. Such a certification is required by the Occupational 

Safety and Health Administration (OSHA), many local fire marshals, tank insurance and state 

tank fund policies, and the provisions contained in many business loan agreements. 

Underwriters Laboratories (UL) is the leading safety certification organization and is 

often specifically referenced in regulations and insurance policies. UL stated that they have data 

which indicates that the use of fuel dispensers certified for up to E10 blends could dispense 

blends up to a maximum ethanol content of 15 volume percent without causing critical safety 

concerns.YYYY Based on these data, UL stated that it would support a decision by Authorities 

who Have Jurisdiction (AHJs, e.g. state and local fire marshals) to permit equipment originally 

certified for up to E10 blends to be used to dispense up to 15 volume percent ethanol.ZZZZ 

However, UL stated that it could not recertify equipment that was originally certified for up to 

 

XXXX The need for additional facilities to receive, store, and blend ethanol is anticipated in any event due to the 

projected need for expanded use of E85 to meet the renewable fuel volume requirements under EISA. 

YYYY The UL announcement can be found at http://www.ul.com/newsroom/newsrel/nr021909.html ZZZZ The reference of up to 15 volume percent ethanol by UL does not equate to E15. Variability in the test method 

for ethanol content and other factors mean that in-use fuel blends with a nominal ethanol content of 15 % could at 

times exceed 15 volume percent. 
 232

E10 blends for a higher ethanol blend.AAAAA Furthermore, the UL announcement did not address 

underground storage systems (storage tank, piping, valves, pumps, fittings, leak detection, etc.). 

Evaluations are currently underway by EPA’s Office of Underground Storage Tanks 

(OUST) in coordination with the Department of Energy (DOE) and UL regarding the 

compatibility of existing UST systems to store mid-level ethanol blends. Based on this 

evaluation, OUST could prepare guidance to states on how facilities with UST systems that store 

a mid-level ethanol blend could demonstrate compliance with the EPA requirement that such 

systems are compatible with the substance stored in the system.BBBBB The Department of Energy 

in coordination with UL is conducting testing to evaluate the suitability of existing retail fuel 

dispensing equipment to accommodate a mid-level ethanol blend.CCCCC Depending on the results 

of the OUST and DOE/UL efforts, the authorities referenced above may be encouraged to allow 

the use of certain existing equipment originally certified for E10 to handle a mid-level ethanol 

blend. One potential approach in lieu of requiring a UL certification might be for AHJs to 

require that fuel retailers have records to establish what type of equipment is present and to 

obtain manufacture certifications that the equipment is suitable for a mid-level ethanol blend. 

Documenting the manufacturer and model number of the various components of their 

fuel storage and dispensing equipment may be a relatively simple undertaking for newer stations 

that have records readily on hand. However, for older stations that may have had multiple 

owners, it may be difficult to assemble a full list of their fuel handling components. For above 

ground components (i.e. the dispenser), a potential gap in the records could be resolved by a 

visual inspection. However, with respect to underground components there may no be practical 

way to identify certain components without breaking concrete. The most difficulty is likely to be 

faced in identifying the type of seals, gaskets, pipe joints, and bonding materials used by the 

contractors who installed the equipment.DDDDD Many UST installation companies and 

components manufactures may have gone out of business, further complicating the process of 

identifying what hardware is installed and obtaining a manufacture certification of compatibility. 

This may tend to limit the ability to introduce a mid-level ethanol blend to newer fuel retailers 

and larger chain retailers who may have more complete records. However, such retailers are also 

likely to have a relatively high fuel sales compared to the fuel retailer population as a whole. 

Thus, the ability to introduce a mid-level ethanol blend at such retailers could potentially support 

the sale of a substantial volume of such a fuel. 

If a partial waiver is granted which provides for the use of a mid-level ethanol blend in a 

subset of vehicles, then E10 would need to continue to be made available for use in 

vehicles/equipment not covered by the waiver.EEEEE We believe that this might be most 

 

AAAAA UL announced a separate retail dispenser certification pathway for ethanol blends up to E25 in August of 

2009 (http://www.ul.com/global/eng/pages/corporate/newsroom/newsitem.jsp?n=ul-announces-new-certificationpath-for-ethanol-fuel_20090810122400). This is addition to the UL certification pathways to cover up to E10 

blends and to cover E85 and lesser ethanol blends. 

BBBBB The EPA OUST requirement is located at 40 CFR Part 280.32. Enforcement of this requirement is typically 

delegated to the State level. 

CCCCC This is the above ground equipment commonly referred to as the fuel pump stand or fuel dispenser. DDDDD These are the UST components where there may be the most concern regarding compatibility with a midlevel ethanol blend. 

EEEEE E0 will also be needed for use in gasoline piston engine aircraft. 
 

 233

practicably accomplished by switching some or all dispensers of regular gasoline at a retail 

facility to handle the mid-level ethanol blend.FFFFF The premium dispenser could continue to 

handle E10 (or E0) for use in legacy vehicles/equipment.GGGGG Some of the nonroad equipment 

currently requires the use of a premium grade fuel. Thus, premium gasoline would continue to 

be the “universal fuel” as it is today, capable of being used in any gasoline vehicle or equipment. 

Some retailers who have multiple regular grade storage tanks may choose to offer both an E15 

and E10 regular grade in order to offer a less expensive E10 fuel to customers that do not require 

the use of premium but are not covered by a partial waiver. In most cases this would likely 

involve breaking concrete to separate tanks that are currently interconnected. 

If the OUST and DOE evaluations show that current retail fuel equipment is largely 

compatible with a mid-level ethanol blend, it may be possible for a substantial number of retail 

facilities to introduce a mid-level ethanol blend at a modest cost. 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. If more extensive modifications are shown to be necessary, the costs could 

approach those necessary to introduce E85. If this is the case, the costs would tend to inhibit the 

rapid introduction of a mid-level ethanol blend. The potential costs to the fuel distribution 

system associated with the introduction of E15 are discussed in Section 4.2.1.1. 

1.7 Ethanol Consumption Feasibility 

1.7.1 Background 

 Over the past decade, ethanol use has grown rapidly due to oxygenated fuel requirements, 

MTBE bans, tax incentives, state mandates, the first federal renewable fuels standard (“RFS1”), 

and rising crude oil prices. Although the cost of crude has come down since reaching record 

levels in 2008, uncertainty surrounding pricing and the environmental implications of fossil fuels 

has continued to drive ethanol use. 

 

 As shown in Table 1.7-1, a record 9.5 billion gallons of ethanol were blended into U.S. 

gasoline in 2008. EIA is forecasting additional growth in the years to come.HHHHH According to 

their recently released Short-Term Energy Outlook (STEO), EIA is predicts 0.7 million barrels 

of daily ethanol use in 2009, which equates to 10.7 billion gallons. The October 2009 STEO 

projects that total ethanol usage (domestic production plus imports) will reach 12.1 billion 

gallons by 2010. 

 

FFFFF Commenters stated that this arrangement could encourage misfueling if the “premium grade” E10 was 

substantially more costly than the “regular grade” E15. 

GGGGG The state of Oregon recently amended its requirement that all gasoline contain 10 percent ethanol to allow 

premium grade gasoline which does not contain ethanol to be sold for use in specified equipment/vehicles which 

may not be ethanol tolerant (including gasoline piston engine aircraft) 

http://www.leg.state.or.us/09reg/measures/hb3400.dir/hb3497.en.html 

HHHHH EIA, Monthly Energy Review, September 2009 (Table 10.2b). 
 234

Table 1.7-1 

U.S. Ethanol Consumption 

Year Production Net Importsb Totala

1999 1.4 0.0 1.4

2000 1.6 0.0 1.6

2001 1.7 0.0 1.7

2002 2.0 0.0 2.0

2003 2.7 0.0 2.8

2004 3.3 0.1 3.5

2005 3.8 0.1 4.0

2006 4.6 0.7 5.3

2007 6.3 0.4 6.7

2008 9.0 0.5 9.5

Ethanol Usage (Bgal)

a

EIA Monthly Energy Review September 2009 (Table 10.2)

bEIA website (http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm)
 

 235

 

 The National Petrochemical and Refiners Association (NPRA) estimates that ethanol is 

currently blended into about 75 percent of all gasoline sold in the United States.IIIII The vast 

majority is blended as E10 or 10 volume percent ethanol, although a small amount is blended as 

E85 for use in flexible fuel vehicles (FFVs). California, the largest U.S. consumer of gasoline is 

yet to reach 100% E10 saturation. Historically, the state has only blended ethanol into gasoline 

at 5.7% vol%, limited by its Predictive Model blending constraints. However, California has 

since adjusted its model and effective January 1, 2010, ethanol blending is expected to increase 

to 10%. 

 Complete saturation of the gasoline market with E10 is referred to as the ethanol “blend 

wall.” The height of the blend wall in any given year is directly related to gasoline demand. In 

AEO 2009, EIA projects that gasoline energy demand will peak around 2013 and then start to 

taper off due to vehicle fuel economy improvements. As shown below in Figure 1.7-1, not only 

is EIA forecasting a flattening of gasoline energy demand in the future due to vehicle 

improvements, but AEO 2009 also shows an additional decline due to the recent economic 

downturn. This is a considerably different projection of the future than EIA made in their prior 

forecasts. Although we have presented AEO 2008 and AEO 2007 for illustrative purposes, the 

final release of AEO 2009 is the basis for all energy and ethanol consumption calculations 

utilized in this analysis. 

Figure 1.7-1 

Projected Gasoline Energy Demand 

0

5

10

15

20

25

2004

20052006

2007

2008

2009

20102011

2012

20132014

20152016

2017

201820192020

2021

202220232024

202520262027

2028

2029

2030

Year

Motor Gasoline + E85 Energy (Quadrillion BTUs)

AEO 2007

AEO 2008

AEO 2009 Final

 

IIIII Based on comments provided by NPRA (EPA-HQ-OAR-2005-0161-2124.1) 
 236

 

 Based on the gasoline demand projections in AEO 2009 , the maximum amount of 

ethanol that can be blended into gasoline as E10 will be around 14-15 billion gallons, depending 

on the year. There are many challenges associated with getting beyond the ethanol blend wall 

and consuming more than 14-15 billion gallons including rapid growth in FFV/E85 

infrastructure, problems with meeting ASTM specs, testing and potential approval of mid-level 

blends, etc. As such, as discussed earlier in Section 1.5.3, a growing number of companies are 

investigating non-ethanol biofuels (e.g., cellulose-based diesel, gasoline, etc.) as a mechanism 

for meeting the cellulosic biofuel standard. The benefit of synthetic hydrocarbon fuels is that 

there’s virtually no blend wall issue, they are fungible with existing fuel infrastructure and they 

can be priced at parity with petroleum at retail. In many ways, they are essentially drop-in 

replacements for gasoline and diesel. However, like all second-generation biofuels, there are 

technological and financial hurdles that need to be overcome before biomass-based synthetic 

hydrocarbon fuels can be brought to market. 

 These factors make it difficult to project the future mix of renewable fuels types that will 

be used to meet the RFS2 standards. To address the uncertainty of which fuels will be used in 

the future under RFS2, we have analyzed three control cases with varying levels of ethanol as 

part of this final rule. As shown below in Table 1.7.2, total ethanol usage (corn, imported and 

cellulosic) ranges from 17.5 to 33.2 billion gallons in 2022. 

Table 1.7-2 

Potential Ethanol Usage Scenarios Under RFS2 

Scenario

2022 Total 

Ethanol Use

RFS1 Reference Case 7.1

AEO 2007 Reference Case 13.2

Low-ETOH Control Case 17.5

Mid-ETOH Control Case (Primary) 22.2

High-ETOH Control Case 33.2

 Under the primary control case, ethanol consumption will need to be about three times 

higher than RFS1 levels, more than twice as much as today’s levels, and about 9 billion gallons 

higher than the ethanol consumption predicted to occur in 2022 absent RFS2 (according to AEO 

2007). A summary of the projected ramp up in ethanol usage in each of these three cases 

compared to the blend wall is provided in Figure 1.7-2. For more information on how the 

control case volumes were derived, refer to Section 1.2 of the RIA. 
 

 237

Figure 1.7-2 

Projected Increase in Ethanol Under RFS2 

0

5

10

15

20

25

30

35

2010

2011

2012

2013

2014

20152016

20172018

2019

2020

2021

2022

Year

Billion Gallons of Ethanol

High-ETOH Control Case

Mid-ETOH Control Case

Low-ETOH Control Case

E10 Blendwall

 As shown above in Table 1.7-2, all three ethanol usage scenarios modeled require the 

nation to get beyond the E10 blend wall. As expected, the more aggressive the ethanol usage, 

the sooner the nation hits the blend wall. As shown above, the nation is expected to hit the blend 

wall in 2013 under our high-ETOH control case, in 2014 under our primary mid-ETOH control 

case and closer to 2015 under our low-ETOH control case. Regardless, to meet today’s RFS2 

requirements using increased volumes of ethanol we are going to need to see growth in the FFV 

fleet , the E85 infrastructure, and in E85 refueling rates (consideration of mid-level blends is 

discussed below in Section 1.7.6 below). However, the amount of change needed is proportional 

to the amount of ethanol we rely upon vs other renewable fuels. As expected, the low-ETOH 

case would require only moderate changes in FFV/E85 infrastructure and refueling whereas the 

high-ETOH case would require very dramatic changes and likely a mandate. 

