## 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: Lifecy cle GHG An alysis.........................................................................

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

Chapter 4: Impacts on Cost of Rene wable 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 Heav y-Duty Highway Engines and Vehicles.....

Endnotes.....................................................................................................................77 13 

## 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 th e Energy Independence and Security Act of 2007 (EISA), Congress made several im portant revisions to the renewa ble 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 a nd 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 discusse d, as well as the different biofuel production technologies, industry plans, and potential growth projections for future facilities. A discussion
of biofuel distribution a nd 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 EI SA, and to determine which qualify for the four
GHG reduction thresholds established in EISA. Futu re 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, acrole in, 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 Re newable Fuels, Gasoline, and Diesel The impact of the proposed program on the pr oduction and distribution costs of ethanol, biodiesel, gasoline and diesel are discussed. Pe r-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 RF S2 proposal on the U.S. and international agricultural sector, U.S. petroleum imports, and th e 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 differ ent 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 r ecommendations 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 e missions data. The emission impacts on NOx, PM, HC, and CO of 20 volume percent biodiesel fu els 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

CH 3 CHO Acetaldehyde

CH 3 C(O)OO

· Acetyl peroxy radical

CH 3 C(O)OONO 2 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 Area7 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

H 2 O 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

HNO 3 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)

m 2 Square meter MCIP Meteorology-Chemistry Interface Processor mg/m 3 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 Hydrocarbons9 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

NO 2 Nitrogen dioxide

NO

x Oxides of nitrogen NPRM Notice of Proposed Rulemaking
NRC National Research Council
NRCS Natural Resource Conservation Service NREL National Renewable Energy Laboratory

O 3 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

PM 10 Coarse Particle

PM 2.5 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 10 15 (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 Group10 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 volu me) of fuel evaporates (ASTM D 86) T90 Temperature at which 90% (by volu me) 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 Year11 

## Chapter 1: Renewable Fuel Production and Consumption

1.1 Biofuel Feedstock Availability

Currently, the main feedstocks used for rene wable fuel production in the U.S. are corn for ethanol and soy for biodiesel. As technologie s 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 en ough 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 gr own in the U.S. into ethanol as well as the introduction of relatively new crop va rieties 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 etha nol, 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 b illion 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 renewa ble fuel volume from business-as-usual on crop acreage, crop allocation to fuel vs. other uses, co sts, etc. See Section 1.2 for more discussion on
the renewable fuel volumes assume d 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 Analysis c 12.8-17.8/2016 76-78 a 178-193 33-40% 2.9-3.0 EPA FRM Analysis

(Base Yield Case) 15/2022 92/87 a 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, Mi ssouri, 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 yi elds calculated at the regional level. The national average depends on crop production in each re gion 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 consultatio n 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 pe rcent of corn under the higher corn yield assumptions to produce 15 billion gallons of corn ethanol.

The amount of corn allocated to fuel vs. ot her 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 di vert 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 modelin g results to help inform us of the potential impacts of an increased growth in renewabl e fuels (see Chapter 5 for more detail).

Over the last 15 years, ethanol indus try 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 va rieties. Combining these figures, we project14 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 Sec tion 1.4 of this RIA for more information on corn ethanol biofuel production tec hnologies, e.g. dry mill vs. wet mill.

Other grains that can be processed into et hanol 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 a nd 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 typi cally 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 importe d ethanol to the U.S. will likely come from

sugarcane.

World production of sugarcane is approxima tely 1.4 billion metric tons (MT) and is concentrated mainly in tropical regions, particul arly in Latin America, Africa, and South and Southeast Asia. Roughly 100 c ountries 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 arab le 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 indicat e 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 availa ble with proper soil and15 climate conditions for sugarcane without utilizin g 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 yi eld of approximately 600 gal/acre which is a
conservative estimate based on exis ting 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 G overnment 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 wit hout irrigation and the potential vol umes 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 Availabl e Land for Sugarcane Expansion B,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 ot her 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 availa ble sugarcane supply by 2017. Brazil is estimated to produce approximately 2/3 of the potential supp ly. The majority of this supply would likely be consumed within the country, with the leftove r potentially available for export to the U.S. and other countries. Recent government and industr y estimates indicate that approximately 3.8-4.2 bgal of ethanol could be available for ex port from Brazil by 2022 (with close to 17 billion gallons being produced and 13 billion gallons c onsumed domestically). See Section 1.5.2.1.1 of
this RIA for further details on Brazilian etha nol 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 reallo cation of arable land for biofuel production. Although Argentina and Columbia have significant underu tilized lands available, these re sources generally do not have
suitable soil and climate ch aracteristics for sugarcane production. Due to these factors, Brazil is the most likely country able to produce substan tial volumes of sugarcane for biofuel production
in the future.

1.1.1.3 Domestic Sugar Ethanol

Currently, there are no U.S. plants pr oducing 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 thes e 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 producin g 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 su gar 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 80617 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 ca ne’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 Et hanol and Power which is currently in the development stage and plans to build a fac ility 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 sugar cane is being grown on marginal and existing cropland that is unsuitable for food crops and w ill 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 pr oduce 12-15 million gallons per year of ethanol on the island of Kauai in Hawaii, perhaps as ea rly as 2010. Hawaii is well suited for sugarcane ethanol production due to se veral factors, including lower cost s for feedstock compared to those in the continental U.S., high prices for el ectricity and liquid fuel s, 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 concen tration of soluble sugars in the sap. 24 They are used for the production of syrup, alcoholic bevera ges, crystal sugar, etc. The interest in bioe nergy production from sweet sorghum comes from the easy accessibility of readily fermentable sugars combined with very high yields for biomass. Yield vari es 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 facilitie s in the U.S. that can process sorghum juice18 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 remove d 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 opera tion. 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 co sts 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 addre ss 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 extensivel y 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 be tween soil type, climate, and management when considering crop residue effects on soil. They recommended that rem oval rates be based on regional yield, climatic conditions and cultura l practices, with no specific rates given. 25 Using the Revised Universal Soil Loss Equation (RUS LE) 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) tr ansformations 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 fo r 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 remove d at the contemplated rates ove r a period sufficiently long for19 the effects to be clearly determined. Another di fficulty is that while the effects of removing a residue may appear to one observer to have aff ected the soil in a certain manner, it may not be completely clear that the observed effects were fu lly related to the residue removal or, were in fact related to a change or to combinations of ch anges 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 nati onal 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 er osion due to wind occurs in much the same manner as rainfall with wind forces dislodging so il particles and carryin g 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 pa rticles to other locations in the field (either downslope or downwind) where they can be transf erred 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 prep aration for the next crop, timing of field operations, present throughout the year, soil ty pe, field characteristics such as field slope, and the amount of residue (cover) left on the fiel d 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 acr oss 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 tolera ble soil loss values denote the maximum rate of soil erosion that can occur for a particular so il type that does not lead to prolonged soil
deterioration and/or loss of productivity. Tolerable soil loss limi ts 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 eros ion-control factors that farmers would be able to implement. However, T values are not a func tion of the type of crop grown.

Another important aspect associated with so il conservation involves soil tilth. Soil tilth is defined as the physical condition of the soil as re lated to its ease of tillage, fitness as a seed bed, impedance to seedling emergence and root penetr ation, 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 blowing20 workability) as well as organic matter content, mois ture content, porosity, water retention, degree of aeration, rate of water inf iltration, drainage, and capillary-wat er 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. Ty pe 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 y ear, and hence, the amount of residue that can possibly be removed for energy purposes. It mu st be noted that even though crop residues may be used for energy purposes, the farmer is, firs t 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 lengt h, 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 mo re importantly, not all soil types within a county may be suitable for agricultural crop producti on. Some soils possess characteristics that make them highly susceptible to erosion that may not be able to sustain certain cropping practices. Pr oduction of conventional agricultu ral 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, residue s can increase soil organic matter (SOM). However, roots appear to be the largest contri butor 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. Re sidue harvest may also require increased fertilizer inputs to make up for nutrients removed in the plant mate rial. When returned to the land, crop residue also replenishes soil organic car bon (SOC) that typically has alre ady been reduced 30 to 50% of precultivation levels through crop production activities. Soil organi c carbon retains and recycles nutrients, improves soil structure, enhances wa ter 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-pr oducing organisms are enhanced by residue removal, others by residue re tention, depending on crop and re gion. 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 to21 crop residues, such as reduced bulk density, e. g., the soil is looser and lighter, and greater aggregate stability, also lead to bette r 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-ass ociated yield reducti ons have been found on poorly drained, fine-textured soils, these soils of ten have low erosion ri sk and residues might safely be removed.

Despite the many important be nefits of crop residues, research shows their effects can vary. For instance, some reports showed lower yi elds in systems with high crop residues due to increased disease or poor germination; others re ported 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 so il 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 remo val. Wrong decisions, carried out over extended periods could have far reaching de leterious effects. Sustainable residue removal rates for biofuel production vary by system, according to such fact ors 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 (% ma ss 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 area s 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 de termination also depends on soil type and other cropping practices. Removal rates will need to be reduced as c limates 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 dete rmine 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 vari able nearly always changes how all the variables
interact.

Given all the issues we’ve discussed regard ing residue removal a nd soil health, rather than try to predict, county-by-county how much residue will be availabl e, we assumed in our FASOM modeling that the available amount will be somewhere between 0% and 50%, at least
until the issues we have disc ussed are settled. We based th e 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 mo st attention across the industry due to their concentrated production areas and because they ge nerate the majority of total residue produced. This also means they will more likely be ab le to support commercia l scale production. In aggregate, the other residues provide fairly si gnificant quantities of mate rial, but because they are spread out, e.g., less densely planted both in th e 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 re sidue 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 Re sidue Feedstock Ava ilability (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 produ ce 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 biofue l estimated to be used by our agricultural modeling in 2022. E See Table 1.1-8. Smaller amounts w ill be required from sugarcane bagasse, wheat residue, as well as sweet sorghum pulp (b agasse) 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
Tota l 7. 7 444. 4 3.1 14. 6 23.1 128. 8 621. 8 Rice Sorghum Wheat Barley Corn Oats

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 re newable source of cellulosic material for biofuel production are not yet comme rcial, but have significant pot ential. 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 lowe r 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 harv esting the above-ground biomass. While most agricultural crops are annual species, perennials are considered beneficial in many ways. Dedicated perennial energy crops have the pot ential to grow on marginal lands, produce high yields, and may have low input needs. Once a pe rennial 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 decrea sing the need for large fertilizer inputs. In southern climates, perennials have the potential for higher yield per ac re 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 possi ble 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, a nd provide refuge for wildlife.

The following sections describe several of the most commonly discussed dedicated energy crops (switchgrass, miscanthus, and hy brid poplars) as well as some less familiarly known crops and the potential marginal lands on wh ich 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 Chap ter 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, aver age 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 resu lted in approximately 70% of the yield for the
first cut and 30% for the second. 44

Water and nitrogen availability are the ma in 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, initia l nitrogen fertilization ra tes 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 ha s 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 fade s and drops off leaving the stem. The stem is the commercially important part of the plant a nd resembles bamboo. Stems can reach nine feet in length, 1⁄2 to 3⁄4 in diameter, and are harv ested 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 estab lished 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. A ccording to trials conducte d 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 biofue l 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 othe r perennial plants at approxima tely $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 spec ies, will inevitably lower overhead costs. 54

Hybrid Poplar

The poplar tree is another option being invest igated 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 larg e canopies, and require less fertilization than their agricultural counterparts.