 Once the nation gets past the blend wall, more ethanol will need to be blended as E85 and 

less as E10. FFV owners who were formerly refueling on E10 will need to start filling up on 

E85. As shown in Figure 1.7-3, under our primary control case, we project that 12.9 billion 

gallons of ethanol would be blended as E10 and 9.3 billion gallons would be blended as E85 to 

reach the 22.2 billion gallons in 2022. 
 238

Figure 1.7-3. 

Ethanol by Blend in 2022 

0

5

10

15

20

25

30

35

Low-ETOH Mid-ETOH High-ETOH

RFS2 Control Case

Total Ethanol

Ethanol as E85

Ethanol as E10

 In the subsections that follow, we will present the FFV and E85 infrastructure 

assumptions made for the final impact analysis and the corresponding FFV E85 refueling rates 

that would be required to reach the ethanol volumes described above. We will also discuss some 

of the retail and other changes that might be needed to encourage E85 usage. 

 It is possible that conventional gasoline (E0) could co-exist with E10 and E85 for quite 

some time. However, for analysis purposes, we have assumed that E10 would replace E0 as 

expeditiously as possible and that all subsequent ethanol growth would come from E85. 

Furthermore, we assumed that no ethanol consumption would come from the mid-level ethanol 

blends (E15 or E20) since they are not currently approved for use in non-FFVs. However, in 

light of the Growth Energy waiver request, we discuss how approval of E15 for use in 

conventional vehicles could help the nation postpone the blend wall in Section 1.7.6. 

1.7.2 Projected Growth in Flexible Fuel Vehicles

 Over the years there have been several policy attempts to increase FFV sales including 

Corporate Average Fuel Economy (CAFE) credits and government fleet alternative-fuel vehicle 

requirements. As a result, there are an estimated 8 million FFVs on the road today, up from 7 

million in 2008. While this is not insignificant in terms of growth, FFVs continue to make up 

less than 4 percent of the total gasoline vehicle fleet. 
 

 239

 According to EPA certification data, over one million FFVs were sold in both 2008 and 

2009. Despite the recession and current state of the auto industry, automakers are incorporating 

more and more FFVs into their light-duty production plans. While the FFV system (i.e., fuel 

tank, sensor, delivery system, etc.) used to be an option on some vehicles, most are moving in the 

direction of converting entire product lines over to E85-capable systems. Still, the number of 

FFVs that will be manufactured and purchased in future years is uncertain. To measure the 

impacts of the RFS2 program, we considered three different FFV production scenarios that might 

correspond to the three biofuel control cases analyzed for the final rule. For all three cases, we 

assumed that total light-duty vehicle sales would follow AEO 2009 trends. The latest EIA report 

suggests lower than average sales in 2008-2013 (less than 16 million vehicles per year) before 

rebounding and growing to over 17 million vehicles by 2019 as shown below in Figure 1.7-4. 

We also used EIA’s car-to-truck sales split adjusted for NHTSA’s new car definition beginning 

in 2011. Accordingly, by 2022, cars are expected to comprise over 70% of new light-duty 

vehicle sales. 

Figure 1.7-4. 

Assumed Light Duty Vehicle Production 

0

2,000,000

4,000,000

6,000,000

8,000,000

10,000,000

12,000,000

14,000,000

16,000,000

18,000,000

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

Model Year

Light-Duty Vehicle Sales

Trucks

Cars

NPRM

 Although we assumed total vehicle and car/truck sales would be the same in all three 

cases, we assumed varying levels of FFV production. For our low-ethanol control case, we 

assumed steady business-as-usual FFV growth according to AEO 2009 predictions.JJJJJ For our 

primary mid-ethanol control case, we assumed increased FFV sales under the presumption that 

 

JJJJJ EIA, AEO 2009 April Update, Table 47. 
 240

GM, Ford and Chrysler (referred to hereafter as the “Detroit 3”) would follow through with their 

commitment to produce 50% FFVs by 2012. Despite the current state of the economy and the 

hardships facing the auto industry, the Detroit 3 appear to still moving forward with their 

voluntary FFV commitment.KKKKK And finally, for our high-ethanol control case, we assumed a 

theoretical 80% FFV mandate based on the Open Fuel Standard that was recently reintroduced in 

Congress. Based on reduced vehicle sales and gasoline demand, we believe an FFV mandate 

would be the only viable means for consuming the 32.2 billion gallons of ethanol in 2022 

required under the high-ethanol control case. All three sets of FFV production assumptions are 

presented in Table 1.7-5 (below) and more information on our primary case is presented below. 

 We estimate that the cost to produce FFVs could be anywhere from $50 to $100 per 

vehicle, depending on the vehicle and how many FFV-capable systems the automaker is 

producing. Current estimates suggest that the per-FFV cost could easily be as high as $100.LLLLL 

However, in the event of a hypothetical mandate, it’s likely that automakers would find a more 

economical way to mass produce the necessary ethanol-compatible fuel tanks, sensors, etc. As 

such, as explained further in Section 4.2 of the RIA, we assigned higher per-vehicle FFV 

production costs in the low-ETOH control case and lower production costs in the high-ETOH 

case. For more on this cost analysis, as well as assumptions made for the control cases, refer to 

Section 4.2 of the RIA. 

Table 1.7-5. 

Annual FFV Sales Assumptions 

Low-ETOH

Based on AEO 

2009 

Predictions

Mid-ETOH

Based on 50% 

Domestic 3 

Commitment

High-ETOH

Based on OFS 

Mandate in 

Congress

2010 1,253,426 1,848,835 3,617,298

2011 1,598,610 2,661,252 5,439,471

2012 1,903,862 3,523,548 7,393,103

2013 2,251,284 3,740,737 9,418,573

2014 2,523,575 3,881,960 11,403,172

2015 2,693,557 3,957,744 13,286,614

2016 2,761,794 3,968,776 13,323,649

2017 2,804,322 4,003,948 13,441,727

2018 2,929,336 4,043,259 13,573,697

2019 2,825,574 4,084,529 13,712,247

2020 2,771,285 4,117,519 13,822,998

2021 2,669,883 4,099,459 13,762,369

2022 2,607,584 4,096,590 13,752,738

Control Case FFV Production

 

KKKKK Ethanol Producer Magazine, “Automakers Maintain FFV Targets in Bailout Plans.” February 2009. Add 

citation to bankruptcy reports which second that GM & Chrysler plan to follow through with their FFV 

commitments. 

LLLLL Insert citation. 
 

 241

 For our primary mid-ETOH control case, we assumed that The Detroit 3 would continue 

to comprise 45% of total vehicle sales – 2008 production levels less Hummer, Landrover, Jaguar, 

Saab, Saturn, and Volvo (brands that were recently or are in the process of being sold off). We 

assumed that domestic automakers would continue to dominate truck sales and car sales would 

gradually increase to allow The Detroit 3 to continue to maintain 45% marketshare in future 

years. With respect to FFV sales, we assumed that the Detroit 3 would follow through with their 

FFV commitment and increase FFV production from 16% of total sales in 2008 to 50% of total 

sales in 2012. With respect to vehicle type, we assumed that about two-thirds of the Detroit 3’s 

FFV sales would be trucks – based on historical sales and 2009 MY offerings. Under our 

primary mid-ETOH scenario, as shown in Table 1.7-5, Detroit 3 and non-domestic FFV sales 

amount to just over 4 million per year in 2017 and beyond. 

 We assumed that non-domestic automakers would continue to maintain 55% marketshare 

in 2009 and beyond (based on adjusted 2008 production levels). Although non-domestic 

automakers have not made any official FFV production commitments, Nissan, Toyota, 

Mercedes, Izuzu, and Mazda all included at least one flexible fuel vehicle in their 2009 model 

year offerings.MMMMM We do not currently anticipate that the non-domestic automakers will 

follow through with an FFV commitment. However, it seems reasonable that we could expect a 

small amount of FFV growth in the future. As such, for our primary mid-ethanol control case, 

we assumed that non-domestic FFV production would grow from 1% in 2008 to 2% in 2009 and 

future years based on current FFV offerings. With respect to FFV vehicle type, we assumed 

about equal car and truck FFV sales (52% and 48%, respectively) based on 2008 sales. 

 Using the FFV annual sales estimates in Table 1.7-5 and applying the car/truck splits, our 

standard factors for annual VMT and scrappage, and projected vehicle fuel economy (based on 

the recently-proposed Vehicle Greenhouse Gas RuleNNNNN), we estimate that the maximum 

percentage of fuel (gasoline/ethanol mix) that could feasibly be consumed by FFVs in 2022 

would be about 20% under our mid-ETOH control case. Under our low-ETOH control, the 2022 

fuel fraction was estimated at 14%. And under the high-ETOH control case, with the FFV 

mandate, the fuel fraction was 56% in 2022. A summary of the FFV fuel fraction over time for 

each of these scenarios is presented in Figures 1.7-5 through 1.7-7. 

 

MMMMM National Ethanol Vehicle Coalition, 2009 FFV Purchasing Guide. NNNNN EPA’s Proposed Rulemaking to Establish Light-Duty Vehicle GHG Emission Standards and Corporate 

Average Fuel Economy Standards. 
 242

Figure 1.7-5 

Low-ETOH / Low-FFV Fuel Fraction

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Year

Gasoline Fuel Fraction

Nonroad, Motorcycles, etc. Legacy NonFFVs 2001+ NonFFVs FFVs

Figure 1.7-6 

Mid-ETOH / Mid-FFV Fuel Fraction

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Year

Gasoline Fuel Fraction

Nonroad, Motorcycles, etc. Legacy NonFFVs 2001+ NonFFVs FFVs
 

 243

Figure 1.7-7 

High-ETOH / High-FFV Fuel Fraction 

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Year

Gasoline Fuel Fraction

Nonroad, Motorcycles, etc. Legacy NonFFVs 2001+ NonFFVs FFVs

 As shown above, we split the non-FFV fuel fraction into multiple categories to help 

determine the number of engines/vehicles that might be capable of handling E15 in the event of a 

waiver. The basis for these assumptions and more information on the data sources is presented 

in Section 1.7.6. 

1.7.3 Projected Growth in E85 Access 

According to the National Ethanol Vehicle Coalition (NEVC), there are currently 2,100 

gas stations offering E85 in 44 states plus the District of Columbia.OOOOO While this represents 

significant industry growth, it still only translates to 1.3% of U.S. retail stations nationwide 

carrying the fuel.PPPPP 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.QQQQQ Accordingly, just over 5% of the nation currently has 

reasonable access to E85, up from 4% in 2008 (based on a mid-year NEVC pump 

estimate).RRRRR 

 

OOOOO NEVC website, accessed on November 23, 2009 PPPPP Based on National Petroleum News gasoline station estimate of 161,768 in 2008. 

QQQQQ For a more detailed discussion on how we derived our one-in-four reasonable access assumption, refer to 

Section 1.6 of the RIA. For the distribution cost implications as well as the cost impacts of assuming reasonable 

access is greater than one-in-four pumps, refer to Section 4.2 of the RIA. 

RRRRR Computed as percent of stations with E85 (2,101/161,768 as of November 2009 or 1,733/161,768 as of 

August 2008) divided by 25% (one-in-four stations). 
 244

 There are a number of states promoting E85 usage by offering FFV/E85 awareness 

programs and/or retail pump incentives. A growing number of states are also offering 

infrastructure grants to help expand E85 availability. Currently, 10 Midwest states have adopted 

a progressive Energy Security and Climate Stewardship Platform.SSSSS The platform includes a 

Regional Biofuels Promotion Plan with a goal of making E85 available at one third of all stations 

by 2025. In addition, the Stimulus Bill recently increased the existing federal income tax credit 

from $30,000 or 30% of the total cost of improvements to $100,000 or 50% of the total cost of 

needed alternative fuel equipment and dispensing improvements.TTTTT 

 Given the growing number of subsidies, it is clear that E85 infrastructure will continue to 

expand in the future. However, like FFVs, we expect that E85 station growth will be somewhat 

proportional to the amount of ethanol realized under the RFS2 program. As such, we analyzed 

three different E85 growth scenarios for the final rule that could correspond to the three different 

RFS2 control cases. As an upper bound for our high-ethanol control case, we maintained the 

70% access assumption we applied for the NPRM. This translates to about 1:6 stations 

nationwide. 

 

 

SSSSS The following states have adopted the plan: Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Missouri, 

Ohio, South Dakota and Wisconsin. For more information, visit: 

http://www.midwesterngovernors.org/resolutions/Platform.pdf 

TTTTT http://frwebgate.access.gpo.gov/cgi-bin/getdoc.cgi?dbname=111_cong_bills&docid=f:h1enr.pdf 
 

 245

 As explained in the NPRM, one way to provide 70% of the nation with reasonable 1-in-4 

access would be to make it available in urban areas. For analysis purposes, we 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 potential ethanol surplus in 2022. 