Technological advances in harvesting and ge netics may help produce species that will be more suitable for use as an energy crop. Ge netic information has helped to understand the characteristics the poplar tree. The complex ge netic 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 impor tance in the market. Dedicated energy crops must see this type of investment to bring a bout further knowledge of basic biology which will lead to advances in breeding and eventual domes tication of the species that have promise. The DOE along with university researchers have identi fied several other plants as potential energy crops. These include additional types of grasses su ch as reed canary grass, high biomass forage sorghum, and energy cane. Yields for forage so rghum 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 sel ection 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 op timal for all areas of the country, especially27 considering the amount of biofuels needed. Temperature, rainfall, and soil composition are highly variable across the continental United St ates; 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 es timated where the possible growing areas could occur (see Figure 1.1-2). 59

Figure 1.1-2. Possible Geographi c 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 Universi ty 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 la nds 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 an d not converted to urban or forested areas.
Historical land use data was obt ained from the History Database of the Global Environment 3.0 (HYDE) which consisted of gri dded maps which show the frac tion 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 wa s 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 approach es were then used to estimate a conservative and a high estimate of total land available. Biomass pr oduction was estimated using the Carnegie-Ames-Stanford Approach ecosystem model which takes into account climate data, soil28 texture, land cover and the nor malized difference vegetation i ndex (NDVI), but does not take
into account fertilizer use or irri gation, which could increase yields.

The low and high estimates for global ab andoned 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 natu ral 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, yiel ds 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, Ne vada, Colorado and Calif ornia each contribute
over 5 million abandoned acres to the total. Mi dwestern 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 pr oduction 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 th e 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 Pro duction by State 61

Area A rea 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

Kentuck y 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 Jerse y 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 Volume a a. Assuming a conservative 80 gal/ton conversion rate30 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 th at 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 benef its 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 forest ed land, two-thirds (504 million acres) is considered timberland which contains more than 20 ft 3 of woody material per
acre – the other one-third of the fo rest land contains less than 20 ft 3 of woody material per acre. Most of this forested land, 58 percent, is privat ely owned, another 29 percent of the forest land is publicly owned, and 13 percent is owned by the fore st industry. A higher percentage of the land is privately owned in the East, and a higher per centage of the land is publicly owned in the West.31 Of the 749 million acres of forestland, 77 are re served 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 bioma ss 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 wood y 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, prima ry 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 bioma ss, 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 ma jor 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 diam eter and greater), the logging industry creates logging residues. Logging residues typically incl ude tops of harvested trees and unwanted trees cut or knocked down and left on site, including de ad and cull trees. Other removals are growing
stock and other sources cut and bur ned or otherwise destroyed in th e process of converting forest land to non-forest uses, such as for making wa y for new housing or industrial developments. They also include growing stock removed in fo restry cultural operations. Forest residues are also available from fuelwood, which is harveste d wood used in the resi dential 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 in to 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 ot her 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, bot h primary wood processing and secondary conversion to finished consumer products can occur in the same facility. 67 Both primary and secondary mills pr oduce residue and woody waste ma terial. 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 re sidues 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 trimmin gs include herbaceous material and woody trimmings. Construction waste is made of contemporary building materials with little32 contamination. Sources include new reside ntial 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. Th e potential contribution of urban wood residues to the production of biofuels is discu ssed 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 ma terial, 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 pr operty and the impact on the environment. Thinning forests involves th e 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 pr event them from becoming overly dense could potentially help them to remain healthier. Ther e are many thinning operations today, but the material is burned or left to decompose in stead. The removed excess woody material from overgrown forests could provide a sour ce 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-u se benefits (e.g., wild life 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. Als o, 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 possibl e. Also, a couple of these factors, the high elevation and rockiness, results in areas of forestland which is inaccessible by forestry equipment. Forestry residues ar e 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 ri sk of fires and/or to improve forest health. In addition, resources such as primary and secondar y mill residues and urban wood residues are already collected at the proces sing facility and it seems probable that some
cellulosic facilities could be co-l ocated to mills and/or landfills to increase the likelihood of having close and steady feedstocks readily availa ble. Some states may also be endowed with larger wood resources than agricultural residues.33 In making estimates of poten tial 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 bi omass in a single pass operation such that residual forest residue for produc ing 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 percen t 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 tran sport of wood residues.

Sustainable Removal

While there has been some discussion of su stainable removal practic es for crop residues, there has been less review on the topic for wood y 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 w oody 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 resi due 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 ma nagement plans from 1995 indicated about 60 percent of western nationa l 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 ener gy 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 ye t to be consensus over the optimal amount.

Yet another issue regarding su stainable removal is the affect of forest residue extraction on biodiversity. The removal of forest residue may affect biodi versity because lower amounts of wood in the forest imply fewer habitats for sp ecies using wood for breeding. Species may also
be threatened because certain in sects colonize in wood that may be burned for energy purposes. Quantitative predictions about how much habitat loss various speci es can tolerate are almost impossible to make. Instead, one study recommended making qualitative predictions on which types of habitats or wood types are most threaten ed. For instance, this study examined Sweden’s
forest fuel extractions and conc luded 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 th eir 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. Studi es have shown that the growth of woody plants and yields of harvestable plant products are decr eased by soil compaction from residue collection equipment, because of the combined effects of high soil strength, decrease d 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 bi omass. On its Biomass Program webpage, the Department of Energy lists the higher heating va lues (lower heating valu es 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 gall ons 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 agricultu ral residues and switchgrass. The reasoning for the higher yields for hardwoods is their potentia l for higher carbohydrate compositions and thus more sugars available for convers ion 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 feedstoc k 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 studi es, and then summarize data which we received directly from the U.S. Forest Service. In addition, we were able to incorporate the forestry sector35 component in the FASOM model, as further desc ribed in Chapter 5. As these feedstocks are now allowed to compete with the various agricultur al 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. Ther efore, 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 su mmarizing much of the information contained in that report here because it is very useful b ackground 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 to tal forest inventory is harvested each year, which corresponds to 444 million dry tons. This re moval 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 remova l 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 potentiall y be available for biof uel 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 cite d 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. Virtua lly 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 wo od processing mills create some wood residue. However, almost all of this waste wood is reco vered 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 additiona l 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 mu ch residue is produced by these secondary wood processing mills, however, a study of these facilities did pr ovide an estimate.36 Approximately 15.6 million dry tons per year were estimated to be availabl e from the smaller of these secondary wood processing mills, however, th e 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 pulpi ng process which convert s 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 pul p and paper industry is already using all of this black liquor, plus purchasing and using some fossil fu els, to generate the el ectricity 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 pul p 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 wood y material. The forests which contain excess woody material are candidates for providing a dditional 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 w oody 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, t hus, 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 biofue ls industry annually, and 42 million dry tons that would supply the logging industry.

As shown below in Table 1.1-11, the Billi on 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 resi due 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 to tal 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 pe r year. We are primarily interested in compliance with the RFS2 biofuels sta ndard in 2022, which is just over 1/3 rd of the way between today and 2050. Thus, by interpolating the projec ted future forest resi due in 2022 relative to current levels and those in 2050, the report suppor ts 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 resi due that could be used to produce biofuels was made by Marie Walsh in a report titled “US Cellulosic Bi omass 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 he r 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 am ount 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 fi ve year intervals through 2030. The amount of logging residue available at diffe rent price points and for differen t years is summarized in Table
1.1-12.38 Table 1.1-12. Quantity of Logging Re sidue 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 Wa lsh 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 Re movals 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 resi due is estimated to be currently unused and available for producing biofuels. She concl udes that out of the 88.7 million dr y 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 add itional 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 othe r uses, including for fuel, it is assumed that at 65% of the market price of the raw wood valu e, 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 fo r 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 ava ilable for producing biofuels. Of 12.5 million dry tons of secondary mill residue which is generated, only 1.2 milli on 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 fo r producing biofuels. One of these potential sources is the forest material that could be available through the thinni ng of overgrown forests to help reduce the fire
risk within these forests. Marie Walsh refe renced 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 c ould be available from forest thinning.

Another potential source of fo rest material for biofuel produc tion that the study discussed is a portion of the estimated 35.4 million tons of fu el 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 th at forest pulpwood supply is exceeding demand in the Southeast. The demand of forest pul pwood decreased from 131 to 121 million tons per year from 1993 to 2003, and this demand is expect ed to further decrease through 2020, and some have projected that this d ecrease in demand will continue beyond 2020. During the period between 1993 and 2003, pulpwood acreage and manage ment intensity have increased, which suggests that the Southeast is and will continue to be over supplied. This oversupply of forest pulpwood could potentially provide a dditional biomass to the biofuels industry, although she did not provide any firm estimate for this.

While both of these studies provide quality a ssessments for the total amount of forest residue available for producing biomass, they both have an important limitation as well. The40 limitation is that these reports did not assess whether the forest residue in any particular area, along with other potential biomass, is of suffi cient density to adequately supply a potential cellulosic biofuel plant. This feedstock densit y assessment must also consider the feedstock availability requirements made by cellulosic plant investor s or banks, which may choose to require that a certain exce ss amount of feedstock be available to justify the use of that biomass in a cellulosic ethanol plant. Without considerin g these limitations, these studies may overestimate the quantity of biomass that would be truly usab le and also the ultimate amount of biofuel that could be produced. Some of these issues were ad dressed 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 informati on also included urban forest residue, however,
because that material is included with the othe r MSW, we did not consider it here (discussed later in Section 1.1.2.4). Like the studies discus sed above, the national fo rest 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 35,476,67442 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 39,724,50243 Table 1.1-17.
Tons of Forest Residue Availa ble 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 40,133,95944 The U.S. Forest Service data reveals that th ere are large amounts of fo rest material in the Southeast, the far Northeast and the Northwest porti ons 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 ac cess more and more of the timberland, the costs ramp up quickly. These numbers are also signif icantly different than those presented in the proposed rule. This is due to a misunderstandi ng 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 lo gging residue and timberla nd 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 op erations would produce logging residue and that the rest would produce timberland thinnings. Base d on suggestions from the forestry service we
have assumed that 50% of l ogging operations would produce logging residue and 50% would produce forestry thinnings. While these changes re sult in a significant decrease in the amount of wood residue available from current forestry ope rations they have no impact on our analyses.
This is due to the fact that the amount of w ood residues used in cellulo sic 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 woul d be available today if these residues were
recovered. The United States contains much fore st 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 fo restry 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 valu e 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 milli on gallons from forestry biomass would
be used to meet the cellulosi c biofuel standard under EISA.

Wood Summary

We compared the quantity of potential bioma ss 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 w ould 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 servi ce, 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 wh ich is already being gathered today and typically incurs a fee for its disposal may be among the firs t 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, gl ass, 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 sepa rately 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 rene wable 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 ce llulosic material such as wood, yard trimmings, paper, and much of food wastes. Paper made up the majority of the total MSW generate d in 2008, approximately 31 percent.