For an illustration of the urban areas representing about 70% of the nation’s VMT, refer to 

Figure 1.7-8 

Figure 1.7-8. 

A Look at 70% E85 Access - Concentrating Pumps in Urban Areas 

. 

 For our other control cases we assumed access to E85 would be lower with the logic that 

retail stations (the majority of which are independently owned and operated and net around 
 246

$30,000 per year) would not invest in more E85 infrastructure than what was necessary to meet 

the RFS2 requirements. For our primary mid-ethanol control case we assumed reasonable access 

would grow from 4% in 2008 to 60% in 2022 and for our low-ethanol control case we assumed 

that access would only grow to 40% by 2022. As a simplifying assumption, we assumed a linear 

phase-in as shown below in Figure 1.7-9. As discussed in Section 1.6, we believe these E85 

growth scenarios are possible based on our assessment of distribution infrastructure capabilities. 

For more on the number of new E85 stations compared to the reference cases and the associated 

cost, refer to Section 4.2 of the RIA. 

Figure 1.7-9. 

Projected Growth in 1-in-4 Station Access to E85 

0%

10%

20%

30%

40%

50%

60%

70%

80%

20102011

20122013

20142015

20162017

2018201920202021

2022

Year

% of Country with 1-in-4 Access to E85

High-ETOH: 70% by 2022

Mid-ETOH: 60% by 2022

Low-ETOH: 40% by 2022

1.7.4 Required Increase in E85 Refueling Rates 

 As mentioned earlier, 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.UUUUU However, E85 usage was only around 12 million gallons in 2008.VVVVV This 

means that, on average, FFV owners were only tapping into about 0.2% of their vehicles’ 

E85/ethanol usage potential in 2008. Assuming that only 4% of the nation had reasonable onein-four access to E85 in 2008 (as discussed above), this equates to an estimated 5% E85 

refueling frequency for those FFVs that had reasonable access to the fuel. 

 

UUUUU Based on the assumption that FFV owners travel approximately 12,000 miles per year and today’s FFVs get 

about 18 miles per gallon on average under actual in-use driving conditions. 

VVVVV EIA Annual Energy Outlook 2009 - ARRA Update (Table 17). 
 

 247

 There are several reasons behind today’s low E85 refueling frequency. For starters, 

many FFV owners may not know they are driving a vehicle that is capable of handling E85. As 

mentioned earlier, more and more automakers are starting to produce FFVs by engine/product 

line, e.g., all 2008 Chevy Impalas are FFVs.WWWWW Consequently, consumers (especially brand 

loyal consumers) may inadvertently buy a flexible fuel vehicle without making a conscious 

decision to do so. And without effective consumer awareness programs in place, these FFV 

owners may never think to refuel on E85. In addition, FFV owners with reasonable access to 

E85 and knowledge of their vehicle’s E85 capabilities may still not choose to refuel on E85. 

They may feel inconvenienced by the increased refueling requirements. Based on its lower 

energy density, FFV owners will need to stop to refuel 22% more often when filling up on E85 

over E10 (and 24% more often when refueling on E85 over conventional gasoline).XXXXX In 

addition, some FFV owners may be deterred from refueling on E85 out of fear of reduced 

vehicle performance or just plain unfamiliarity with the new motor vehicle fuel. However, as we 

move into the future, we believe the biggest determinant will be price – whether E85 is priced 

competitively with gasoline based on its reduced energy density (discussed in more detail 

below). 

 To comply with the RFS2 program and consume 17.5 to 33.2 billion gallons of ethanol 

by 2022, not only will we need more FFVs and more E85 retailers, but we’ll also need to see a 

dramatic increase in the FFV E85 refueling frequency relative to today. Based on the FFV and 

retail assumptions presented in Sections 1.7.2 and 1.7.3, our analysis suggests that FFV owners 

with reasonable access to E85 would need to refuel on it 42-70% of the time, depending on the 

scenario (refer to Figure 1.7-10). This is a significant increase from today’s estimated 5% 

refueling frequency. 

 

WWWWW NEVC, “2008 Purchasing Guide for Flexible Fuel Vehicles.” Refers to all mass produced 3.5 and 3.9L 

Impalas. However, it is our understanding that consumers may still place special orders for non-FFVs. XXXXX Based on our assumption that denatured ethanol has an average lower heating value of 77,012 BTU/gal and 

conventional gasoline (E0) has average lower heating value of 115,000 BTU/gal. For analysis purposes, E10 was 

assumed to contain 10 vol% ethanol and 90 vol% gasoline. Based on EIA’s AEO assumptions, E85 was assumed to 

contain 74 vol% ethanol and 26 vol% gasoline on average. 
 248

Figure 1.7-10. 

Necessary FFV E85 Refueling Rates 

(Given 1-in-4 Access to Fuel) 

0%

10%

20%

30%

40%

50%

60%

70%

80%

2010201120122013

201420152016201720182019

202020212022

Year

% of Time FFVs Refuel on E85 (Given Access)

Low-ETOH: AEO 2009 FFVs, 40% Access to E85

Mid-ETOH: Committed FFVs, 60% Access to E85

High-ETOH: Mandated FFVs, 70% Access to E85

Max = 70%

Max = 42% 

Max = 58%

 As shown above, modeling an FFV mandate and E85 station access reaching 70% by 

2022, results in the lowest required FFV E85 refueling frequency (42%) for the high-ETOH 

control case. Similarly, the infrastructure assumptions modeled for the low-ETOH control case 

resulted in the highest required FFV E85 refueling frequency (70%). While this may seem 

counter-intuitive, the result is a product of the competing and variable modeling assumptions 

used. Had we elected to hold FFV production and E85 access constant for all three control cases 

(i.e., applied more aggressive infrastructure assumptions across the board), we would have come 

up with the lowest required FFV E85 refueling frequency for low-ETOH case and the highest 

requirements for the high-ETOH case. The computed required refueling frequency would also 

look more linear. However, this would mean large investments in FFV production and E85 

refueling infrastructure despite low demand for E85. We figured that, at costs of up to $100 per 

FFV (refer back to Section 1.7.2) and $23,000 per E85 station outlet (refer to Section 4.2.1.1.9), 

the nation would not build more FFV/E85 infrastructure than what was needed to meet the RFS2 

requirements Regardless, in order for any significant increase in FFV E85 refueling rates to 

occur, there will need to be an improvement in the current E85/gasoline price relationship. 

1.7.5 Market Pricing of E85 Versus Gasoline 
 

 249

 According to an online fuel price survey, E85 is currently priced almost 40 cents lower 

than regular grade conventional gasoline. YYYYY To increase our nation’s E85 refueling 

frequency to the levels described above, E85 needs to be priced competitively with (if not lower 

than) conventional gasoline based on its reduced energy content, increased time spent at the 

pump, and limited availability. On average, we estimate that E85 would need to be priced about 

25% lower than gasoline at retail in 2022 in order for it to make sense to consumers as outlined 

below. 

 First, E85 needs to be priced about 78% less than E10 based on its reduced energy 

density as shown below.ZZZZZ In 2022, based on $116/gallon crude oil projections, gasoline can 

be expected to be around $4.10/gallon at retail. That means E85 should be priced at about 

$3.20/gal. 

0.78

0.10 77,012 / 0.90 115,000 /

0.74 77,012 / 0.26 115,000 /

10

85 = ∗ + ∗

∗ + ∗ = BTU gal BTU galBTU gal BTU gal

E EnergyDensity

E EnergyDensity

 In addition, we need to take the value of FFV owners’ time into consideration because 

they could be spending 22% 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 based on an average of values identified in a review of economics literature and is 

consistent with 2005 Brownstone and Small VOT estimates.411 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, the greatest access we anticipate FFV 

owners will have to E85, is one-in-four stations offering the fuel. And that will likely only be in 

select areas of the country. 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.AAAAAA,412 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 58% of the time in 2022 (as is, under 

our primary mid-ETOH control case), it needs to be given an $0.11/gallon price advantage 

(1997$). Inflating the 1997 David Greene estimate to 2007 dollars, E85 would need to be priced 

an additional 14 cents per gallon lower than E10. 

 

YYYYY Based on average E85 and regular unleaded gasoline prices reported at http://www.fuelgaugereport.com/ on 

November 23, 2009. 

ZZZZZ Denatured ethanol was assumed to have a lower heating value of 77,012 BTU/gal based on the new denaturant 

requirements. 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 2009 report). 

AAAAAA 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) 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. 
 250

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%

$0.11/gal Price Advantage (1997$)

X

 Overall, our retail price analysis suggests that E85 would need to be priced at around $3 

per gallon ($3.20/gal - $0.04/gal - $0.14/gal) in order for it to be competitive with $4.10 gasoline 

in 2022. Essentially E85 would need to be priced at least 25% lower than gasoline at retail 

outlets in order for consumers to want to choose it regularly. 

 However, ultimately it comes down to what refiners are willing to pay for ethanol 

blended as E85. The more ethanol you try to blend as E85, the more devalued ethanol becomes 

as a gasoline blendstock. Changes to state and Federal excise tax structures could help promote 

ethanol blending as E85. But for the most past, as long as crude oil prices remain high (as 

projected by AEO 2009), it should look attractive to refiners as a blendstock. Based on our retail 

cost calculations (considering fuel taxes, mark-up at retail, and distribution), ethanol would have 

to be priced around $2/gal in order for it to be attractive to refiners for E85 blending in 2022. 

The current ethanol rack price is around $1.80/gallon. Therefore, while gasoline refiners and 

markets will always have a greater profit margin selling ethanol in low-level blends to consumers 

based on volume, they should be able to maintain a profit selling it as E85 based on energy 

content in the future. 

1.7.6 Consideration of >10% Ethanol Blends

 

 As explained in the preamble, on March 6, 2009, Growth Energy and 54 ethanol 

manufacturers submitted an application for a waiver of the prohibition of the introduction into 

commerce of certain fuels and fuel additives set forth in section 211(f) of the Act. This 

application seeks a waiver for ethanol-gasoline blends of up to 15 percent by volume ethanol. 
 

 251

On April 21, EPA issued a Federal Register notice announcing receipt of the Growth Energy 

waiver application and soliciting comment on all aspects of it.BBBBBB On May 20, 2009, EPA 

issued an additional Federal Register notice extending the public comment period by an 

additional 60 days.CCCCCC The comment period ended on July 20, 2009, and EPA is now 

evaluating the waiver application and considering the comments which were submitted. 

 

 Although EPA has yet to make a waiver decision, since its approval could have a 

significant impact our analyses that are based on the use of E85, as a sensitivity analysis, we 

have evaluated the impacts that E15 could have on ethanol consumption feasibility. More 

specifically, we have assessed the impacts of a partial waiver for newer technology vehicles 

consistent with the direction of EPA’s November 30, 2009 letter. 

 For our analysis, we assumed that E10 would need to continue to co-exist for legacy and 

non-road equipment based on consumer demand regardless of any waiver decision. As shown in 

Figures 1.7-5 through 1.7-7, the percentage of nonroad gasoline consumption was held constant 

at about 8% based on information obtained from ORNL’s 2009 Transportation Energy Data 

Book. For analysis purposes, we assumed E10 would be marketed as premium-grade gasoline 

(the universal fuel), E15 would be marketed as regular-grade gasoline (to maximize ethanol 

throughput) and, like today, midgrade would be blended from the two to make a 12.5 vol% blend 

(E12.5). In addition, we assumed that some E15-capable vehicles would continue to choose E10 

or E12.5 based on today’s premium and midgrade sales shown below in Table 1.7-6.DDDDDD 

Table 1.7-6. 

Mid-level Ethanol Blend Assumptions 

Grade of Gasoline

% of CG 

Sales*

Ethanol 

Content

Regular 86.5% 10.0%

Midgrade 5.0% 12.5%

Premium 8.5% 15.0%

*Petroleum Marketing Annual 2008, Table 45

 

 In the event of a partial waiver, it is unclear how long it would take for E15 to be fully 

deployed or whether it would ever be available nationwide. For analysis purposes, we made the 

simplifying assumption that E15 would be fully phased in and available at all retail stations 

nationwide by the time the nation hit the blend wall, or by around 2014 for our primary midETOH case shown below in Figure 1.7-12. 

 

 

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

CCCCCC Refer to 74 FR 23704 (May 20, 2009). DDDDDD According to EIA’s 2008 Petroleum Annual Outlook (Table 45) midgrade and premium comprise 13.5% of 

total gasoline sales. 
 252

Figure 1.7-12 

Max E15 Ethanol Consumption Compared to Mid-ETOH Control Case 

 

0

5

10

15

20

25

30

35

40

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

Year

Billion Gallons of Fuel (ETOH-Eq)

Non-Ethanol Biofuels

Cellulosic Ethanol

Imported Ethanol

Corn Ethanol

E15 Blendwall (Partial Waiver)

E10 Blendwall

 As modeled, a partial waiver for E15 could increase the ethanol consumption potential 

from conventional vehicles to about 19 billion gallons. Under our primary RFS2 control case 

(shown in Figure 1.7-12), E15 could postpone the blend wall by up to five years, or to 2019. 

Although E15 would fall short of meeting the RFS2 requirements under this scenario, it could 

provide interim relief while the country ramps up non-ethanol cellulosic biofuel production 

and/or expands E85/FFV infrastructure. 