Although recycling/recovery rates are incr easing 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 to tal MSW generated fro m 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% ya rd 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): Pa per, 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 ... 15.147 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% pape r, 8% wood, 3% yard trimmings, a nd 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 biofue l use, and therefore report in Table 1.1-21 the percent composition of total MSW discarded after acc ounting 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 (2 008) 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 MS W landfilled is only part of the picture. We also need to understand the types of cellulosic material likel y 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 intere sted 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, we48 estimated the percent composition of MSW landfilled by state using a ratio of percent composition of national material generated (estimated in Tabl e 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 th e volume of MSW (in tons) generated for each state in the year 2022 by the percent of MSW es timated to be la ndfilled (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 potentia lly available is limited by assumptions on percent moisture and percent c ontamination. 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% contam inated, due to objects such as nails, paint, chemicals, etc. typically associated with such feedstocks. 101 Paper and food wastes are assumed to be mostly uncontaminate d, assuming 95% uncontaminated. 102 Yard trimmings are also assumed to be largely unc ontaminated, assuming 75% uncont aminated. We account for contamination because it is likely to affect th e quality of the wood waste and could potentially cause problems in the processing steps of cellulo sic 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 productio n. 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 de molition and renovation, a nd the rest comes from new construction. Roughly equal percentage s 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 am ounts 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 appr oximately 124 million
metric tons. 106 As seen in Table 1.1-22 above, only a por tion 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 pot ential locations that could utiliz e this material. This is
described in more detail in Sec tion 1.8.1.3, the cellulosic ethanol plan t 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 w ould 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 sp lit 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 Feed stocks 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 bioe lectricity. 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 bagass e to be allocated to other uses, including cellulosic biofuel, as additional straw c ould potentially be collected and used to produce bioelectricity.

J Assuming 90 gal/dry ton ethanol conversion yield for urban waste in 202250 In fact, a recent study was performed und er 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 biom ass feedstock potential for sele cted countries outside the United States and projected supply availa ble for export or for biofuel production. K,109 For the study’s baseline projection in 2017, it was estima ted that approximate ly 21 billion ethanolequivalent gallons could be pr oduced 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 cellu losic 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 inte rnal estimate of the types of cellulosic feedstocks projected to be used and their corresponding vol ume contribution to 16 billion gallons cellulosic biofuel by 2022 for the purposes of our impacts asse ssment. 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 2022 L

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 th e 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 inco mes 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. Expans ion of biodiesel mark et volumes beyond the mandates is dependent on it being able to compet e on a price basis with the petroleum diesel being displaced.

The primary feedstock for domestic biodiesel pr oduction 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 feedst ocks 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 don e for this proposal (see Chapter 5 of this document) suggests that soybean oil production w ill 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 th e year 2022 with the EISA mandates indicates that domestic soy oil production would s upport 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 biofue l via simple transesterificati on due to their homogeneity of composition and lack of contaminates.

1.1.3.2 Corn Oil Extracted Duri ng Ethanol Production

A source of feedstock which could provide si gnificant 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 collec tion of processes used to get additional product streams of value from the cor n. 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, star ch, and germ components ahead of fermentation, or alternatively, oil can be extracted from the di stillers’ grains after fermentation. Both have advantages and disadvantages rela ted to plant capital cost and energy consumption, as well as yield of ethanol and the other coproducts. Fo r 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 gr ade 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 w ith several technology pr oviders. 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 co rn flowing into ethanol plants, we assumed approximately 70 percent of proj ected total ethanol production will implement some type of corn oil extraction system by 2022, generating approxima tely 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 recl aimed cooking oils and grea ses 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 dow n 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 Yo rk 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 recovere d 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 producti on 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 doi ng 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 othe r 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 th at 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 appr oximately 22% of this materi al 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 s upported 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 willbe 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 op erations, taking advantage of volumes or prices of feedstock th at 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 accoun t 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 a nd 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 gr ow 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 target ed 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 coul d 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, ca n require low water inputs, can recycle waste streams from other processes, does not compet e with food production, and has high oil yield.

N Algenol 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 th e 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 Spec ies 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 m 2 ) 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 / m 2 / day, due to cold temperatures and native species of algae taking over the ponds. Af ter 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, a nd 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 th e cultivation and processing of algae. With the high price of oil in 2008 and increased inte rest from airline providers to cut costs, fuel companies and start-ups have be gun collaboration efforts to deve lop 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 biom ass-based diesel standard . We believe this is reasonable given several announcements from th e 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 al gae-based biofuels. 118 We discuss some of the information contained in the report, below.

In addition, we have consulted with the Na tional Renewable Energy Laboratory (NREL) on developing several reasonable pathway scen arios 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 comple ted 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 pr ovide further understanding, the modeling completed by NREL also included sensitivity analyses which evaluated various parameters and their affect on the cost s of production (e.g. nutrients required, CO 2 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 uncer tain, 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 documen t 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 al gal system impacts the amount of these inputs needed. Microalgae, which can have a high mass pe rcentage 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 ca rry 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) cu ltivation, heterotrophic cultiv ation (without light), and integrated biofixation systems. P

Due to higher cell densities, the use of phot obioreactors typically has lower land use in comparison to open pond systems producing the sa me volume of fuel. While other oil crops such as soy, sunflower, rapeseed, and jatropha ne ed 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 photobioreact ors, evaporation of water is limited, and water extracted during the drying pro cess 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 es timated 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 magn itude 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, w ith salt concentrations up to twice that of seawater, which is often available in salin e groundwater aquifers in the southwest. 126, 127
However, the salt, other mineral s, and contaminants may pose a problem to the dewatering and extraction process, depending on the method used.

Aside from sunlight, land, and water, algae re quire two main physical inputs for growth:
CO 2 and nutrients. 128 Nutrients can be obtained from conven tional fertilizers, or from domestic or industrial waste sources, su ch as farm refuse and manure. 129 Co-locating algae farms with animal husbandry, in order to directly use the ma nure as a nutrient, would reduce transportation

costs. 130 In addition, both of these inputs can be obtai ned 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 CO 2 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 hi gh 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 alg ae 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 (assu mptions reasonable but still challenging in near57 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 Yield Q (gal/acre per year) Base Case Aggressi ve 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 t echniques include disc rete sedimentation, membrane filtration, phototactic autoconcentration, tila pia-enhanced sedimentation, tube settling, and ultrasonic separation. Wet biomass may also be dewatered or dried. Dewa tering 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), usuall y 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 solven t extraction, supercritical fluid extraction, mechanical extraction, os motic 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) depend ing on the slate of products desired. In some cases, the entire algae biomass is converted us ing thermochemical a nd biochemical methods such as pyrolysis, gasification, liquefaction, a nd fermentation to produce biofuels. See Figure 1.1-6 for the various pathways for th e processing of algal biomass.

Q Only land required for pond/PBR, not including land necessary for processing equipment58 Figure 1.1-6. Pathways for Processing Algal Biomass 141

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 pe rcent 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 particul ar, some potential advantages in clude growth on marginal lands, tolerance to drought, low nutrient a nd 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, insec ticide, 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 c onditions; 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 considered59 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 dr opping 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
CO 2 /mol H 2 O, respectively. 150 This is similar to that of other oil seed species like soybean, with a water use efficiency of 3.90 mol CO 2 /mol H 2 O. 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 efficientl y or economically when it is water-deprived. 152 Obviously, further studies relating water us e 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 monocu ltures of jatropha on soil health has also not been studied thoroughl y. 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, s unflower, 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, a nd 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 leve ls 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 yi elds 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 omeg a-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 winter60 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 Northe rn 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 Ameri ca 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 requir es the use of few, if any, herbicides, as well as little to no tillage 165 . Camelina can also be used to break the continuous planting cycle of small grains, effectively reducing the disease, inse ct, and weed pressure in fields planted with wheat the following year 166 . Camelina seeds contain approximate ly 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 likely 165 . 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 north west. It has several qualities that make it a potential feedstock source for biodiesel producti on. 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 crushed 167 . In addition to the oil, the seeds of pennycress also contain the chemical sinigrin, which has potential uses as a bio-fumi gant. 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 inva sive nature of pennycress. Even though it does not compete directly with summer annual crops due to its gr owing season, there is some concern that, once established, pennycress would be ve ry 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 seve ral 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 future 168 . While the initial attempts to grow pennycress were unsuccessful, more recent on farm trials have
resulted in the successful establishment of pennycress 167 . Pennycress has a large potential as a secondary crop if its cultivati on proves to be profitable.61 1.1.3.6 Imported Biodiesel

In 2007, the EU produced 58 percent of worl dwide 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 ot her climates, is not particularly good for oilseed production. 171 Estimates for future EU biodiese l 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 fu ture biofuels consump tion 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 b illion 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 othe r countries to make up the remaining 5.8 billion gallon demand (after accounting for domestic pr oduction of 2.2 billion gallons as estimated from above). So not only will the EU, the largest curren t 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 biodi esel (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 th e 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 me t, this would mean that approximately 500 million gallons could be available for expor ts 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 a nd 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 biof uels goals. In fact, Malaysia is anticipating biodiesel export opportunities in the European ma rket 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 th e 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 thatthe 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 prof itable if palm oil prices remain high. With Malaysia and Indonesia’s eyes set on importing bi odiesel 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 biodies el from this part of the world.

As described above, another pot ential source of biofuel feed stock is jatropha. Although the potential for India to produce biodiesel fr om jatropha is large, there are still great
uncertainties as to whether India can meet ev en 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 cultiva tion of jatropha has yet to be seen, and that jatropha has unpredictable yields, it seems unlikely that India c ould 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 jatr opha 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 bi odiesel and renewable di esel 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 project ed 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 establishi ng a primary set of fuel types and volumes on
which to base our assess ment of the impacts of the new standa rds. EISA contains four broad categories: cellulosic biofuel, bi omass-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 reas onable renewable fuel volumes based on our best estimate of likely fuels that could come to market.