 Under our low-ETOH case, a partial waiver for E15 could eliminate the need for 

additional FFV/E85 infrastructure all together. Similarly, for our high-ETOH case, E15 could 

postpone the blend wall by about 3 years from 2013 to 2016. These scenarios are shown in 

Figures 1.7-13 and 1.7-14. 
 

 253

Figure 1.7-13 

Max E15 Ethanol Consumption Compared to Low-ETOH Control Case 

0

5

10

15

20

25

30

35

40

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

Year

Billion Gallons of Fuel (ETOH-Eq)

Non-Ethanol Biofuels

Cellulosic Ethanol

Imported Ethanol

Corn Ethanol

E15 Blendwall (Partial Waiver)

E10 Blendwall
 254

Figure 1.7-14 

Max E15 Ethanol Consumption Compared to High-ETOH Control Case 

0

5

10

15

20

25

30

35

40

2010

2011

2012

2013

2014

2015

2016

2017

20182019

2020

2021

2022

Year

Billion Gallons of Fuel (ETOH-Eq)

Non-Ethanol Biofuels

Cellulosic Ethanol

Imported Ethanol

Corn Ethanol

E15 Blendwall (Partial Waiver)

E10 Blendwall

1.8 Inputs Used for the Air Quality Modeling 

 The information presented in Section 1.5 reflects our most current assessment of the 

renewable fuels industry and our projections through 2022 to meet the RFS2 standards. In 

addition, Section 1.7 reflects our most current assessment on how the renewable fuel might be 

consumed and the associated challenges, e.g., E10 blendwall, etc. The information presented in 

these sections serves as the basis for various final rulemaking impact analyses, including cost. 

However, the air quality modeling and some of the fuel distribution analyses had to begin prior 

to this assessment being completed. As a result, they relied on industry assessments carried out 

for the NPRM. Section 1.8 presents the relevant NPRM assessment which served as the basis for 

these analyses. 

1.8.1 Ethanol Inputs 

1.8.1.1 Corn Ethanol Inputs 

1.8.1.1.1 Existing Corn/Starch Ethanol Production 

 At the time of our May 2008 corn ethanol plant assessment used for air quality modeling, 

there were 158 fuel ethanol plants operating in the U.S. with a combined production capacity of 
 

 255

9.2 billion gallons per year.EEEEEE413414 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 1.8-1. 

 

Table 1.8.1 

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).FFFFFF 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 

 

EEEEEE 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. 

FFFFFF Facilities were assumed to burn natural gas if the plant boiler fuel was unspecified or unavailable on the public 

domain. 
 256

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 1.8-2. 

 

Table 1.8.2. 

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 1,720 18.8% 18 11.4% 8

Coal, Biomass 50 0.5% 1 0.6% 0

Natural Gasb 7,141 77.9% 134 84.8% 15

Natural Gas, Biomassc 113 1.2% 3 1.9% 1

Natural Gas, Landfill Syngas, Wood 100 1.1% 1 0.6% 0

Natural Gas, Syrup 46 0.5% 1 0.6% 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 1.8.-3 below. 

Table 1.8-3. 

May 2008 Corn/Starch Ethanol Production Capacity by PADD 

PADD

Capacity

MGY

% of

Capacity

No. of

Plants

% of

Plants

PADD 1 50 0.5% 2 1.3%

PADD 2 8,619 94.0% 140 88.6%

PADD 3 170 1.9% 3 1.9%

PADD 4 160 1.7% 7 4.4%

PADD 5 171 1.9% 6 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 1.8.1 and Table 1.8.4 below. 
 

 257

Figure 1.8.1. 

May 2008 Corn/Starch Ethanol Plant Locations
 258

Table 1.8-4 

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%
 

 259

1.8.1.1.2 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.GGGGGG These projects were at various phases of construction from conducting land 

stabilization work, to constructing tanks and installing ancillary equipment, to completing startup activities. 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 1.8-5. 

Table 1.8-5. 

Projected RFS2 Ethanol Production Capacity by Feedstock 

(Based on May 2008 Ethanol Industry Characterization) 

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. 

New Plants/Exp. Total RFS2 Est.

Plant Feedstock

(Primary Listed First)

 

GGGGGG 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. 
 260

 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.HHHHHH 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.IIIIII 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 1.8-6. 

Table 1.8-6. 

Projected Near-Term Corn/Starch Ethanol Production Capacity by Energy Source 

(Based on May 2008 Ethanol Industry Characterization) 

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.

New Plants/Exp. Total RFS2 Est.

Plant Energy Source

(Primary Listed First)

 The information presented in Table 1.8-6 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. 

 

HHHHHH We anticipate that all the coal-fired corn ethanol plants would be grandfathered under the RFS2 program. 

For more on our grandfathering assessment, refer to Section 1.5.1.4. 

IIIIII 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 since terminated. Accordingly, 

this plant was not included in our November 2009 RFS2 projections. 
 

 261

 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 1.8-7. 
 262

Table 1.8-7. 

Projected RFS2 Corn/Starch Ethanol Production Capacity by PADD 

(Based on May 2008 Ethanol Industry Characterization) 

Capacity

MGY

No. of

Plants

Capacity

MGY

No. of

Plants

PADD 1 214 2 264 4

PADD 2 5,002 47 13,620 187

PADD 3 215 2 385 5

PADD 4 70 2 230 9

PADD 5 328 5 499 11

Total 5,829 58 14,998 216

New Plants/Exp.

PADD

Total RFS2 Est.

 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 1.8-2 and a summary of the ethanol production capacity by state 

is presented in Table 1.8-8. 
 

 263

Figure 1.8-2 

Projected RFS2 Corn/Starch Ethanol Plant Locations 

(Based on May 2008 Ethanol Industry Characterization) 
 264

Table 1.8-8. 

Projected RFS2 Corn/Starch Ethanol Production Capacity by State 

(Based on May 2008 Ethanol Industry Characterization) 

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

New Plants/Exp. Total RFS2 Est.

State

1.8.1.2 Projected Ethanol Import Locations 

 A discussion of the sugarcane ethanol imports that might come directly from Brazil 

versus through the CBI countries is contained in Section 1.5.2. However, to provide upstream 

inputs for AQ modeling and distribution purposes, we needed to estimate imports based on their 

country of origin and projected U.S. destination, i.e., port location. 
 

 265

1.8.1.2.1 Origin of Projected Imports 

 

 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 1.8-9 contains 2005-2007 

data from the ITC on ethanol imports from CBI countries.415 Table 1.8-10 contains January – 

March 2008 data from the ITC on ethanol imports from CBI countries.416

Table 1.8-9. 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 1.8-10. 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 1.8-11 
 266

Table 1.8-11. 

Projected Future Breakdown of 

Ethanol Imports from CBI Countries

 % of Total Ethanol Imports from 

CBI Countries 

Costa Rica 20% 

El Salvador 20% 

Jamaica 30% 

Trinidad and Tobago 15% 

Virgin Islands 15% 

1.8.1.2.2 Destination of Projected Imports 

 As explained above, to determine where imported ethanol might enter the United States, 

we started by looking at historical ethanol import data and made assumptions as to which 

countries would likely contribute to the CBI ethanol volumes and to what extent. 

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.417 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 1.8-12. 

Table 1.8-12 

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 

presumably, these ports cities already have existing gasoline storage tanks that could be 
 

 267

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 1.8-3 below).JJJJJJ 

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 1.8.1.1 and 1.8.1.3, respectively). 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 1.8-3. 

Figure 1.8-3. 

Projected RFS2 Ethanol Import Locations and Volumes (Million Gallons)KKKKKK

 

JJJJJJ 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. 

KKKKKK 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. 
 268

1.8.1.3 Cellulosic Ethanol Plant Siting 

As explained in Section 1.5.3, cellulosic biofuel 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 biofuel production, including: 

agricultural residues, forestry biomass, the certain renewable portions of municipal solid waste 

and construction and demolition waste and energy crops. These feedstocks are currently 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. 

 

1.8.1.3.1 Summary of Plant Siting Results 

As long leadtimes were required for our air quality modeling, it was necessary to use 

available data at the time on the likely cellulosic feedstocks and projected locations of cellulosic 

facilities for production of 16 billion gallons cellulosic biofuel by 2022. Our original plant siting 

analysis for cellulosic ethanol facilities used the most current version of outputs from FASOM at 

the time, which was from April 2008. Therefore, the version used for the majority of other 

analyses in the rest of this package is different from the results presented below. 

Our cellulosic ethanol plant siting analysis assumed that the following cellulosic 

feedstock and volumes would be used, as shown in Table 1.8-13. 

Table 1.8-13. 

Cellulosic Feedstocks Assumed to Meet EISA in 2022 

(NPRM version for AQ Modeling) 

Feedstock Volume (Ethanolequivalent Bgal) 

Agricultural Residues 9.1 

Corn Stover 7.8 

Sugarcane 

BagasseLLLLLL

1.2 

Sweet Sorghum Pulp 0.1 

Forestry Biomass 3.8 

Urban Waste 2.2 

Dedicated Energy Crops 

(Switchgrass) 

0.9 

Total 16.0 

 

 

LLLLLL 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. 
 

 269

 Future cellulosic biofuel plant siting was based on the types of feedstocks that would be 

most economical as shown in Table 1.8-13, 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).418 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. Refer 

to Section 1.8.1.3.2 below for more detailed information. 

 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 1.8-14 

shows the volume of cellulosic facilities by feedstock by state projected for 2022. Table 1.8-15 

lists the 180 cellulosic ethanol facilities that we project could potentially be used to produce 16 

Bgal of cellulosic biofuel by 2022. The total volumes given in Table 1.8-14 match the total 

volumes given in Table 1.8-15 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. See Figure 1.8-4 for a visual representation of the locations of these facilities. 

 
 270

Table 1.8-14. 

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 

 
 

 271

Table 1.8-15. 

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 

 Morgan Illinois 67 

 Ogle Illinois 95 

 Richland Illinois 81 

 Shelby Illinois 68 

 Tazewell Illinois 107 

 Washington Illinois 85 

 Benton Indiana 92 

 Clinton Indiana 80 

 Daviess Indiana 93 

 De Kalb Indiana 91 

 Fulton Indiana 74 

 Jasper Indiana 82 
 272

 Jennings Indiana 94 

 Madison Indiana 78 

 Morgan Indiana 100 

 Parke Indiana 92 

 Union Indiana 82 

 Vanderburgh Indiana 74 

 Wells Indiana 77 

Benton Iowa 69 

Buchanan Iowa 83 

Buena Vista Iowa 84 

Cerro Gordo Iowa 79 

Chickasaw Iowa 82 

Des Moines Iowa 87 

Dubuque Iowa 70 

Franklin Iowa 80 

Grundy Iowa 83 

Guthrie Iowa 85 

Ida Iowa 88 

Mahaska Iowa 80 

Muscatine Iowa 83 

O Brien Iowa 80 

Page Iowa 81 

Palo Alto Iowa 75 

Pottawattamie Iowa 84 

Sioux Iowa 72 

Story Iowa 89 

Union Iowa 76 

Webster Iowa 86 

Logan Kansas 75 

Nemaha Kansas 78 

Sedgwick Kansas 71 

Stevens Kansas 87 

Webster Kentucky 70 

Bienville Louisiana 115 

E. Baton Rouge Louisiana 106 

E. Carroll Louisiana 103 

Jeff Davis Louisiana 87 

Allen Louisiana 50 

Avoyelles Louisiana 100 

Iberville Louisiana 90 

La Fourche Louisiana 50 

Lafayette Louisiana 100 

Pt. Coupe Louisiana 100 

St Landry Louisiana 100 

Penobscot Maine 100 

Piscataquis Maine 91 

Calhoun Michigan 109 

Ionia Michigan 117 

Tuscola Michigan 105 

Van Buren Michigan 89 
 

 273

Wayne Michigan 85 

Chippewa Minnesota 92 

Dakota Minnesota 114 

Dodge Minnesota 86 

Faribault Minnesota 88 

Lyon Minnesota 84 

Martin Minnesota 95 

Rock Minnesota 73 

Sibley Minnesota 102 

Stearns Minnesota 68 

Stevens Minnesota 76 

Forrest Mississippi 107 

Grenada Mississippi 107 

Audrain Missouri 86 

Chariton Missouri 74 

Clark Missouri 89 

Gentry Missouri 95 

New Madrid Missouri 84 

Ray Missouri 100 

St. Louis Missouri 125 

Sanders Montana 92 

 Boone Nebraska 98 

 Custer Nebraska 84 

 Harlan Nebraska 78 

 Hitchcock Nebraska 83 

 Holt Nebraska 91 

 Lancaster Nebraska 74 

 Lincoln Nebraska 81 

 Nuckolls Nebraska 76 

 Saunders Nebraska 100 

 Wayne Nebraska 96 

 York Nebraska 94 

Clark Nevada 17 

Carroll New Hampshire 136 

Carroll New Hampshire 35 

West Chester New York 72 

Cumberland North Carolina 110 

Forsyth North Carolina 104 

Martin North Carolina 102 

Auglaize Ohio 80 

Clinton Ohio 100 

Franklin Ohio 77 

Logan Ohio 75 

Portage Ohio 98 

Richland Ohio 83 

Wood Ohio 85 

Craig Oklahoma 130 

Grady Oklahoma 108 

Hughes Oklahoma 91 

Kingfisher Oklahoma 110 
 274

Lincoln Oklahoma 120 

Muskogee Oklahoma 118 

Osage Oklahoma 116 

Lane Oregon 126 

Yamhill Oregon 118 

Montgomery Pennsylvania 42 

Berkeley South Carolina 105 

Spartanburg South Carolina 108 

 Day South Dakota 85 

 Edmunds South Dakota 80 

 Kingsbury South Dakota 98 

 Lake South Dakota 83 

 Turner South Dakota 89 

Monroe Tennessee 97 

Angelina Texas 114 

Bexar Texas 16 

Cameron Texas 100 

Dallas Texas 52 

Harris Texas 80 

Hidalgo Texas 100 

Travis Texas 14 

Willacy Texas 100 

Halifax Virginia 98 

Prince George Virginia 99 

Chelan Washington 78 

Thurston Washington 97 

Harrison West Virginia 149 

 Calumet Wisconsin 91 

 Dane Wisconsin 76 

 Dunn Wisconsin 63 

 Eau Claire Wisconsin 65 

 Grant Wisconsin 68 

 Jefferson Wisconsin 94 

 Marquette Wisconsin 65 

 Wood Wisconsin 59 

 Total 16039 
 

 275

Figure 1.8-4. Projected Cellulosic Facilities

1.8.1.3.2 Assumptions and Details of Plant Siting Analysis 

An important assumption in our siting analysis 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).MMMMMM 

 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. 