The following subsections deta il 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 proj ections of renewable fu el volumes without the
enactment of EISA and are described in further de tail 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 fu el 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 nationa l 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 focu sed 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 etha nol-equivalent gallons if necessary (i.e. times 1.5 for biodiesel or
1.7 for cellulosic diesel and re newable 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 de velopments in hydrocarbon-based or so-called “drop-in” renewable fuels as well as butanol, a nd marketplace challenges for consuming high64 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 in terest and potential for such fuels. We have
continued to assume zero volume for renewable fu els or blendstocks such as biogas, jatropha, palm, imported cellulosic biofuel, a nd other alcohols or ethers in our control cases. Although we
have not included these renewable fuels and blends tocks in our impact analyses, it is important to note that they can still be counted under our prog ram 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 vol umes are based on the Energy Information Administration’s (EIA) Annual Energy Ou tlook (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 imp act of increased renewable fuel volumes under EISA as well as fuel economy improvements und er 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 change d since then). Table 1.2-1 and Table 1.2-2
summarize the renewable fuel vol umes 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 s uggesting 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.65Table 1.2-1. AEO 2007 Reference Case Renewable Fuel Volumes (billion gallons)Advanced BiofuelCellulosicBiofuelBiomassBased DieselaOtherAdvancedBiofuelNonAdvancedBiofuelYearCellulosicEthanolcFAMEBiodieselbImportedEthanolCorn EthanolTotalRenewableFuel2010 0.12 0.32 0.29 10.49 11.222011 0.19 0.33 0.16 10.69 11.372012 0.25 0.33 0.18 10.81 11.572013 0.25 0.33 0.19 10.93 11.702014 0.25 0.23 0.20 11.01 11.692015 0.25 0.25 0.39 11.10 11.992016 0.25 0.35 0.51 11.16 12.272017 0.25 0.36 0.53 11.30 12.442018 0.25 0.36 0.54 11.49 12.642019 0.25 0.37 0.58 11.69 12.892020 0.25 0.37 0.60 11.83 13.052021 0.25 0.38 0.63 12.07 13.332022 0.25 0.38 0.64 12.29 13.56aBiomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.bOnly fatty acid methyl ester (FAME) biodiesel volumes were consideredcAEO 2007 reference case assumes actual production of cellulosic biofuel (i.e. not corn ethanol plants utilizing 90% biomass for energy) and thereforewas assumed to be 0.25 billion gallons.66Table 1.2-2. RFS1 Reference Case Renewable Fuel Volumes (billion gallons)Advanced BiofuelCellulosicBiofuelBiomassBased DieselaOtherAdvancedBiofuelNonAdvancedBiofuelYearCellulosicEthanolcFAMEBiodieselbImportedEthanolCorn EthanolTotalRenewableFuel2010 n/a n/a n/a n/a n/a2011 n/a n/a n/a n/a n/a20120.000.3030.007.0467.3520130.000.3030.007.0467.3520140.000.3030.007.0467.3520150.000.3030.007.0467.3520160.000.3030.007.0467.3520170.000.3030.007.0467.3520180.000.3030.007.0467.3520190.000.3030.007.0467.3520200.000.3030.007.0467.3520210.000.3030.007.0467.3520220.000.3030.007.0467.35aBiomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.bOnly fatty acid methyl ester (FAME) biodiesel volumes were consideredcUnder 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 volum es for the primary control case for the years 2010-2022. Although actual volumes and feed stocks 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 feedst ock types within the renewable fu el categories here can be found
in Section 1.1.68Table 1.2-3.Primary Control Case Projected Renewable Fuel Volumes (billion gallons)Advanced BiofuelCellulosic Biofuel Biomass-Based DieselaOther Advanced BiofuelNon-AdvancedBiofuelYearCellulosicEthanolCellulosicDieselbFAMEcBiodieselNCRDdOtherBiodieseleImportedEthanolCorn EthanolTotalRenewableFuelf2010 0.03 0.04 0.61 0.04 0.22 0.29 11.24 12.482011 0.08 0.10 0.72 0.08 0.17 0.16 12.07 13.382012 0.15 0.20 0.92 0.08 0.12 0.18 12.83 14.482013 0.31 0.41 0.92 0.08 0.28 0.19 13.42 15.612014 0.54 0.71 0.85 0.15 0.39 0.20 14.09 16.932015 0.92 1.22 0.85 0.15 0.53 0.39 14.79 18.852016 1.31 1.73 0.85 0.15 0.56 0.63 15.00 20.232017 1.69 2.24 0.85 0.15 0.60 1.07 15.00 21.602018 2.15 2.85 0.85 0.15 0.64 1.51 15.00 23.152019 2.61 3.46 0.85 0.15 0.68 1.96 15.00 24.712020 3.23 4.28 0.85 0.15 0.72 1.88 15.00 26.112021 4.15 5.50 0.85 0.15 0.77 1.81 15.00 28.232022 4.92 6.52 0.85 0.15 0.82 2.24 15.00 30.50aBiomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.bCellulosic Diesel includes 1.96 billion gallons from Fischer-Tropsch Biomass-to-Liquids (BTL) processes and 4.56 billion gallons from this or other types ofcellulosic 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 samepercentage of the total cellulosic biofuel standard as in year 2022, i.e. 31% cellulosic ethanol and 69% cellulosic diesel.cFatty acid methyl ester (FAME) biodieseldNon-Co-processed Renewable Diesel (NCRD)eOther Biodiesel is biodiesel that could be produced in addition tothe amount needed to meet the biomass-based diesel standard.fMay not total due to rounding.69 1.2.2.1 Cellulosic Biofuel

As defined in EISA, cellulosic biofue l means renewable fuel produced from any cellulose, hemicellulose, or lignin that is derive d from renewable biomass and that has lifecycle greenhouse gas emissions, as determined by the Admin istrator, 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 co mprised of other alcohols, synthetic gasoline, synthetic diesel fuel or heating oil, and sy nthetic jet fuel, propane, and biogas. Whether cellulosic biofuel is ethanol will depend on a numbe r 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 s ubsidy, however, gives ethanol producers a considerable advantage over those pr oducing 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 ce llulosic 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 Eur opean market with diesel fuel supply and oversupplying it with gasoline, and based on the re cent 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 c ould 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 in frastructure 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 cellulo sic 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 bioe lectricity. 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 bagass e to be allocated to other uses, including cellulosic biofuel, as additional straw c ould potentially be collected and used to produce bioelectricity. Although in ternational 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 fo r our impact analyses just on domestic supplies.

As discussed, there is uncertainty as to whic h mix of cellulosic biof uels will be produced to fulfill the 16 Bgal mandate by 2022. For asse ssing 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 (B TL) diesel volumes (1.96 billion gallons) using Fischer-Tropsch70 (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-equiva lent gallons, we assume d 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 Po licy 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 dies el (RD) that has not been co-processed with a petroleum feedstock, as well as cellulosic diesel. Althoug h cellulosic diesel produced through the FischerTropsch (F-T) process or other processes could po tentially contribute to th e biomass-based diesel category, we have assumed for our analyses th at 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 sa me 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. Othe r feedstocks assumed to be used by biodiesel plants are fuel-grade corn oil from corn oil extr action, fats, waste oils, and waste greases. For
the FRM we have also included a small volum e of oil feedstock fro m algae for biodiesel production. We note that there are a wide rang e 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 ar e from fats, waste oils, and waste greases. This is because the RD process involves hydrot reating (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 tr ace amounts of free fatty acids or other contaminates which are typical of recy cled fats and greases. In terms of volume availability of feedstocks, supp lies of fats, waste oils, and wa ste 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 ma terial was mixed with petroleum during the hydrotreating operation. EISA specifically forb ids co-processed RD from being counted as biomass-based diesel, but it can s till count toward the total advanc ed biofuel requirement. What fraction of RD will ultimately be co-processed is uncertain at this time, since little or no71 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 renewabl e 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 base d on production plans from Syntroleum.

1.2.2.3 Other Advanced Biofuel

As defined in EISA, advanced biofuel mean s renewable fuel, other than ethanol derived from corn starch, that has lifecycle gree nhouse gas emissions, as determined by the Administrator, that are at least 50% less than baseline lifecycle gree nhouse gas emissions. As defined in EISA, advanced biofuel includes the ce llulosic biofuel, bioma ss-based diesel, and coprocessed renewable diesel categories that were mentioned in Se ction 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 th at 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 assume d 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 bi ofuel and biomass-based diesel would be from imported sugarcane ethanol and perhaps limited am ounts of co-processed renewable diesel. Our
assessment of international fuel ethanol production and demand i ndicate 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., th en there would be suffici ent volume to meet the
advanced biofuel standard. To calculate the amount of importe d ethanol needed to meet the
EISA advanced biofuel standard s, we assumed it would make up the difference not met by cellulosic biofuel, biomass-base d 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 pl ans 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 specificall y 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 wa s cut from $1 a gallon to 50 cents a gallon as part of the credit bill approved by Congress and signed by Presiden t 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, 200872 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 pr ojects 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 th e RFS2 standard. Producti on 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 prod ucing 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 dist ribution costs associated with ethanol’s need to be shipped separately from its gasoline bl endstock 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. Th e 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 ar e 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 combus tion 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 tran sportation 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 combuste d 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 biologi cal 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 approx imately 24 billion ethanolequivalent gallons of biogas (referring to ener gy 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 te rm. 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 configur ed to consume these volumes of biogas. Thus, we expect future biogas fuel st reams 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 sm all 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 th at 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 durin g 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 partie s 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 suffic ient 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 ethano l production exists that is grandfathered and not required to meet the 20% thre shold. 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 imp act analyses conducted for the ru le. The first case, we refer
to as the “Low-Ethanol” control case and assu me 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 1.2-5.75Table 1.2-4.Low-Ethanol Control Case Projected Renewable Fuel Volumes (billion gallons)Advanced BiofuelCellulosic Biofuel Biomass-Based DieselaOther Advanced BiofuelNon-AdvancedBiofuelYearCellulosicEthanolCellulosicDieselbFAMEcBiodieselNCRDdOtherBiodieseleImportedEthanolCorn EthanolTotalRenewableFuelf2010 0.00 0.06 0.61 0.04 0.22 0.29 11.24 12.472011 0.00 0.14 0.72 0.08 0.17 0.16 12.07 13.352012 0.01 0.29 0.92 0.08 0.12 0.18 12.83 14.422013 0.02 0.58 0.92 0.08 0.28 0.19 13.42 15.492014 0.03 1.01 0.85 0.15 0.39 0.20 14.09 16.722015 0.05 1.74 0.85 0.15 0.53 0.39 14.79 18.492016 0.07 2.46 0.85 0.15 0.56 0.63 15.00 19.722017 0.09 3.18 0.85 0.15 0.60 1.07 15.00 20.942018 0.11 4.05 0.85 0.15 0.64 1.51 15.00 22.312019 0.13 4.92 0.85 0.15 0.68 1.96 15.00 23.692020 0.16 6.08 0.85 0.15 0.72 1.88 15.00 24.852021 0.21 7.82 0.85 0.15 0.77 1.81 15.00 26.612022 0.25 9.26 0.85 0.15 0.82 2.24 15.00 28.57aBiomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.bCellulosic Diesel includes 1.96 billion gallons from Fischer-Tropsch Biomass-to-Liquids (BTL) processes and 4.56 billion gallons from this and other types ofcellulosic diesel processes in year 2022. In order to calculate the split of cellulosic ethanol vs. cellulosic diesel in yearsprior to 2022, we assumed the samepercentage of the total cellulosic biofuel standard as in year 2022, i.e. 2% cellulosic ethanol and 98% cellulosic diesel.cFatty acid methyl ester (FAME) biodieseldNon-Co-processed Renewable Diesel (NCRD)eOther Biodiesel is biodiesel that could be produced in addition tothe amount needed to meet the biomass-based diesel standard.fMay not total due to rounding.76Table 1.2-5.High-Ethanol Control Case Projected Renewable Fuel Volumes (billion gallons)Advanced BiofuelCellulosic Biofuel Biomass-Based DieselaOther Advanced BiofuelNon-AdvancedBiofuelYearCellulosicEthanolCellulosicDieselbFAMEcBiodieselNCRDdOtherBiodieseleImportedEthanolCorn EthanolTotalRenewableFuelf2010 0.10 0.00 0.61 0.04 0.22 0.29 11.24 12.512011 0.25 0.00 0.72 0.08 0.17 0.16 12.07 13.452012 0.50 0.00 0.92 0.08 0.12 0.18 12.83 14.622013 1.00 0.00 0.92 0.08 0.28 0.19 13.42 15.892014 1.75 0.00 0.85 0.15 0.39 0.20 14.09 17.432015 3.00 0.00 0.85 0.15 0.53 0.39 14.79 19.702016 4.25 0.00 0.85 0.15 0.56 0.63 15.00 21.442017 5.50 0.00 0.85 0.15 0.60 1.07 15.00 23.172018 7.00 0.00 0.85 0.15 0.64 1.51 15.00 25.152019 8.50 0.00 0.85 0.15 0.68 1.96 15.00 27.132020 10.50 0.00 0.85 0.15 0.72 1.88 15.00 29.112021 13.50 0.00 0.85 0.15 0.77 1.81 15.00 32.082022 16.00 0.00 0.85 0.15 0.82 2.24 15.00 35.06aBiomass-Based Diesel could include FAME biodiesel, cellulosic diesel, and non-co-processed renewable diesel.bCellulosic Diesel is assumed to be zero, while cellulosic ethanol is assumed to be 100% of the cellulosic biofuel standard.cFatty acid methyl ester (FAME) biodieseldNon-Co-processed Renewable Diesel (NCRD)eOther Biodiesel is biodiesel that could be produced in addition tothe amount needed to meet the biomass-based diesel standard.fMay not total due to rounding.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 transpor ting 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 al ready 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 pr ocesses must be deve loped 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 re newable 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 separa tion process if the waste material is separated by the waste pr oducer 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 ma terials before this material may be used. This sorting can be done either by hand or with an automated process. Cleaner stre ams are produced when the waste stream is sorted by hand, however this is a slower and more expensive proc ess. 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 Harvest78 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 industr ies. 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 resi due is mill residue. Mill residue is a waste product of both primary mills, mills that c onvert roundwood into other wood products, and secondary mills, those that produce finished c onsumer 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 collec tion 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 resi dues potentially available is a function of harvest amount, logging met hod, and type and location of timberlands. clxxxvii In addition, residue availabilit y is limited by economic factors. Acco rding to one study, “the actual operations of harvesting, collecting, processing and transporting loose forest residues are costly and present an economic barrier to reco very 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 re covering 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 ch ippers, and sufficient bi omass volume per acre. However, in-woods chipping systems are not as effective when ground-based skidding is restricted or when there are no merchantable prod ucts 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. Th ere are also high costs for wood grinders with low production rates. cxc Fortunately, there have been deve lopments in alternative methods to reduce the costs of biomass collection systems.

There has been much focus recently on devel oping methods of densifying residues in order to increase productivity of handling operations (i.e. hauling, skidding, and loading). New approaches to removing forestry residues ar e currently being evaluated (e.g. slash bundling machines, horizontal grinders, and roll on/off cont ainer 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 sma ller and have greater surface area for potential79weathering. 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, th ere are some difficulties with bundling of brittle residues or s hort, large diameter pieces. In addition, some residues may
include rocks or trash that can result in add itional saw maintenance a nd 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 th innings. 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 fore st 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 feedst ock 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 previ ously 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 Sec tion 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 resi dues 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, su ch 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 ju st 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 gr ain straws that use common hay equipment. One proposal for corn stover harvest is to shut the sp reader off on the grain combine in order to form80 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 ra ke 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 de mand 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 roadsi de, 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 th e ground and pull all of it, e.g., stalks, leaves, cobs, and grain into the combine, where they b ecome 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 fu rther processing and storage. At the elevator, the stover/grain mix is unloaded into equipment for further processi ng 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 stat ionary. 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 r ubbed 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 betwee n 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 gr ain 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 se nse 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 from81 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 fo r 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 re sidues, 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 harveste d, 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 ot her 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 ha ve 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 ch ipped and blown into chip vans for transportation to the biofuel production facility, or bundled usin g the process described above in the forest residue section. It82 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 regu lar spacing of the trees found on tree plantations. In Europe self propelled harves ters 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 used cxciii . 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 dr y before being chipped and used for biofuel production. We anticipate that woody energy cr ops will be harvested using a process optimized to fit the individual woody energy crop plantati on, likely resembling one of the processes just
described.

1.3.2 Feedstock Transpor tation and Storage

Once cellulosic feedstocks have been made available at the roadside, either through collection or harvesting, they must then be tr ansported 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 feedstoc k from the location where it is produced to the biofuel production facility is most dependent on whether the feed stock is available year round
and harvested on an as needed basis or collected or harvested on an annu al 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 feed stock on site, we estimate 3-4 days worth, and additional feedstock can be received regularly di rectly from the producers. Agricultural residues and herbaceous energy crops, however, are harv ested annually or semi-a nnually, and therefore the biofuel producer must be able to store a year s worth of feedstock. Because of the low energy density of cellulosic feedstocks it would not be feas ible 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 stor ing baled feedstock at the roadside on the farms where it is produced. It would then be lo aded onto trucks and tran sported to the biofuel production facility as needed. This method of cellulosic stor age 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 fo r 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 extende d periods of inclement weather. We believe83 that the combination of these factors makes feed stock storage at the site where it is produced unlikely.

Another storage option would be to use sec ondary storage sites. In this method of feedstock storage baled cellulosic feedstock w ould 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 pr oduction facility as needed. Feed stock 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 plan t and the density of the feedstock production. Storing cellulosic feedstock in secondary storag e sites increases the delivered cost of the feedstock, but could be necessary due to the limitations of on farm st orage mentioned above.

In addition to where the cellulosic feedstock is stored, there is also the question of how
the feedstock will be stored. Ma ny different ways of storing th e 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 s hould be stored. Round ba les 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, instab ility of the stack, and dr y matter loss. Square bales, however, can be stacked as many as fi ve 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 st oring 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 feas ible to transport and st ack 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 ed ges 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, whic h 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 feed stock is relatively simple. If the biofuel producer is using MSW that has already been sepa rated, 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. Th is would be done in large ove r-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 be cause MSW is produced and collected year round no secondary storage would be necessary.84 If the biofuel producer is receiving unsorte d MSW it is probable that the sorting facility would be co-located with the biofuel production fac ility. 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 producti on 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 co nsistent 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 th e forestry operation for forest residue and forest thinnings, and transported dir ectly to the biofuel production facility in large over-the-road trucks. For each of the three type s 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 co sts 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 Cr op Transportation and Storage

Unlike MSW and wood residues, which are av ailable to be harvested and collected throughout the course of the year, agricultura l residues and herbaceous energy crops are
harvested on an annual or semi-annual basis. As a result, a la rge 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 agricu ltural 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 wago ns 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 traile rs that can haul net-loads of up to about 45- to 50-tons. However, because the ba le 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 f eedstock, 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 th at 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 de pot 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, and85 merchandising potential. In addition, data supporting the pr eferential deconstruction of feedstock materials due to their bio-composite structure identifies the potential for significant improvements in equipment efficienci es 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 bi ns 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 in to lower transportation costs.

1.3.3 Cellulosic Feedstock Transp ortation and Storage Model

In order to better estimate the impacts of tr ansport 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 plan t-containing county) as well as imported from other areas in the country. The model also provi des us an estimate of the type of feedstock material used by each plant, allowing us to de termine 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 Nati onal Agricultural Statisti cal 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 m odel, see Section 1.1.2 of this RIA. Data for agricultural residues provided by NASS reported harves ted grain values, and needed to be modified to reflect agricultural residue values, using grain to residue ratios cxcvi . 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 farm side to the county centroi d, with consideration for feedstock density within the county as well as the total county area. Furthermore, transport of feedstock between counties (for plants importing f eedstock outside the county they are located in) is based on the distance between county centr oid locations, with an additional factor to account for the added distance of using on-road tr ansportation. 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 co sts in the model are based on the amount of feedstock to be stored, the density of the feedstoc k being stored, as well as the type of feedstock itself. As discussed in Section 1.3.2, the model a ssumes that no secondary storage is necessary86 for either municipal solid waste, which would be transported to the plant directly by waste removal services; or for forest residue, which can be harveste d year-round and transported on asneeded to the plant. Capital costs used in th e model for plant selection are based on current refinery modeling, broken down by PADD locatio n. 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 feed stock availability (by county) based on the
data sources discussed in S ection 1.3.3.1. Using county locations, it builds a list for each county
that contains the locations of other counties w ithin 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 densitie s, total amount of feedstock available, and feedstock type specific to each county. Using th is 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 countie s. At the end of this step in the model operation, each county has a datapoint in the mo del 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 informat ion for each feedstock available to a county.
These costs include the farmside cost of the f eedstock, the transportation required to move the feedstock to the centroid of its own county and th e secondary storage of that feedstock. If the feedstock is available by import from a neighborin g 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 mode l operation, each county datapoint contains a list detailing the total cost of each f eedstock available as they would be delivered to that county.

In the next step of the model operation, the lis t of feedstock availability cost is used to choose feedstocks that a plant locat ed 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 f eedstock 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 feed stock sources to a county by selecting the next cheapest feedstock on the list. Selection proceed s 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 e nd 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 is87 removed as a source from any feedstock availabilit y list used by other counties. The model then repeats using this modified feedstock data, st arting 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 tota l 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 estima te 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 contri bution of capital cost is known for each of the estimated plants (as these are inputs to the mode l), 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 thes e 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 aver age number of plants selected for the southern88 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 va riations of plant c onstruction and operation costs. The lower capital cost in the southern re gion (most likely due to existing construction
infrastructure for conventional oil refineries) reduces the overall pri ce 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 devel oped over time, the model can be easily adjusted and updated to ta ke into account this new information.



### 1.4 Biofuel Production Technologies

Biofuel production technologies continue to evolve with rese arch and development efforts focused on reducing costs and increasing efficiencies. Improvements include increasing conversion yields for various feedstocks, reducin g 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 comp ete 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 conve rting 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: distille rs 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 prio r to processing into its component parts and produce other co-products (usually gluten feed, glut en meal, and food-grade corn oil) in addition to DGS. Each process is described in great er 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 Technology 197

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 gr ound into course flour also know as “meal.” Next the meal is cooked to physically and ch emically 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 li quefaction, which occurs in two steps. First the hot slurry is pumped through a pressurized jet cooker at approximate ly 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 hour s 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 adjus tment 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 glucoamy lase 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 th e time the product stream leaves the distillation columns, it contains about 95% ethanol by volum e (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 pro cess is dehydration to remove the remaining 5% water. The ethanol is passed through a molecu lar sieve to physically separate the water from
the ethanol based on the different sizes of th e molecules. The result is 200-proof anhydrous (waterless) ethanol. At this poi nt, 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 fermen t 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 sc rubber 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 a dded during the process. It is separated via centrifuge into thin stillage (a liquid w ith 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 require d 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. Th is 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 ea sily 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 th e 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 dr ying system to remove moisture and extend the shelf life. The resulting dried distillers grains with solubles (DDGS) ar e commonly used as a high-protein ingredient in cattle, swine, poultry, a nd 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 Technology 198

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 th e separation of the corn kernel into germ, fiber, gluten, and starch.

After steeping, the corn slurry is processed th rough 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 co rn oil for use in cooking applications. The remaining fiber, gluten and starch components ar e further segregated using centrifugal, screen, and hydroclonic separators.

The steeping liquor is concentrated in an ev aporator. 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-frien dly alternative to salt for removing ice from92 roads.

The gluten component (protein) is filtered a nd 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 ma sh is generally processed in one of three ways: fermented into ethanol, dried and sold as dr ied or modified corn st arch, or processed into corn syrup. If made into ethanol, the fermenta tion process is very similar to the dry mill ethanol production process described above . A schematic of the wet millin g 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 expl oring new technologies with the potential to increase their profits by producing higher valu e co-products and reducing the ethanol plants energy requirements. Dry fractionation and corn o il 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 requirement s are two of several new technologies focusing on reducing the energy usage of ethanol produc tion 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 descri bed in more detail below.