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 

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 

 

MMMMMM 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. 

Forest Residue Plant

Ag. Residue Plant 

Switchgrass Plant

MSW Plant

Bagasse Plant
 276

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. 

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 placed 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. 

It is important to note, 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. 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.419 

For this analysis, we estimated MSW and C&D wood waste by state (similar to the 

analysis described in Section 1.1.2.4) and 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. 

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. 

 We did not consider small cities that might be able to justify a cellulosic ethanol plant 

because some other source of biomass is also available that, when 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 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 
 

 277

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 1.8-16. 

Table 1.8-16. 

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 1.8-17. 

The total contribution from dedicated cellulosic MSW and C&D wood waste is approximately 

640 million gallons. 
 278

Table 1.8-17. 

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. Therefore, we estimated that urban waste could help contribute to the 

production of approximately 2.2 billion gallons of ethanol.NNNNNN

 The results from the April 2008 version of the agricultural modeling (FASOM) suggested 

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).OOOOOO Smaller contributions were 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 the proposal, FASOM was able to model 

agricultural residues but not forestry biomass as potential feedstocks. As a result, we had relied 

on USDA-Forest Service (FS) for information on the forestry sector for our plant siting analysis. 

 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 1.8-18 for a summary of the 

 

NNNNNN Assuming approximately 90 gal/dry ton ethanol conversion yield; Note that this is slightly different from the 

2.3 billion gallons of ethanol assumed in other analyses in this package. 

OOOOOO Assuming 94 gal/dry ton ethanol conversion yield for corn stover in 2022 
 

 279

states producing corn stover, and their projected volume contribution to meeting the EISA 

cellulosic requirement by 2022. 
 280

Table 1.8-18. 

Projected Ethanol Produced to Meet EISA in 2022 from Corn Stover (NPRM version for AQ Modeling)146

Total 

Harvested 

Acres

Total Residue 

Yield 

Total Residue 

Available 

Sustainably 

Removable Residue 

Yield 

Removable 

Sustainably 

Residue Available Residue Used

Residue 

Percent 

Used

Ethanol 

Produced

Wisconsin 3,001,454 4.74 14 2.33 7 5 35% 432South Dakota 4,268,425 4.01 17 1.41 6 4 23% 350Ohio 3,712,612 4.91 18 1.89 7 5 27% 453Nebraska 10,135,162 5.88 60 1.28 13 9 15% 840Missouri 2,732,875 4.73 13 2.93 8 5 39% 434Minnesota 7,509,658 5.37 40 1.60 12 8 20% 750Michigan 2,238,321 4.30 10 1.79 4 3 31% 246Kentucky 1,473,023 5.08 7 2.04 3 1 13% 63Kansas 3,026,615 5.33 16 1.65 5 3 19% 261Iowa 14,482,313 5.47 79 1.59 23 17 21% 1557Indiana 6,209,463 5.58 35 2.09 13 10 29% 922Illinois 12,994,100 5.43 71 1.62 21 15 21% 1444Total 71,784,020 n/a 380 n/a 122 82 22% 7752State (in 2022) (tons/acre) (Million tons) (tons/acre) (Million tons) (Million tons) (Million gallons)

146 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 April 2008 version of the agricultural modeling, actual yields will vary greatly depending on specific soil type, slope, etc. The values above are calculated using the FASOM data outputs from April 2008 and thus are different from those found in other sections of this package which use more updated runs from 2009. 
 

 281

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 the RIA 

for more discussion on sugarcane ethanol produced in the U.S. If all the sugarcane acres 

harvested in the U.S. in 2007 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 1.8-19. FASOM, however, predicted 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 1.8-19. 

Projected Ethanol Produced to Meet EISA in 2022 from Sugarcane Bagasse 

State

Total Harvested 

Acres (in 2007)

Total Bagasse 

Yield 

(tons/acre)

Residue Used 

(Million tons)

Ethanol 

Produced 

(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).420

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. 

 For forestry biomass, we utilized data provided by the USDA-FS (biomass supply curves 

for various sources i.e., logging residues, other removal residues, thinnings from timberland, 

etc.). This information suggested that a large portion of forest material could be available for 

producing biofuels (excluding forest biomass material contained in national forests as required 
 282

under the Act). See Section 1.1.2.3 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. 

The April 2008 version of the FASOM results projected 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. 

1.8.1.4 Ethanol Usage Assumptions 

 To understand the impacts of increased ethanol use on air quality, we estimated where the 

ethanol might be used in the future under the RFS2 program. For this analysis, discussed in 

more detail in Chapter 3 of the RIA, we measured the impacts of 34.1 billion gallons of ethanol 

use in 2022, the total volume of ethanol assumed to be produced and consumed in the NPRM. 

For this analysis, we also applied NPRM assumptions with respect to FFV and E85 availability, 

described in more detail below. 

 With respect to FFVs, we assumed that the Detroit 3 would follow through with their 

50% by 2012 FFV commitment and the non-domestic automakers would follow suit and produce 

25% FFVs by 2017. This corresponded to the primary Optimistic FFV Production Scenario 

outlined in the NPRM. The annual FFV sales by vehicle type are summarized in Table 1.8-20 

below. For analysis purposes, we made the simplifying assumption that all FFVs would be 

distributed homogeneously and total vehicle sales would remain constant around 16 million units 

per year. This differs from vehicle assumptions made for the final rule, outlined in Section 

1.7.1.2. 
 

 283

Table 1.8-20. 

Optimistic FFV Production Scenario – FFV Production Assumptions 

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

Year

GM, Chrysler & Ford Non-Domestic Automakers

 Based on these FFV production assumptions and forecasted vehicle phase-out, VMT, and 

fuel economy estimates provided by an earlier version of EPA’s MOVES Model, we calculated 

that the maximum percentage of fuel (gasoline/ethanol mix) that could feasibly be consumed by 

FFVs in 2022 would be about 30%. The resulting gasoline energy consumption by vehicle type 

under the Optimistic FFV Production Scenario is shown below in Figure 1.8-5. For analysis 

purposes, 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.cdxxi 
 284

Figure 1.8-5. 

Optimistic FFV Production Scenario - Gasoline Consumption by Vehicle Type 

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

% of Gasoline Consumption

FFVs

Tier 2 Vehicles (Non-FFVs)

Pre-Tier 2 Vehicles

Nonroad, HDGVs & Motorcycles

 

 For the primary ethanol usage scenario analyzed in the NPRM and used for the AQ 

modeling work, we assumed practical, yet aggressive growth in E85 access. We considered the 

possibility that 70% of the nation could have reasonable one-in-four-station access to E85 by 

2022. This is roughly equivalent to all urban areas in the United States offering E85. For this 

analysis, we have defined “urban” areas as: 
 

 285

• 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 1.8-6. 

Figure 1.8-6. 

A Look at 70% E85 Access - Concentrating Pumps in Urban Areas 
 286

 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. For more on fuel distribution logistics and 

costs, refer to Sections 1.6 and 4.2 of the RIA. 

 Assuming that reasonable E85 access grows linearly 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 analyzed for the NPRM. Under a very aggressive FFV 

production scenario, we estimate that E0 could theoretically remain in existence until 2016 as 

shown below in Figure 1.8-7. However, we anticipate that E10 will likely replace E0 sooner 

based on current market trends. 

Figure 1.8-7. 

Assumed Phase-Out of E0 and Phase-In of E10 & E85 

0%

20%

40%

60%

80%

100%

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

Year

Nationwide Access to Fuel

E0

E10

E85
 

 287

 To comply with the proposed RFS2 program and consume 34.1 billion gallons of ethanol 

by 2022, not only would we need more FFVs and more E85 retailers, we’ll need to see a 

significant increase in FFV E85 refueling. 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 refueling frequency. 

 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.cdxxii 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) rulecdxxiii 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).cdxxiv 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 on this general methodology, refer to Section 1.7.1.2.5 of the 

RIA. 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 terminalto-retail transportation costs (assumed to be $0.03) to arrive at the estimated retail value of E85, 

and ultimately, the retail value of ethanol.147 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 of the proposal) 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 1.8-8. 

 

147 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. 
 288

Figure 1.8-8 

Projected E85 Availability in 2022 Under RFS2 

 

1.8.2 Biodiesel & Renewable Diesel Inputs 

1.8.2.1 Upstream Production Inputs 

 In order to generate county-level emissions inputs we needed projected locations of 

biodiesel production facilities. This task was complicated by the fact that the current aggregate 

industry production capacity is significantly larger than the volume of biodiesel projected to be 

consumed in our primary control case, a fact which suggests the industry may downsize in the 

long term. 

 We developed a method to determine where biodiesel producers were most likely to 

remain based on state incentives to biodiesel producers and for biodiesel sales or use. Data on 

state incentives was taken from an online database maintained by the Department of Energy 

Office of Energy Efficiency and Renewable Energy.cdxxv Two other factors we considered were 

the BQ-9000 status of individual plants and their ability to process multiple feedstock types, as 

listed by the National Biodiesel Board. cdxxvi Based the volume of the primary control case, 

assuming a capacity utilization factor of approximately 80%, a list of plants for the 2022 
 

 289

scenarios was generated choosing first from those plants with most favorable status of the four 

factors and working downward. Efforts were made to choose a mix of large and small plants, 

and to place plants in all regions, with the intention being to form a representative list. 

 From the 2022 plant list, emission quantities were generated for each county based on 

each plant’s biodiesel production rate. Spreadsheets showing lists of the representative plants 

and their emission factors as input in the inventory and air quality models can be found in the 

docket. 

1.8.2.2 Downstream Consumption Inputs 

 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 1.8-21 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.cdxxvii State-level forecasts were not available for transportation 

fuel use, thus the reliance on historical data for this estimate. 
 290

Table 1.8-21. 

State biodiesel incentives as of summer 2008 and potential volumes based on 2005 

data.cdxxviii

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

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 

some conditions

491 24.5

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 

bus requirement

1,234 24.7

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 

some conditions

738 36.9

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 

some conditions

1,230 24.6

Total biodiesel 468.7

State Incentive or mandate

 Table 1.8-22 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. 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. 
 

 291

Table 1.8-22. 

Potential biodiesel use in heating oil based on 2005 data.cdxxix

Heating oil 2% biodiesel Volume Used

(million gal/yr) (million gal/yr) (million gal/yr)

U.S. 5,565,489 111.3

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

Area

 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. For more on biodiesel-related distribution 

issues and costs, refer to Section 4.2.2.2.

 

1

 See the following documents: Iowa State University Center for Agricultural Research and Development, 

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version is available from July 2007); USDA Agricultural Projections to 2018, Report OCE-2009-1, February 

2009 (also USDA Agricultural Projections to 2016, Report OCE-2007-1, February 2007 for details on ethanol 

conversion yield); 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

 USDA/NASS. “Quick Stats: U.S. and All States Data- Corn field” 

3

 USDA/NASS. “Corn: Yield by year, US,” 

http://www.nass.usda.gov/Charts_and_Maps/Field_Crops/cornyld.asp, November 10, 2009. 
292

 4

 USDA Agricultural Projections to 2018, Report OCE-2009-1, February 2009 

5

 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.

6

 USDA Agricultural Projections to 2016, Report OCE-2007-1, February 2007, page 22. 

7

 Shapouri, H., Gallagher, P., “USDA’s 2002 Ethanol Cost-of-Production Survey,” July 2005, p.11. 

8

 F.O. Licht, “World Ethanol Markets: The Outlook to 2015,” 2006, page 45. 