Dry Fractionation93 Dry fractionation is a mechanical separation of the corn kernel into its three component pieces, the germ, bran, and endosperm before fermentation. This se paration decreases the
amount of non-fermentable material sent through the process and allows each of the components to be processed separately to produce new, high er-value co-products. As shown in Figure 1.4-1, the germ is the small, non-fermenta ble 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 contai ns 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 material s (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 d ecreasing 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 incr eases by approximately 2-3% due to starch loss in the fractionation proces s. Dry fractionation is also a capital intensive process, costing an estimated $35 million to a dd 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 anal yses we have assumed an oil recovery rate of 50% for ethanol plants that use dry fractionati on. Several companies, including ICM, Delta-T, and POET currently offer dry fractionati on options for new or existing plants.

Corn Oil Extraction 199

An alternative method to recovering the oil contained in the corn kernel is corn oil
extraction. Corn oil extraction is a method of mech anical separation, often by centrifuge, used to extract the crude corn oil from the thin stillage (the non-ethanol liquid le ft after fermentation), the DGS before it has been dried, or a combinatio n of both. While the corn oil is of a lower quality and value than that produced from corn fr actionation, 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 losse s 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 o il 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 gene rating an additional reve nue stream, extracting the
corn oil has several other benef its 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 and94 concentrates its protein content. The de-fatte d 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 gr eater 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 Fermentation 200201

POET Biorefining, the United States’ largest corn ethanol producer W , has developed a cold starch fermentation process that uses raw-star ch hydrolysis to convert starch to sugar, which
then ferments to ethanol w ithout 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 additiona l starch for conversion to ethanol, increases protein content and quality of co-products, increases co-product flowability, potentially increases plant throughput, and signific antly decreases plant emissions. The benefits of the process include reduced energy costs, in creased 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 additi onal benefit of the cooki ng process is that it sterilizes the starch slurry before fermentati on, killing microorganisms a nd neutralizing toxins
that are often contained in the corn. Without this step, the microorganisms may compete with the yeast, lowering ethanol yields. Toxins ma y 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 Siftek TM technology. Siftek TM

membranes have been successful ly 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 th eir Chatham, Ontario plant, which produces 187 million liters of ethanol per year, by the end of 2008. Vaperma claims its Siftek TM membranes are capable of producing a fuel grade ethanol product from an ethanol/water mixture that
contains as much as 60% water. These membrane s would replace the rectifier unit as well as the
molecular sieves used in a conventional et hanol plant, potentially reducing the energy consumption of the ethanol dehydration proc ess 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 usua lly recycled to the rectifier and makes up approximately one third of the feed to the rectifying column. Using Siftek TM technology to treat
this stream reduces the feed to the rectifie r, 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 etha nol 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 me mbrane 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 se paration. 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 Power 202

Ethanol production is a relatively resource-in tensive process that requires the use of water, electricity, and steam. In most case s, water and electricity are purchased from the municipality and steam is produced on-site using bo ilers 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 a nd power (CHP) technology. CHP, also known as cogeneration, is a mechanism for improving overa ll 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 gene rator unit that produces electricity, and using waste heat to make process steam. In some case s, 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 conve ntional plant, the additional energy used is far less than what would be required to produce the same amount of electric ity 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 so lely by the ethanol plant, or jointly operated with the local utility company. In th ese 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 ener gy costs for both parties, as well as reducing the green house gas emissions that would be produced by opera ting 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 gran t 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 pot ential alternative boiler fuel is biogas produced by the anaerobic digestion of the stillage in th e 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, howev er all revenue from DGS sales would be lost. Whether or not these systems are a dopted in the future is likely to be dependent97 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-term Y 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 suga rcane 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 re quire additional steps before sugars are released for use in the fermentation step.

In the production of sugarcane ethanol and su gar 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 left over 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 ev aporated in vacuum pans and seed crystallized, leading to a mixture of sucrose crystals su rrounded by molasses with a concentration of 91- 93°Brix. The sugar crystals and molasses are s ubsequently separated by centrifugation. In ethanol production in Brazil, the sugars in the juic e are fermented into ethanol by the addition of yeast. Fermentation varies from 4-12 hours, w ith ethanol yields ranging from 80-90%. The fermented mixture is then distilled to produce hy drous (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 a nd export) or ethanol depends on the supply and demand changes for both products.

Figure 1.4-5. Simplified Overview of Sugarca ne 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 sugarc ane are commonly referred to as trash. Sugarcane trash in Brazil is not currently harveste d (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 ther e 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 afte r 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 elect ricity. U.S. factories and ot her 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 displ aces 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 etha nol distillation process. It is rich in minerals, organic material, and water. Some c ountries 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 legisla tion 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 a nd thermochemical proc esses while Section 1.4.3.2 discusses cellulosic diesel which is produced th rough thermochemical processes. We end the section with specific company desc riptions of cellulosic biofuel t echnologies 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 ma y have been one of the earliest to try commercializing a process to produce ethanol fr om a cellulosic feedstock, probably from wood in the late 1890s. They used dilute acid to hy drolyze the cellulose to glucose and xylose, but were able to only produce a little less than 20 gall ons 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 hydr olysis were constructed in the U.S. Lumber production decreased following World War I, whic h resulted in the closing down of cellulosic plants. 204, 205 Although corn-grain ethanol was used in the early 20 th 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 au tomobiles and light-duty trucks. From the early 1970’s and up through the present, ethanol from co rn, has been increasingly used as a fuel; however, recently, ethanol from cellulose is being viewed with increasing interest.

Several processing options are currently av ailable to convert ce llulosic biomass into ethanol. These conversion technologies generally fall into two main categ ories: biochemical and
thermochemical. Biochemical conversion refers to the fermentation of sugars liberated from the
breakdown of biomass feedstock. Thermochemic al conversion includes the gasification and pyrolysis of biomass material into a synthesis gas or liquid oil for subs equent fermentation or catalysis. The main benefit of gasification/ pyrolysis over the biochemical route is that thermochemical processes can more easily c onvert 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 thermochemi cal process does have some drawbacks, such as tar production and clean-up gas procedures that re quire additional capital
investment.

Since commercial production of cellulosic etha nol 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 biochemic al and thermochemical ethanol processing plants. In addition, some investors are currently supporting research and development in both cellulosic processing proced ures, 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 carboh ydrate is starch, li gnocellulosic biomass is composed mainly of cellulose (40-60 %) and hemicellulose (20-40 %). The remainder consists of lignin, a complex polymer which se rves 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 fe edstocks must be hydrolyzed prior to
fermentation. Structural diffe rences at the molecular level make it far more difficult, and therefore more costly, to hydrolyze cellulosic biom ass than it is to hydrolyze starch. Glucose,
C 6 H 12 O 6 , the repeating monomer in both starch and cellulose, is a six-sided ring, similar in
conformation to the classic ‘cha ir’ conformation of cyclohexane or benzene, except one carbon atom in the ring is replaced by an oxygen at om. For uniformity (and ease) of discussion, it is generally assumed that the first carbon atom ne xt to the oxygen, is carbon #1; the numbering, 2- 5, continues around the ring with oxygen in the 6 th position; one of the four bonds of the fifth carbon atom is attached to the oxygen atom to co mplete the ring, one is attached to hydrogen
atom and the fourth to a -CH 2 OH group. Thus, a glucose molecule/monomer is a six-sided molecule, but not a six-carbon ring (although th ere 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 approx imately one in twenty-five glucose units. 209 The -OH groups on the same side of the polymer, along wi th 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 de velop between adjacent polymers to form tight, rigid, strong, mostly straight polymer bundles calle d 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 hemic ellulose. It consists mainly of a random mixture of highly branched and heavily substitu ted 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 uroni c and acetic acid. Hemicellulose is not as rigid or strong as cellulose, but does contribute add itional 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 fr om coniferyl alcohol by extensive condensation101 polymerization. Covalently bonded to the hemicellulose, it is essen tially a glue-like polymer that
covers the cellulose and hemice llulose polymer cell walls and he lps 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 proces s 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 pl ant cell walls through conde nsation reactions. In general, condensation is a chemic al process by which two molecule s 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 cat alyzes 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 (H 2 O or water) molecule is removed leaving an -O- that links the monomers together to form the polysaccharide ch ain. Again, depending on the direction of the – OH group at carbon 1, it may be called an alpha (a s 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 glucos e 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. Th ese are two of the major problems that must be satisfactorily resolved for biochemical c onversion 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 devel oped and is being pursued to co mmercialization in certain niche situations. For example, concentrated acid hy drolysis 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 r ecovery. Refer to Figure 1.4- 6 for an illustration of the enzymatic biochemical production process. We used NREL’s study as102 a guide to describe, somewhat generically, how su ch 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. 219103 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 chemical s to make the biomass mo re 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 appro aches 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 in hibit microorganisms in the fermentation step. A well known pretreatment method that does not degrade biomass sugars or produce
fermentation inhibitors is amm onia fiber expansion (AFEX). Du ring AFEX, liquid ammonia is
added to the cellulosic material followe d by a rapid pressure release.

Each type of feedstock, whether softwoods, co rn stover or bagasse, requires a particular combination of pretreatment me thods 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 a nd Hydrolyzate Conditioning

NREL refers to this stage as a combinati on of pretreatment and hydrolysis. In their process flow diagram, the washed and sized-redu ced 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 smal l amount of glucan in the hemicellulose and in the cellulose is converted into glucose. The rundo wn 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 gy psum and other contaminants that would be toxic to downstream enzymes. The cake is wa shed, 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 ‘Sim ultaneous Saccharifica tion and Fermentation’ (SSF). Saccharification, in the process we’re disc ussing, 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 elevated104 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 cellulo se 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 manufactur ers. 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 re search 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 compar able to those used to produce ethanol from corn grain at a cost of 3 to 4 cents per gallon of et hanol. 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 multi ple feedstocks, in which variations are more likely.

Following cellulose saccharification, both the glucose and xylose sugars are cofermented. Although xylan, the hemicellulose polys accharide, 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 viab ility 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 st ep 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 ne cessary. 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 la g in the development of molecular biological methods to manipulate organisms th at secrete cellulases naturally. 229

Stage 4 – Ethanol Dehydration

NREL’s process model indicates that th e fermentation reactor rundown stream, now called ‘beer,’ runs down the beer column feed su rge tank. The beer column feed consists of105 about 83% water and only 5.5% ethano l; the balance of the mixture is very complex, but consists mostly of lignin. The beer column removes the dissolved CO 2 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 mo stly water with about 0.05% ethanol that’s recycled back to the process. The rectifica tion column overhead that consists of about 92.5% ethanol and 7.5% water, is fed to a molecula r 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% insolubl e solids is essentially lig nin microbial cells, and other unconverted biomass remnants, (e.g., cellulo se, xylose, glucan, xylan, other oligomers, etc.,) from the process. This material can be either combusted to provi de process heat for the biochemical operation for a co-locat ed starch ethanol plant, or as we discuss in the following section, could be used as feedst ock for a thermochemical unit.