9

 Renewable Fuels Association. “2008 World Fuel Ethanol Production”. 

http://www.ethanolrfa.org/industry/statistics/ 

10 “Sugarcane Industry in Brazil: Ethanol, Sugar, Bioelectricity” brochure from UNICA 

11 UNICA. “Sugarcane Production – Brazil” Spreadsheet available 

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12 Agra FNP. “Sugar and Ethanol in Brazil: A Study of the Brazilian Sugarcane, Sugar and Ethanol Industries,” 

2007. 

13 “Sugarcane Industry in Brazil: Ethanol, Sugar, Bioelectricity” brochure from UNICA 

14 Scaramucci, Jose & Cunha, Marcelo, “Bioethanol as Basis for Regional Development in Brazil: An InputOutput Model with Mixed Technologies.” 

15 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. 

16 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. 

17 USDA, “The Economic Feasibility of Ethanol Production from Sugar in the United States,” July 2006. 

18 Kline, K. et. al., “Biofuel Feedstock Assessment for Selected Countries,” Oak Ridge National Laboratory, 

February 2008. 

19 USDA, “The Economic Feasibility of Ethanol Production from Sugar in the United States,” July 2006. 

20 Personal communication with Nathalie Hoffman, Managing Member of California Renewable Energies, 

LLC, August 27, 2008. 

21 Christiansen, Ryan, “Analysis: Sugarcane Ethanol Has 95% Less Emissions,” Ethanol Producer Magazine, 

March 2009. 

22 Voegele, Erin, “Sugarcane Economics,” Ethanol Producer Magazine, March 2009. 

23 Voegele, Erin, “Sugarcane plays role in development of green polyethylene, Sugarcorn,” Ethanol Producer 

Magazine, March 2009. 

24 Saballos, Ana. in W. Vermerris (ed.), (2008) “Development and Utilization of Sorghum as a Bioenergy 

Crop,” Genetic Improvement of Bioenergy Crops DOI: 10.1007/978-0-387-70805-8_8 

25 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, 

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American Society of Agronomy, Madison, WI 53711 USA, Published in Agron. J. 96:1-17 (2004) 

26 Predicting Soil Erosion by Water. A Guide to Conservation Planning with the Revised Universal Soil Loss 

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27 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 Windinduced Soil Erosion Methodology, Biomass and Bioenergy 22 (2002) 349 – 363, Published by Elsevier 

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28 Linda Mann, Virginia Tolbert, Janet Cushman, Environmental Sciences Division, Oak Ridge National 

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ISSN 0167-8809 Elsevier Science, Amsterdam. June 2002. 

29 http://www.nrcs.usda.gov/technical/Standards/nhcp.html 
293

 30 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 Windinduced Soil Erosion Methodology, Biomass and Bioenergy 22 (2002) 349 – 363, Published by Elsevier 

Science Ltd. 

31 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,

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32 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 

33 Graham, R.L. et. al., “Current and Potential U.S. Corn Stover Supplies,” American Society of Agronomy 99:1-

11, 2007.

34 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.

35 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.

36 Milbrandt, A., “Geographic Perspective on the Current Biomass Resource Availability in the United States,” 

NREL Report No. TP-560-39181, 2005. 

37 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. 38 Walsh, Marie, “U.S. Cellulosic Biomass Feedstock Supplies and Distribution,” Unpublished Manuscript, 

January 10, 2008.

39 Graham, R.L. et. al., “Current and Potential U.S. Corn Stover Supplies,” American Society of Agronomy 99:1-

11, 2007. 

40 Wright, Lynn. (July 2007) “Historical Perspective on How and Why Switchgrass was Selected as a “Model” 

High-Potential Energy Crop,” Oak Ridge National Laboratory. 

41 U.S Department of Energy. “Breaking the Biological Barriers to Cellulosic Ethanol: A Joint Research 

Agenda.” (2006). 

42 Kumar, A., & Sokhansanj, S., “Switchgrass (Panicum vigratum, L.) delivery to a biorefinergy using 

integrated biomass supply analysis and logistics (IBSAL) model.” Bioresource Technology, (2006). 

43 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. 

44 Kumar, op. cit. 45 McLaughlin, op. cit.

46 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. 

47 Pyter, R., Voigt, T., Heaton, H., Dohleman, F., & Long, S. Growing giant miscanthus in Illinois. University 

of Illinois. (2006). 

48 Ibid.

49 Ibid.

50 Lewandowski, op. cit. 51 Pyter, op. cit.

52 Pyter, op. cit.

53 Lewandowski, op. cit. 

54 Pyter, op. cit. 

55 U.S Department of Energy. “Breaking the Biological Barriers to Cellulosic Ethanol: A Joint Research 

Agenda,” 2006. 

56 Saballos, op. cit. 57 McCutchen, Bill et. al. High-Tonnage Dedicated Energy Crops: The Potential of Sorghum and Energy Cane. 
294

 58 U.S Department of Energy. “Breaking the Biological Barriers to Cellulosic Ethanol: A Joint Research 

Agenda,” 2006. 

59 Ibid. 

60 Campbell, J.E. at al., ”The Global Potential of Bioenergy on aAbandoned Agriculture Lands,” Environ. Sci. 

Technology, 2008. 

61 Adapted from additional information received from J. Elliot Campbell. “The Global Potential of Bioenergy 

on Abandoned Agriculture Lands,” Environ. Sci. Technology, 2008. 

62 USDA, Farm Services Agency, “Conservation Reserve Program Summary and Enrollment Statistics,” FY 

2008. 

63 USDA, Farm Services Agency, “Conservation Reserve Program Statistics: Monthly Summary November 

2009.” 

64 Ibid. 

65 Ibid.

66 Walsh, M.E. (2007) Sungrant Bioweb. Forest Resources. 

http://bioweb.sungrant.org/Technical/Biomass+Resources/Forest+Resources/Default.htm 

67 Ibid. 

68 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. 

69 Ibid. 

70 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. 

71 Puttock, G.D. (1995). Estimating cost for integrated harvesting and related forest management activities. 

Biomass and Bioenergy 8(2), 73-79. 

72 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. 

73 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. 

74 Ibid. 

75 Timko, B., 2003. USDA, Forest Service, personal communication as noted in the “Billion-ton Study” by 

Perlack, R.D., et. al. 

76 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.

77 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. 

78 Kozlowski, T.T., 1999. Soil Compaction and Growth of Woody Plants. Scandinavian Journal of Forest 

Research, Volume 14, Number 6. Taylor and Francis Ltd. 

79 Rummer, B.; Len, D.; and O’Brien, O. (2004). Forest Residues Bundling Project-New Technology for 

Residue Removal. USDA Forest Service, Southern Research Station 

80 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. 

81 Aden, Andy. December 10, 2009. “Feedstock Considerations and Impacts on Biorefining.” National 

Renewable Energy Laboratory 

82 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. 
295

 83 Walsh, Marie E., U.S. Cellulosic Biomass Feedstock Supplies and Distribution; January 10, 2008. 84 Data provided by e-mail by Perlack, Robert D., May 2008. 

85 EPA. “Municipal Solid Waste Generation, Recycling, and Disposal in the United States: Facts and Figures 

for 2008,” 

86 USEPA. “Municipal Solid Waste in the United States,” 2007; See Tables 1-3. 

87 Biocycle, “The State of Garbage in America,” Vol. 49, No. 12, December 2008, page 22. 

88 Midwest Assistance Program, Inc. “The 2006-2007 Missouri Municipal Solid Waste Composition Study,” 

October, 2007. 

89 R. W. Beck, “Georgia Statewide Characterization Study,” June 2005. 

90 Engineering Solutions and Design, Inc., “State of Ohio Waste Characterization Study,” April 2004. 

91 NYC Department of Sanitation, “2004-2005 NYC Waste Characterization Study.” 

92 R.W. Beck, “Statewide MSW Composition Study: A Study of Discards in the State of Minnesota,” 2000. 

93 R.W. Beck, “Statewide Waste Composition Study: Pennsylvania State-wide Waste Composition,” April 

2003. 

94 DSM Environmental Services, Inc, “Vermont Waste Composition Study,” June 2002. 

95 R.W. Beck, “1992 Washington State Waste Characterization Study.” 

96 R.W. Beck, “Wisconsin Statewide Waste Characterization Study,” May 2003. 

97 Department of Environmental Quality, “Oregon 2002 Waste Composition Study,” 2002. 

98 Williams, Robert and California Biomass Collaborative, “Biofuels from Municipal Wastes- Background 

Discussion Paper,” March 28, 2007. 

99 Ibid.

100 Walsh, Marie, “U.S. Cellulosic Biomass Feedstock Supplies and Distribution,” Unpublished Manuscript, 

January 10, 2008. 

101 Falk, Robert and McKeever, David. 2004. “Recovering Wood for Reuse and Recycling A United States 

Perspective” USDA Forest Service 

102 Fricke, K. (1989). “Technology and undesirable components on compost of separately collected organic 

wastes” Agriculture, Ecosystem, Environment. 103 McKeever, David. (December 1999). “How Woody Residues Are Recycled in the United States" BioCycle 104 Center for Sustainable Systems “U.S. Food System Fact Sheets,”2008 

105 USEPA, Construction and Demolition (C&D) Materials. 

http://www.epa.gov/osw/nonhaz/industrial/cd/basic.htm Accessed August 10, 2008. 

106 Fehrs, J., “Secondary Mill Residues and Urban Wood Waste Quantities in the United States-Final Report,” 

Northeast Regional Biomass Program Washington, D.C., December 1999. 

107 Wiltsee, G., “Urban Wood Waste Resource Assessment,” Appel Consultant, Inc. Valencia, CA. November, 

1998. 

108 Seabra, Joaquim. (July 2009). “Comparison of options for advanced ethanol production in Brazilian 

sugarcane biorefineries” draft manuscript, anticipated to be available in Biomass and Bioenergy soon. 

109 Kline, K. et. al. Biofuel Feedstock Assessment for Selected Countries. Oak Ridge National Laboratory. 

February 2008. 

110 See F.O. Licht World Ethanol and Biofuels Report, vol 7, no 21, p 434 (July 8, 2009). 

111 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 

112 “Essential Rendering”, published by the National Renderer’s Association, edited by David Meeker. 2006. 

Available at http://nationalrenderers.org/assets/essential_rendering_book.pdf 

113 “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 

114 A copy of this letter is available in the docket. 

115 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. 

116 Ibid. 
296

 117 Ryan, Catie. op. sit.

118 Ryan, Catie, “Cultivating Clean Energy: The Promise of Algae Biofuels,” NRDC and Terrapin Bright Green, 

LLC. October 2009. 

119 Davis, Ryan. November 2009. Techno-economic analysis of microalgae-derived biofuel production. 

National Renewable Energy Laboratory. Technical Memorandum to EPA. 

120 Davis, Ryan. op. sit.

121 Chisti, Yusuf, "Biodiesel from Microalgae." Biotechnology Advances 25, 294-306, 2007. 

122 Schenider, David, "Grow Your Own?" American Scientist, Sept.-Oct. 2006. 

123 Campbell, Matthew N., "Biodiesel: Algae as a Renewable Source for Liquid Fuel." Guelph Engineering 

Journal, 1, 2-7, 2008. 

124 Chisti, op. sit. 

125 Pienkos, Philip T., "The Potential for Biofuels from Algae," Algae Biomass Summit. San Francisco, CA. 

Nov. 15, 2007. 

126 Campbell, op. sit. 

127 Pienkos, op. sit. 

128 Pienkos, op. sit. 

129 Campbell, op. sit. 

130 Putt, Ron. “Algae as a Biodiesel Feedstock,” Nov. 20, 2007. 

131 Sheehan, op. sit. 

132 "Algae Bloom Again." Nature, 447, 520-21 2007. 

133 Deshayes, Pierre-Henry, "As planet swelters, are algae unlikely saviour?" AFP, July 10, 2008. 

134 Sheehan, op. sit. 

135 Pienkos, op. sit. 

136 “PV Solar Radiation,” Digital image. National Renewable Energy Laboratory. May 2004. 

137 Bullock, Cary, "Algae Corrals Carbon Dioxide," EnergyBiz Magazine, 68-70, Mar.-Apr. 2007.

138 Chisti, op. sit.

139 Sheehan, op. sit. 

140 Davis, Ryan. op sit.

141 Ryan, Catie, op. sit. 

142 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. 

143 Euler, Hartlieb, and David Gorriz, “Case Study "Jatropha Curcas"” Rep. No. Global Facilitation Unit for 

Underutilized Species, Frankfurt, 2004. 

144 Jongschaap, op. sit.

145 Ibid.

146 Fairless, Daemon. "The little shrub that could - maybe." Nature 449 (2007): 652-55. 

147 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. 

148 Woltjer, Lyanne. Size does matter. Expertise Centrum voor Duurzame Ontwikkeling (ECDO). Dec. 2006. 

149 Jongschaap, op. sit.
297

 150 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. 

151 Jongschaap, op. sit.

152 Fairless, op. sit.

153 Jongschaap, op. sit. 

154 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. 

155 Jongschaap, op. sit.

156 Kumar, op. sit. 

157 Ibid.

158 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. 