1.4.3.1.2 Thermochemical Conversion

Thermochemical conversion involves bioma ss being broken down into intermediates using heat and upgraded to fuels using a combin ation of heat and pressure in the presence of catalysts. 230 Thermochemical processes include pyro lysis (absence of oxygen), gasification (partial oxidation in the presence of a gasifying agent, usually air, oxyg en, 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 al so applicable to other feedstocks (e.g., coal or natural gas); the only difference is that a renewa ble feedstock is used (i.e. biomass) to produce
cellulosic biofuel. A thermochemical unit can al so complement a bioche mical processing plant to enhance the economics of an integrated bior efinery 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 use d, based on availability of long-term suppliers, seasonal availability, harvest cycle, and costs. Agricultural residue, energy crops, wood residues, and municipal solid waste are a ll being considered as potential feedstocks. Geographic location, availability of biomass, the existence of bioma ss suppliers, and costs would all likely influence the mix of biomass feedstocks utilized. The general steps of the gasification thermochemical process include: feedstock handling, gasificati on, gas cleanup and conditioning, fuel synthesis, and separation. Refer to Figure 1.4-7 for a sche matic of the thermochemical cellulosic ethanol production process through gasification. For greater detail on the th ermochemical mixedalcohols route refer to NR EL technical documentation. 232106 Figure 1.4-7.
Cellulosic Ethanol Thermochemical Gasification Process

Stage 1 – Feedstock Handling

The particle size requirement for a th ermochemical process is around 10-mm to 100-mm
in diameter. 233 Once the feed is ground to the proper si ze, 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 leve l 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 re action 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 expe nsive and typically requires large plant sizes to improve economics.

The second general class, ca lled 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 ga s can be combusted with air (external to the gasifier itself) to provide the energy required fo r gasification. Although steam gasifiers have the107 advantage of not requiring oxygen, most operate at low pressure and therefore require product gas compression for downstream purific ation 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 fl uidized 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 fluidi zed 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 us ing biomass as a feedstock, a second reactor is
sometimes added which solely targets converting the tar to sy n-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 medi um energy content depending on the gasifying agent and consists mainly of CO, H 2 , CO 2 , H 2 O, N 2 , and hydrocarbons. The minor components, tars, sulfur, nitrogen oxides, alka li metals, and particulates have the potential to negatively affect the syngas conversion steps. Therefore, unwan ted impurities are removed in a gas cleanup step and the gas composition is further modified dur ing gas conditioning. Gas conditioning steps include sulfur polishing to remove trace levels of H 2 S and water-gas shift to adjust the final

H 2 /CO ratio for optimized fuel synthesis.

Stage 4 – Fuel Synthesis

After cleanup and conditioning, the “clean” sy ngas is comprised of essentially CO and

H 2 . 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 th e choice of producing diesel fuel or alcohols from syngas by optimizing the type of catalyst used and the H 2 /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 cu rrently available for ethanol production, it may be economically advantageous for fuel producers to convert syngas to ethanol instead of to diesel108 fuel. Production of cellulosic diesel is discu ssed in further detail in the following Section
1.4.3.2.

Conceptual designs and techno-economic m odels have been developed for ethanol production via mixed alcohol synthesis using cataly tic processes. The proposed mixed alcohol process produces a mixture of ethanol along w ith higher normal alcohols (e.g., n-propanol, nbutanol, and n-pentanol). The by-product hi gher normal alcohols have value as commodity chemicals and fuel additives. Typically the mix ed alcohol products are high in methanol, but
contain a wide distribution of seve ral different alcohols. One concept proposed in literature is to completely recycle this metha nol 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 tota l alcohol product was etha nol. This was made possible through the addition of an almost comp lete recycle of methanol within the process. 236
For the final rule, we worked with NREL to develop the thermochemic al 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 materi als 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 fast er 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 se parator 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 al cohol 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, st eam generators, and super-h eaters generate steam that drives turbines on compressors and elect rical 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 technolog ies 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 th e thermochemical ethanol process described previously, the BTL process produces a syngas fro m biomass. However, instead of reacting the syncas to alcohol, the syngas is fed to a Fische r-Tropsch (FT) reactor to primarily produce diesel fuel and some naphtha. 241

The BTL method removes contaminants fro m 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 maki ng 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 coupl e of steps of BTL plants, including biomass processing and gasification, are similar to the ther mochemical cellulosic et hanol 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 su ch 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 nece ssary 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 catalys t. The FT catalyst is either iron-based or cobalt-based. The cobalt catalyst is more expensive, although it doe s not require a recycle, while the less expensive iron catalyst does require a recy cle. 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 component s based on their vapor pressure , mainly liquid petroleum gas (LPG), naphtha, distillate and wax fractions. The heavier co mpounds 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 eith er 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 su ch 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, t hus 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 pr oduced varies in oxygen content or viscosity according to the feedstock used. The oil must have particulates and ash re moved in filtration to create a homogenous product and is further upgrad ed 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 technol ogies 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 eas es 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 we re 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 Pr oduced 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 technolog ies capable of meeting either th e advanced biofuel or cellulosic
biofuel RFS standard. The followi ng sections describe specific companies and the new biofuel technologies which the companies have develope d or are developing. This summary is not112 meant to be an unabridged list of new biofuel tech nologies, but rather a description of some of the more prominent or interesting of the new biof uel technologies that serv e 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 hydrocar bon fuels from sugars through biochemical reactions. The technology uses cu stom 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 th eir 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 c onstruction of a pilot plant as we ll as a commercial demonstration plant in Brazil to showcase their technology. Am yris 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 provide s better storage and cold flow properties than
biodiesel.

Biochemical to Diesel Fuel - Bell Bio-Energy

Bell Bio-Energy has developed a bioche mical technology which uses genetically engineered bacteria to convert cellulosic feedst ocks directly to synthetic hydrocarbon fuels and compost. Depending on the types of bacter ia 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 exam ple, 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 comple ted their development work, they discussed their technology with the Departme nt of Defense which became inte rested in this technology for providing fuels to their land and air based vehi cles. 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.113 The technology works by first grinding the ce llulosic 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 rene wable product per ton of feedstock and the simplicity of the process results in low capital costs per volume produced.

Strong Acid Hydrolysis/Bioch emical - BlueFire Ethanol

BlueFire Ethanol has a commercial strong acid hydrolysis technology process that
converts cellulosic materials into ethanol. Th e technology can make et hanol from urban trash, rice and wheat straws, wood waste and other agricultu ral residues. Acid hydrolysis is the main
reaction mechanism to convert cellulosic and hemice llulosic material into simple sugars such as hexose and pentose or "C6 and C5" sugars. Ferm entation of these sugars with microbes converts these sugars into ethanol. This process for conve rting cellulosic and hemicellulosic material into ethanol via acid hydrolysis and fermentation ha s 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 etha nol yields and lower production costs.

BlueFire uses a proprietary concentrated aci d hydrolysis system and several other process improvements to make ethanol production more economically attractive than older acid hydrolysis methods. Some of BlueFire’s stat ed 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 consis ts 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 seekin g 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 munici pal 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-Energy114 The Cello-Energy process is a catalytic de polymerization technology. At moderate pressure and temperature, th e Cello-Energy process catalytically removes the oxygen and minerals from the hydrocarbons that comprise cellulo se. This results in a mixture of short chain (3, 6 and 9 carbon) hydrocarbon compounds. Th ese 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 meet s 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 c onvert 94% of the hydrocarbon material to diesel fuel, although a very small amount of h eavier 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 pr ocess 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 af ter 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 milli on gallon per year commercial demonstration plant. As of late 2009, the plant is operationa l, 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 produc tion to 20 MGY from a previously operated demonstration plant. As of November 2009, they had ordere d new equipment and are waiting
for it to arrive and be installe d which they hoped would allow for operations to be restarted as early as February or March, 2010. Cello energy already has chosen loca tions 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 Al abama. Cello explained that they will use prefabrication techniques so that th ese plants can readily be constructed, shipped and installed anywhere in the U.S.

Thermochemial/Fischer Tropsch - Choren115 Choren has a technology called Carbo-V, which is a Fischer-Tropsch process that can be used to make diesel fuel. The process can pro cess a wide variety biomass and recycled material materials as feedstocks. The process converts ag riculture 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 Car bo-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, hi gh temperature gasifi cation and endothermic entrained bed gasification. In the first stage, biom ass 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 in to 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 gasi fication 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 hy drocarbons produced from the three stages can then be sent to a hydrocracking proc ess 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. Initia lly, 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-ba sed technology which produces ethanol from biomass and other forms of carbon through a bi ofermentation route. A wide variety of feedstocks can be used, municipal waste, agri culture waste and other carbonaceous containing material. Since this process uses combustion and biofermentation, it is not easily classifiable as either a biochemical or thermochemical produc tion 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 fe ed stocks into syngas, comprised primarily of carbon monoxide and hydrogen. The syngas pr oduced 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 ener gy costs. Additional energy savings can be realized by employing membrane technology to se parate ethanol from the reactor decant liquid. This technology uses gravity and filtration to re cover ethanol, resulting in significant savings on distillation capital and energy costs used in othe r cellulosic and corn based production methods.116 Initial ethanol production cost es timates are lower than the bioc hemical and thermochemical cellulosic technologies described in pr eviously 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 operati onal 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 gene ration and transportation ve hicles. 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 ca n be processed. The fuel produced from the Dynamotive process is called “BioOil” and cont ains 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 di rectly useable as fuel in conventional vehicles
and would have to be converted via another cata lytic 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-meth anol via a catalytic reaction (the BTL process). The diesel fuel produced is expected to be compa tible 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 (1 0-20% wt.). The char produced is similar to coke and can be used as fuel by other industrie s while the gases yielded from the process can be used to supply about 75% of the energy requireme nts of the pyrolysis process. The pyrolysis process operates at reactor temperatur es 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 dr y 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 ca pacity between the two plants is estimated at around 9 MGY of bioOil, but both plants are curr ently 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 Dynamotive117 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 c onventional ethanol in 23 plants in seven states with production capability of one billion ga llons of ethanol annuall y. POET has expanded their production capability to include cellulosi c ethanol technology. POET’s cellulosic technology will make ethanol from plant materials like corn stalks , switch grass, wood chips and refuse. In February 2007, PO ET was selected by DOE for an award totaling $80 million for federal funding for a commercial cellulosic ethano l 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 En ergy, 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 de monstration cellulosic ethanol plant in North America. Iogen’s plant located in Ottawa, Ca nada 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 drama tically 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 cellulo sic ethanol producer to sell its advanced
biofuel at a retail service stati on in Canada. Their cellulosic et hanol was blended to make E10
available for sale to the consumers at an Otta wa Shell station. Iogen also recently announced plans to build its first commercial scale plan t 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 w ill involve the production a nd 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 biochemic al conversion of cellulosic material into ethanol. DDCE received funding fr om the State of Tennessee and th e 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 comme nced in October 2008 and the plant is now mechanically complete and currently undergoing st art-up operations. The facility is scheduled to come online in January and the company hope s 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 MS W 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 onl y fractionates MSW but biological ly 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 a nd build other small comme rcial 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 ove r 7 years using over 20 different nonfood feedstocks. Range broke ground building its firs t 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 cap acity to convert the methanol to ethanol.