159 Jongschaap, op. sit. 

160 USDA, "PLANTS Profile for Jatropha curcas L." USDA Natural Resources Conservation Service. 

http://plants.usda.gov/java/profile?symbol=jacu2, November 3, 2008. 

161 Jongschaap, op. sit. 

162 Oregon Climate Service, “State Annual Precip Maps,” http://www.ocs.oregonstate.edu., November 3, 2008. 

163 Carney, Dan. "Second-generation biodiesel." Automotive Engineering, May 2008: 20-22. 

164 Koch, Blair. “Canola yield light, but growers pleased with first crop.” Ag Weekly August 21, 2007. 

<http://www.agweekly.com/articles/2007/09/10/news/ag_news/news32.txt> 

165 W.M. Breene, J.T. Budin, L.A. Field, and D.H. Putnam. “Camelina: A Promising Low-Input Oilseed.” New Crops. 1993. 314-

322. < http://www.hort.purdue.edu/newcrop/proceedings1993/v2-314.html> 

166 Great Plains: The Camelina Company < https://www.camelinacompany.com/marketing/agronomics.aspx#Facts> 

167 Schill, Susanne R. “Making Pennycress Pay Off.” Biodiesel Magazine February 2008. 168 Biofuel Manufacturers of Illinois. http://www.growpennycress.com/ 

169 F.O. Licht’s World Ethanol and Biofuels Report. Vol 6, No 11, p.203. Feb 15, 2008. 

170 Figures taken from European Biodiesel Board website as of December 2009. See http://www.ebbeu.org/stats.php. 

171 DTN Ethanol Center, ”EU Biodiesel Feedstock Challenge,” October 11, 2007, 

http://www.dtnethanolcenter.com/index.cfm?show=10&mid=66&pid=27 

172 World Biofuels: FAPRI 2008 Agricultural Outlook. http://www.fapri.org/outlook2008/text/14Biofuels.pdf, 

November 3, 2008. 

173 Biofuels Barometer. Geographic Information System: EurObserv'ER 

http://www.eufores.org/index.php?id=29, November 3, 2008. 

174 EUROPA Press Release, “Stricter fuel standards to combat climate change and reduce air pollution,” Jan. 31, 

2007. 

175 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. 

176 Ministry of Mines and Energy, “The Brazilian Experience with Biofuels,” Presentation by Ricardo de 

Gusmao Dornelles, June 1, 2007. 

177 EPE, “Plano National de Energia 2030.” Presentation from Mauricio Tolmasquim, 2007. 

178 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. 

179 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. 

180 USDA FAS, “Gain Report. Indonesia Bio-Fuels Biofuels Annual 2007,” June 13, 2007. 
298

 181 USDA FAS, “Palm oil continues to dominate global consumption in 2006/2007,” 

http://www.fas.usda.gov/oilseeds/circular/2006/06-06/Junecov.pdf 

182 Dato’ Dr. Mohd. Basri Wahid, “Malaysian Palm Oil Board. Presentation: Technological Progress and 

Commercialization of Biodiesel in Malaysia.” 

183 USDA FAS, “Gain Report. India Bio-fuels Annual 2007,” June 1, 2007. 

184 Fairless, op. sit. 

185 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. 

186 Milbrandt, A. (2005). “Geographic Perspective on the Current Biomass Resource Availability in the United 

States.” 70 pp.; NREL Report No. TP-560-39181 

clxxxvii 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. 

clxxxviii Rummer, B.; Len, D.; and O’Brien, O. (2004). Forest Residues Bundling Project-New Technology for 

Residue Removal. USDA Forest Service, Southern Research Station 

clxxxix Ibid. cxc Rawlings, C., et. al. (2004). A Study of How to Decrease the Costs of Collecting, Processing and 

Transporting Slash. USDA Forest Service. 

cxci 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. 

cxcii 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 

cxciii P. Savoie, L. D’Amours, F. Lavoie, G. Lechasseur, H. Joannis. Development of a Cutter-Shredder-Baler to 

Harvest Long-Stem Willow. Paper Number: 061016, Presented at: 2006 ASABE Annual International 

Meeting, Sponsored by ASABE, Portland Convention Center, Portland, Oregon, USA, July 9 – July 12, 2006 

cxciv 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 cxcv 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 Biomass Feedstocks to a 

Bioenergy Industry, Paper No: 066151, 2006 ASABE Annual International Meeting, Oregon Convention 

Center, Portland, Oregon, 9 - 12 July 2006 

cxcvi Biomass Research Development Board. The Economics of Biomass Feedstocks in the United States. 

Occasional Paper 1, October 2008.

197 ICM website, Ethanol Production Process, http://www.icminc.com/ethanol/production_process 

(Supplemented with information provided by EPA’s Region 7). 

198 Renewable Fuels Association website, How Ethanol is Made: The Ethanol Production Process –Wet Milling, 

http://www.ethanolrfa.org/resource/made. 

199 Renewable Fuels Association, Annual Energy Outlook 2006 

(http://www.ethanolrfa.org/objects/pdf/outlook/outlook_2006.pdf) 

200 POET website, Technology - BPXTM, http://www.poetenergy.com/learn/bpx.asp. 
299

 201 Kirkbride McElroy, Anduin , “Poet, ISU partner for BPX research,” Ethanol Producer Magazine, 

http://www.ethanol-producer.com/article.jsp?article_id=3770, March 2008. 

202 U.S. Environmental Protection Agency, Combined Heat & Power Partnership website, Basic Information, 

http://www.epa.gov/chp/basic/index.html.

203 Smeets, Edward, et. al. “Sustainability of Brazilian bio-ethanol”. August 2006 

204 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). 

http://pubs3.acs.org/acs/journals/toc.page?incoden=iechad&indecade=3&involume=37&inissue=1] 

205 Harris, E.E., Beglinger, E., Hajny, G.J., and Sherrard, E.C., , Industrial and Engineering Chemistry, 37(1): 

12–23 (1945) 

http://pubs3.acs.org/acs/journals/toc.page?incoden=iechad&indecade=3&involume=37&inissue=1] 

206 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. 

207 LaMonica, Martin. “Investor Vinod Khosla: Advanced biofuels are closer than you think”. Accessed at: 

http://www.news.com/8301-11128_3-9811702-54.html 

208 DOE. “Biomass Program: ABC’s of Biofuels”. Accessed at: 

http://www1.eere.energy.gov/biomass/abcs_biofuels.html#content 

209 Starch Hydrolysis; http://www.bio-link.org/pdf/starch.pdf 

210 Glossary of Biomass Terms, National Renewable Energy Laboratory, Golden, CO. 

http://www.nrel.gov/biomass/glossary.html

211 Glossary of Biomass Terms, National Renewable Energy Laboratory, Golden, CO. 

http://www.nrel.gov/biomass/glossary.html

212 Condensation and Hydrolysis; http://www.biotopics.co.uk/as/disaccharideformation.html 

213 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. 

214 Stephanopoulos, Gregory, et. al., “Challenges in Engineering Microbes for Biofuels Production,” Science, 

315, 801, February 9, 2007. 

215 Dipardo, Joseph, “Outlook for Biomass Ethanol Production and Demand,” Energy Information 

Administration, 2002. 

216 Tao, Ling and Aden, Andy. November 2008. Techno-economic Modeling to Support the EPA Notice of 

Proposed Rulemaking (NOPR). National Renewable Energy Laboratory (NREL) 

217 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. 

218 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. 

219 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 

220 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. 

221 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 

222 Gray, K., et. al., “Bioethanol,” Current Opinion in Chemical Biology, 10:141-146, 2006. 

223 Graf, op. sit.
300

 224 Aden, Andy. December 10, 2009. “Feedstock Considerations and Impacts on Biorefining.” National 

Renewable Energy Laboratory 

225 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. 

226 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. 

227 Genencor Launches First Ever Commercial Enzyme Product for Cellulosic Ethanol, Rochester, NY, WorldWire, October 22, 2007 Copyright © 2007,. All rights reserved. World-Wire is a resource provided by 

Environment News Service. http://world-wire.com/news/0710220001.html 

228 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 

229 Stephanopoulos, op. sit.

230 US. DOE. Technologies: Processing and Conversion. Accessed at:

http://www1.eere.energy.gov/biomass/processing_conversion.html on October 28, 2008 

231 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 

232 Aden, Andy, Mixed Alcohols from Woody Biomass – 2010, 2015, 2022, National Renewable Energy 

Laboratory (NREL), September, 23 2009. 

233 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 

234 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. 

235 Ciferno, Jared P., Benchmarking Biomass Gasification Technologies for Fuels, Chemicals and Hydrogen 

Production, National Energy Technology Laboratory, Department of Energy, June 2002. 

236 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 

237 Aden, Andy, Mixed Alcohols from Woody Biomass – 2010, 2015, 2022, National Renewable Energy 

Laboratory (NREL), September, 23 2009. 

238 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. 

239 DOE EERE. “Biomass Program: Thermochemical Conversion of Corn Stover,” April 2006. Accessed at: 

http://www1.eere.energy.gov/biomass/pdfs/thermochemical_stover.pdf. 

240 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 

241 Davis, Ryan; Techno-economic analysis of current technology for Fischer-Tropsch fuels production, 

National Renewable Energy Laboratory for EPA, August 14, 2008. 

242 DOE EERE Biomass Program. “Thermochemical Conversion Processes: Pyrolysis” 

http://www1.eere.energy.gov/biomass/thermochemical_processes.html, November 6, 2008. 

243 Zeman, Nicholas, “Thermochemical Versus Biochemical,” Biomass Magazine, June 2007. 

244 Information derived from staff-level communication with National Biodiesel Board personnel. 
301

 245 “Tyson ConocoPhillips Venture in Jeopardy.” The Morning News, article dated 9/26/08. 

http://www.nwaonline.net/articles/2008/09/26/business/092708fuelcredits.txt 

246 See Syntroleum Investor Presentation, dated November 2009. Available here: 

http://www.syntroleum.com/Presentations/SyntroleumInvestorPresentation.November%205.2009.FINAL.pdf. 

Accessed December 16, 2009. 

247 “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 

248 Based on presentation materials by Lars Peter Lindfors dated 29 September 2009, available here: 

http://www.nesteoil.com/default.asp?path=1,41,538,2496,12947. Accessed December 16, 2009. 

249 Renewable Fuels Association website, Historical U.S. Fuel Ethanol Production, 

http://www.ethanolrfa.org/industry/statistics/#A. 

250 Ibid

251 Ibid.

252 Ministry of Agriculture in Brazil (MAPA), http://www.agricultura.gov.br/ Accessed: April 3, 2009 

253 F.O. Licht’s, “World Ethanol Markets: The Outlook to 2015,” pg. S-22 to S-23, 2006. 

254 F.O. Licht’s, “World Ethanol and Biofuels Report,” Vol. 5, No. 22, July 23, 2007. 

255 Agra FNP, “Sugar and Ethanol in Brazil: A Study of the Brazilian Sugar Cane, Sugar and Ethanol 

Industries,” 2007. 

256 Agra FNP, op. sit.

257 ANFAVEA (Associação Nacional dos Fabricantes de Veículos Automotores 

Assessoria de Planejamento Econômico e Estatístico Indústria Automobilística Brasileira - Empresas 

Associadas). Internal Sales in Brazil 2009. http://www.anfavea.com.br/tabelas.html, November 24, 2009.

258 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, December 9, 2009. 

259 Ewing, Elizabeth, “Pipeline Projects on Hold.” Ethanol Producer Magazine, July 2008. 

260 Rothkopf, Garten, “A Blueprint for Green Energy in the Americas,” 2006. 

261 Ibid. 262 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. 

263 Agra FNP, op. sit.

264 Carpenter, Claudia, “Sugar Gains Capped by Brazil Ethanol Expansion, Czarnikow Says,” Bloomberg, June 

19, 2008. 

265 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. 

266 AFP, “Brazil says biofuel production not to blame for food crisis,” June 1, 2008. 

267 Business News Americas, “Odebrecht to invest US$2.6 bn to Lead Ethanol Sector – Brazil,” June 28, 2007. 

268 The Wall Street Journal, “ADM Plans Entry Into Sugar-Cane Ethanol in Brazil,” June 22, 2007. 

269 Agra FNP, op. sit.

270 Petrobras Magazine No. 122. “Ethanol: From Brazil to the World,” August 13, 2007. 

271 Ibid.

272 Ewing, op. sit. 

273 Rothkopf, op. sit. 

274 Ibid.

275 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. 

276 Petrobras Magazine No. 122, op. sit.

277 Agra FNP, op. sit. 
302

 278 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. 

279 Ewing, op. sit.

280 Walter, A. et. al., “Perspectives on Fuel Ethanol Consumption and Trade,” Biomass and Bioenergy, 32, 730-

748, 2008. 

281 AFP., “EU Deputies Seek to Limit Use of Biofuels,” September 11, 2008. 

282 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 

283 BP, “BP Statistical Review of World Energy 2007 (revised with 2008 statistics) Historical Data,” 

http://www.bp.com/statisticalreview. 

284 Walter, A., op. sit.

285 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.

286 Ribeiro, F., “The New European Challenge for Brazilian Ethanol Exports,” Frost & Sullivan Market Insight, 

February 7, 2008. 

287 European Bioethanol Fuel Association (eBio), “The Industry, Statistics: Production Data,” 

http://www.ebio.org/statistics.php?id=4, September, 2009. 

288 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, 

September 9, 2009. 

289 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. 

290 Fukuda, Hisao, et. al.,“Japan Bio-fuels Production Report,” USDA, FAS, May 26, 2006. 

http://www.fas.usda.gov/gainfiles/200605/146197881.pdf 

291 Iijima, Midori. (2009) “ Japan to Focus on Next Generation Biofuels,” USDA FAS GAIN Report. 

292 Rothkopf, op. sit.

293 Fukuda, op. sit.

294 Ibid. 

295 Rothkopf, op. sit.

296 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. 

297 Iijima, op sit.

298 Rothkopf, op. sit.

299 Ibid. 

300 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 

301 Ewing, op. sit. 

302 Fukuda, op. sit.

303 Rothkopf, op. sit.

304 Iijima, op sit. 

305 Rothkopf, op. sit.

306 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. 

307 Nayak, D., “Weak Crude, Cane Shortage Hit India Ethanol Expansion” Wall Street Journal, April, 1, 2009.

308 Regaldo, Antonio, et. al., “Ethanol Giants Struggle to Crack Brazil Market,” Wall Street Journal, September 

10, 2007. 

309 Ibid.

310 Ohga, op. sit.
303

 311 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. 

312Renewable Fuels Association (RFA), “2008 World Fuel Ethanol Production, ” 

http://www.ethanolrfa.org/industry/statistics/#E, December 23, 2009. 

313 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. 

314 Rothkopf, op. sit.

315 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 

316 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. 

317 Rothkopf, op. sit. 

318 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. 

319 Rothkopf, op. sit. 

320 Ibid. 

321 Ibid. 

322 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. 

323 Rothkopf, op. sit. 

324 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 

325 Joseph, Ken, “Argentina Bio-Fuels Argentine Bio-Fuels Report 2007,” USDA, FAS, May 21, 2007. 

http://www.fas.usda.gov/gainfiles/200706/146291490.pdf 

326 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. 

327 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 

328 Sobolik, Jessica, “Canadian Government Passes Renewable Fuels Standard,” Ethanol Producer Magazine, 

August 2008. 

329 Pinzon, L., “Colombia Bio-fuels Annual 2007,” USDA, FAS, June 1, 2007. 

http://www.fas.usda.gov/gainfiles/200706/146291386.pdf 

330 Chavez, L., et. al., “Mexico Bio-fuels Annual Report 2007,” USDA, FAS, June 12, 2007. 

http://www.fas.usda.gov/gainfiles/200706/146291366.pdf 

331 F.O. Licht’s, “World Ethanol Markets: The Outlook to 2015,” pg. S-18 to S-20, 2006. 

332 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 

333 Bryan, Tom, “Entering Tariff-Free,” Ethanol Producer Magazine, January 2004. 

334 Office of the United States Trade Representative (USTR), “Ethanol Provisions in the CAFTA-DR,” July 

2007. 

335 Bryan, op. sit. 

336 Rapoza, Kenneth, “UPDATE: Tax Loophole Helps US Import Ethanol ‘Duty Free’- ED&F,” INO News, 

Dow Jones Newswires, March 2008. http://news.ino.com/ 

337 Peter Rohde, “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. 

338 Perkins, Jerry, “BRAZIL: Loophole Hurt U.S. Ethanol Prices,” DesMoinesRegister.com, October 18, 2007. 

339 Public Law Version 6124 of the Farm Bill. 2008. http://www.usda.gov/documents/Bill_6124.pdf. 

340 Lundell, Drake, “Brazilian Ethanol Export Surge to End; U.S. Customs Loophole Closed Oct. 1,” Ethanol 

and Biodiesel News, Issue 45, November 4, 2008. 
304

 341 MacDonald, T., et. al., “Ethanol Supply Outlook for California,” California Energy Commission, October 

2003. http://www.ethanolrfa.org/objects/documents/100/castaffreport.pdf 

342 Petrojam Limited, “Official Opening of Petrojam Ethanol Limited,” November 12, 2008. 

http://www.pcj.com/petrojam/whats_new.htm 

343 Petrojam Limited, “About Us,” November 12, 2008. 

http://www.petrojambunkering.com/petrojam_aboutb.htm 

344 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. 

345 Email Correspondence with Jeffrey Tuite, ED&F Man, September 6, 2007. 

346 Yacobucci, Brent, “Ethanol Imports and the Caribbean Basin Initiative,” CRS Report for Congress, Order 

Code RS21930, Updated March 18, 2008. 

347 Email Correspondence with Jeffrey Tuite, ED&F Man, September 6, 2007. 

348 Ethanol Producer Magazine, “Ethanol Dehydration Facility to be Built in Trinidad,” December 2006. 

349 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. 

350 Homer, Louis, “Another Energy Sector Stimulus,” PetroleumWorld.com. November 22, 2006. 

http://www.petroleumworldtrinidad.com/storytrini06112606.htm 

351 Etter, op. sit.

352 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 

353 Email Correspondence with Jeffrey Tuite, ED&F Man, September 6, 2007. 

354 Ramjeet, Oscar, “Barbados to Build $72 Million Ethanol Dehydration Plant,” Caribbean Net News, August 

22, 2008. 

355 Jamaica Gleaner News, “US$36m Ethanol Plant for Barbados,” August 23, 2008. http://www.jamaicagleaner.com/gleaner/20080823/business/business1.html 

356 Email Correspondence with Jeffrey Tuite, ED&F Man, September 6, 2007. 

357 Bryan, op. sit. 

358 Etter, op. sit.

359 Ibid.

360 Email Correspondence with Jeffrey Tuite, ED&F Man, September, 7, 2007. 

361 Etter, op. sit. 

ccclxii 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. 

ccclxiii 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. 

ccclxiv 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. 

ccclxv 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. 

ccclxvi 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. 

ccclxvii 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. 

ccclxviiiMidwest Governors Association, “Energy Security and Climate Stewardship Platform for the Midwest 

2007,” http://www.midwesterngovernors.org/resolutions/Platform.pdf, Published November 2007. 

369 Plant information taken from Nation Biodiesel Board website as of November 2009. 

370 Capacity data taken from National Biodiesel Board as of November 2009. Production, import, and export 

figures taken from EIA Monthly Energy Review, Table 10.4 as of October 2009. 
305

 371 See http://www.biodiesel.org/buyingbiodiesel/plants/showall.aspx and 

http://www.afdc.energy.gov/afdc/incentives_laws.html. Tax incentive information used here was current as of 

October 2008, and plant statistics as of October 2009. 

372 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). 

373 “Tyson ConocoPhillips Venture in Jeopardy.” The Morning News, article dated 9/26/08. Available in the 

docket. 

374 See Syntroleum Investor Presentation, dated November 2009. Available here: 

http://www.syntroleum.com/Presentations/SyntroleumInvestorPresentation.November%205.2009.FINAL.pdf. 

Accessed December 16, 2009. 

375 “Tyson's Fats to Fuel Plant on Schedule.” The Morning News, article dated 10/6/08. Available in the 

docket. 

376 Syntroleum Investor Presenation dated November 5, 2009. Available in the docket or at: 

http://www.syntroleum.com/Presentations/SyntroleumInvestorPresentation.November%205.2009.FINAL.pdf 

377 Ethanol and Pipeline Transportation Policy Paper, Association of Oil Pipelines (AOPL and American 

Petroleum Institute (API), February 2007, 

http://www.aopl.org/pdf/AOPL_API_Ethanol_Transportation_Final144839.pdf 

378 Testimony of Tim Felt President and CEO Explorer Pipeline On Behalf of and the Association of Oil Pipe 

Lines (AOPL) and API Before the House Committee on Energy and Commerce Subcommittee on Energy and 

Air Quality March 12, 2008, http://www.aopl.org/pdf/felt-testimony.pdf

379 Kinder Morgan announcement that their Central Florida Pipeline from Tampa to Orlando ships batches of 

ethanol along with batches of gasoline. http://www.kindermorgan.com/business/products_pipelines/ 

380 “POET Joins Magellan Midstream Partners to Assess Dedicated Ethanol Pipeline”, March 2009, 

http://www.poet.com/news/showRelease.asp?id=155 

381 Kinder Morgan announcement that their Central Florida Pipeline from Tampa to Orlando ships batches of 

ethanol along with batches of gasoline. http://www.kindermorgan.com/business/products_pipelines/ 382 “Analysis of Fuel Ethanol Transportation Activity and Potential Distribution Constraints”, prepared for EPA 

by Oak Ridge National Laboratory, March 2009.

383 “Analysis of Fuel Ethanol Transportation Activity and Potential Distribution Constraints”, prepared for EPA 

by Oak Ridge National Laboratory, March 2009.

384 “The Importance of Adequate Rail Investment”, Association of American Railroads, 

http://www.aar.org/GetFile.asp?File_ID=150 

385 American Association of State Highway and Transportation Officials (AASHTO) Freight-Rail Bottom-Line

Report, 2003. 

386 Association of American Railroads (AAR), National Rail Freight Infrastructure Capacity and Investment 

Study, September 2007. 

387 “Analysis of Fuel Ethanol Transportation Activity and Potential Distribution Constraints”, prepared for EPA 

by Oak Ridge National Laboratory, March 2009. 

388 Transportation activity data output spreadsheet that accompanied the report entitled “Analysis of Fuel 

Ethanol Transportation Activity and Potential Distribution Constraints”, prepared for EPA by Oak Ridge 

National Laboratory, March 2009. 389 Transportation activity data output spreadsheet that accompanied the report entitled “Analysis of Fuel 

Ethanol Transportation Activity and Potential Distribution Constraints”, prepared for EPA by Oak Ridge 

National Laboratory, March 2009.

390 “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

391 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_historical.html
306

 392 “Analysis of Fuel Ethanol Transportation Activity and Potential Distribution Constraints”, prepared for EPA 

by Oak Ridge National Laboratory, March 2009. The list of projected ethanol import locations is contained in 

Table 3 in Section 3.3.2 of this report.

393 “Analysis of Fuel Ethanol Transportation Activity and Potential Distribution Constraints”, prepared for EPA 

by Oak Ridge National Laboratory, March 2009.

394 Transportation activity data output spreadsheet that accompanied the report entitled “Analysis of Fuel 

Ethanol Transportation Activity and Potential Distribution Constraints”, prepared for EPA by Oak Ridge 

National Laboratory, March 2009.

395 “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

396 Our projections of the motor fuel demand can be found in chapter 1.2 of this RIA. 

397 “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 GovernmentIndustry Meeting. 

398 “Infrastructure Requirements for an Expanded Fuel Ethanol Industry”, Downstream Alternative 

Incorporated, January 15, 2002. 

399 A discussion of the volumes of biofuels we estimate would be used absent the RFS2 standards is located in 

chapter 1.2 of this RIA. 

400 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/highwaydiesel/regs/ria-v.pdf, EPA Docket A-99-06. 401 “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 GovernmentIndustry Meeting. 

402 “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 GovernmentIndustry Meeting. 

403 Chapter 1.7 of this RIA 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. 

404 “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. 405 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. 

406 “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. 

407 National Petroleum News, “2008 marketfacts”, www.npnweb.com

408 National Petroleum News, “2007 marketfacts”, Volume 99, Number 10, October 2007, www.npnweb.com 

409 The National Ethanol Vehicle Coalition estimate of E85 refueling facilities is located at 

http://www.e85refueling.com/ estimates http://www.e85refueling.com/ 410 The “NEAR85” estimate of E85 retail facilities is located at http://www.neare85.com/

411 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). 

412 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. 

413 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. 

414 Renewable Fuels Association (RFA) website, Ethanol Biorefinery Locations, 

http://www.ethanolrfa.org/industry/locations, Updated on April 2, 2008. 
307

 415 International Trade Commission 2005-2007 historical ethanol import data as reported by the Renewable 

Fuels Association, http://www.ethanolrfa.org/industry/statistics/ 

416 Communication from Douglas Newman, International Trade Commission to Doris Wu, EPA, May 20, 2008. 

417 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 

418 NASS database. http://www.nass.usda.gov/ 

419 USDA, WGA, Bioenergy Strategic Assessment project findings upcoming as noted in report WGA. 

Transportation Fuels for the Future Biofuels: Part I. 2008. 420 NASS database. http://www.nass.usda.gov/

cdxxi 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). 

cdxxii 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). 

cdxxiii 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). 

cdxxiv American Petroleum Institute, Gasoline Tax Report, 

http://www.api.org/statistics/fueltaxes/upload/January_2008_gasoline_and_diesel_summary_pages-2.pdf, 

January 2008. 

cdxxv See http://www.afdc.energy.gov/afdc/fuels/biodiesel_laws.html. Incentives were evaluated as of October 

2008. 

cdxxvi Status taken from the online plant database as of October 2009. Current data is available at 

http://www.biodiesel.org/buyingbiodiesel/plants/showall.aspx 

cdxxvii 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 

cdxxviii 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 

cdxxix 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/current/pdf/table

16.pdf