Enerkem is another company like Range Fuel s pursuing cellulosic ethanol production via
the thermochemical route. The Canadian-based company was recently announced as a recipient119 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 sche duled 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 starte d 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 expr essed 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 i ndustry. While refinery-based reforming raises natural gasoline’s octane value a nd 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 w ith 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 technol ogy, as production costs estimates are low in comparison to many other renewable and biom ass 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, ce llulose 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 su gar 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 ar e 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 pr essures 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) linke d 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 fo rm methyl esters. Glycerin is formed as a coproduct from the three-carbon backbones that remai n. 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 a nd pressure conditions.120 Figure 1.4-9. Overview of bi odiesel 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 ex tracted after ethanol pr oduction, addition of base will result in the formation of soap, an undesirabl e process contaminate when present above trace levels. To avoid this, these feedstocks must firs t undergo an acid pre-treatment step to esterify the FFAs before proceeding to the base-cataly zed triglyceride transe sterification reaction. Feedstocks with small amounts of FFAs may be c onverted 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 recovere d. 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 pr ocess 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

triglyceride121 Figure 1.4-10. Schematic of typical biodie sel production from virgin plant oil

Some differences exist between large and sm all 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 empl oy continuous flow processes, which afford
certain efficiencies of scale a nd 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 tig hten 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 th e 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 th e future. That said, it is worth noting some potential changes as existing plants strive to comp ly 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
Product Filter

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
Product Filter122 One such change may be an increase in distillation of biodiesel. EPA requires biodiesel to meet the ASTM D-6751 specifica tion 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 finish ed 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 ensu re a high purity product is through distillation.
At this time it is unclear to what extent di stillation 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 a nd 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 pro cess complexity and per-gallon energy use.

1.4.4.2 Renewable Diesel

The renewable diesel production process conv erts 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 hy drogen and catalyst to remove oxygen from the triglyceride molecules in the feedstocks oils via a decarboxylation and hydro-oxygenation reaction, yielding some light pe troleum 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 pa raffins to create fuels with varying properties.
All of these reactions consume si gnificant amounts of hydrogen. The yield of these reactions to the primary product (diesel) de pends on the process conditions, as some of the carbon backbone
of the oils can be cracked to na phtha and lighter products with high er 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 diagra m of the primary steps of renewable diesel production.123 Figure 1.4-11. Process flow diagram of prim ary 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, LL C (a joint venture of Syntroleum Corp. and Tyson Foods, Inc.) announced constr uction of a 75 million gallon per year plant (5,000 bbl/day) in Geismar, Louisiana, that will us e 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 w ith 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

reactor124 They have further adapted this process to use a variety of fats and oils as feedstocks, calling it Bio-Synfining. It is this technology th at will be used in the Geismar facility.

Looking internationally, the Finnish co mpany 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 hydr ocarbon fuels from fats and biomass is a relatively new endeavor to conduct on a commercia l 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 st ate of the biofuel industry and how production might grow in the future under the RFS2 prog ram based on our volume assumptions. The bulk of the discussion focuses on corn ethanol, impor ted sugarcane-based et hanol and conventional FAME-based biodiesel, today’s most establishe d 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 deve lop during the course of the RFS2 program.

In the subsections that follow, we’ll discu ss 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 ther e we will discuss the availability of imported
ethanol from Brazil and Caribbean Basin Initiative (CBI) countries to help meet the advanced
biofuel standard. Dome stic sugarcane- and sweet sorghum-b ased ethanol plants could also contribute to meeting the advanced biofuel standard in EISA. Fo llowing this discussion, we will characterize the present state of the cellulosic biofiuel industry and talk about the projected
timeline for commercialization base d on industry plans and technol ogical breakthroughs aided by state and federal grants, tax incentives, and loan guarantee programs. As part of this
discussion we will describe our a ssessment of the cellulosic industry in the context of setting the standard for 2010. Finally, we will conclude our industry charac terization by discussing the present state of the biomass-ba sed diesel industry and how we expect biodiesel production to grow in the future along with renewa ble diesel and algae-based biodiesel.

1.5.1 Corn Ethanol

The majority of domestic biofuel production cu rrently 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 pr ocessing 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 et hanol producer in the world. In 2008, the U.S. produced nine billion gallons of fuel ethanol fo r 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 gr own exponentially over the past decade.

Figure 1.5-1.
Historical Growth in U.S. Corn/Starch Ethanol Production 250

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

19 99 20 00 20 01 2002 20 0 3 20 04 20 05 2006 2007 20 0 8

YearCorn/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 cr edit, 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/sta rch ethanol plants operating in the U.S. with a combined production capacity of a pproximately 12 billion gallons per year. 30 This does not include idled ethanol plants, discussed later in this subsec tion. 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 processi ng waste beverages or other waste sugars and starches. A summary of U.S. ethanol producti on 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 % o f Capacity No. o f

Plants % o f

Plants

Corn a 

### 10,994 91.5% 155 86.1% Corn, Milo b 

### 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 Beverages c 

### 20 0.2% 5 2.8% Waste Sugars & Starches d 

### 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 opera ting plants, 173 process corn and/or other similarly processed grains. Of these facilitie s, 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 num ber 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 pate nt-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 de signed 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 ex isting ethanol plants more sustai nable. For more information
on corn oil extraction and other advanced technol ogies 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 co mes 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 Midland a 

### Cedar Rapids, IA 250 2.1%
Archer Daniels Midland a 

### Clinton, IA 190 1.6%
Archer Daniels Midland a 

### Columbus, NE 95 0.8%

Archer Daniels Midland a 

### Decatur, IL 290 2.4%
Archer Daniels Midland a 

### 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 proce ss waste beverages or sugars/starches and operate differently than their grain-based count erparts. 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 pl ants 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. o f

Plants % o f

Plants Avg. Size
MGY Dry Milling a 

### 10,618 88.3% 162 90.0% 65.5 Wet Milling a 

### 1,376 11.4% 11 6.1% 125.1
Other b 

### 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-i ntensive 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 gas 33 (exclusively), three burn a combination of natural gas and bi omass, one burns natural gas a nd 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 exis t. 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 th e 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 etha nol 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 % o f

Plants CHP

Tech.

Coal a 

### 1,758 14.6% 17 9.4% 8 Coal, Biomass 50 0.4% 1 0.6% 0
Natural Gas b 

### 9,706 80.7% 152 84.4% 14 Natural Gas, Biomass c 

### 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 Heat d 

### 50 0.4% 1 0.6% 1

Waste Heat d 

### , 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 pro cess, large amounts of carbon dioxide (CO 2 ) gas are released. In some plants, the CO 2 is vented into the atmosphere. But where local markets exist, it is captured, purified, and sold to the food proc essing industry for use in carbonated beverages and flash-freezing applications. We are currentl y aware of 40 fuel ethanol plants that recover
CO 2 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 CO 2 per year which translates to
about 5-7% of all the CO 2 produced by the industry. 36

Since the majority of ethanol is made from co rn, 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
MG Y % o f Capacity No. o f

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 ar e 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 PA DD 2, there are a growing number of plants
situated outside the traditional Corn Belt. Our November 2009 industry assessment indicates that Arizona, California, Colo rado, 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 Mi dwest, 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 % o f

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 comp rised 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 th e total domestic product comes from 40 plants owned by just three different companie s – 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 A rcher Daniels Midland, 1,100 POET Biorefining, 1,535

Hawkeye Renewables,
460

The Andersons, 275 Glacial Lakes Energy, LLC, 250 A ventine Renewable Energy, 207

BioFuel Energy Corp., 230 Other, 6,714

Valero entered the ethanol industry in Ma rch 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 th e 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, dome stic ethanol production is project ed 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, provide d 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 require ment, EISA allows for 15 billion gallons of the

37 Valero recently announced that it has purchase agreemen ts 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 me t by conventional biofuels. We expect that corn ethanol will fulfill this requirement, provided it is more cost competitive than imported
ethanol or cellulosic biof uel in the marketplace.

In addition to the 180 aforementioned corn/s tarch ethanol plants currently online, 27 plants are presently idled. Some of these are smal ler 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 a ll together (e.g., VeraSun) whereas others are using bankruptcy as a means to protect themselv es 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 2 009, 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 we ll. Since our April 2009 industry assessment used for the NPRM, nine corn ethanol pl ants have come back online.

For analysis purposes, we assumed that a ll 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 projects 40 currently under construction or in advanced stages of planning would come online. This include s 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

Plants a Under

Construction b Planned Exp. o r DOE-Funded
Projects c 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 plant 41 , the rate at which new plant capacity comes online will be dict ated 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 reach ing 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 prog ram, 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 re quired 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. o f

Plants Capacity

MGY No. o f

Plants Barley 65 1 65 1

Corn a 2,549 30 13,543 185 Corn, Milo b 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 Beverages c 0 0 20 5 Waste Sugars & Starches d 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 plants 43 , 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 curr ently 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. o f

Plants Capacity

MGY No. of

Plants CHP

Tech.

Biomass 88 1 88 1 1

Coal a 550 2 2,308 19 10 Coal, Biomass 0 0 50 1 0 Manure Biogas 139 2 139 2 0
Natural Gas b 2,130 33 11,836 185 16 Natural Gas, Biomass c 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 lik ely drive a number of ethanol producers to pursue CHP technology. For more on our projected 2022 utilization of th ese 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 outsi de 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 progra m 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
MG Y No. o f

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. Et hanol 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 producti on 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. o f

Plants Capacity
MGY No. o f

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 ar e 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 Renewabl es is expected to be the third largest ethanol producer with over 1.1 billion gallons of productio n capacity, provided the most recent ethanol139 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 A rcher 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 Ad vanced Processing Technologies

While we can get a good idea of what the et hanol 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 efficien cy 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 pot ential low life cycle green house gas emissions incentives may further encourage ethanol producer s to transition from fossil fuels to biomass
based fuels.

As ethanol plants become more efficient a nd require less energy, their ability to use biofuels increases. Two of the biggest drawback s 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 equivale nt 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 grea ter extent, by waste products and locally produced biofuels. This would greatly reduce the purchase and transportation costs of the biofuels. If140 ethanol producers do decide to make a transition to biofuels, is likely that plants currently using natural gas would transition to us ing 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 emissi ons, are expected to increase the number of ethanol producers using combined heat and po wer (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 bot h increase the efficiency of un its currently used in ethanol production, as well as provide energy saving alte rnatives to conventiona l production practices. Increasing energy efficiency is a priority in many ethanol plants as is can dramatically increase profitability by reducing energy costs, the s econd highest cost of ethanol production behind raw materials. Several groups are currently workin g 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. Th e 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 re lative 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.pdf141 Table 1.5-13. 46 Projected Energy Savings from Conv entional Produc tion 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 en ergy saving changes to the ethanol production process. Several process changes, including ra w 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 factor s, including technology availability, capital cost of implementation, energy cost savings, and co-product revenue ge neration. A description of each of these technologies, including the cha llenges 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 be nefits 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, 2007142 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-pr oduct 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 spo ilage. 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 dr y 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 (p rimary fuel sources, energy savings from efficiency improvements, new technology and proce ss 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 show ing the energy impact calculations of the technology improvements (EPA-HQ-OAR-2005-0161-2729143 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 ca se scenario” plant. This plant was defined as a plant that used the combination of all the technol ogies 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 fractiona tion but not both, and dry fractionation resulted in greater energy savings. Best case scenario energy usage numbers we re calculated for both natural gas and coal/biomass fi red plants producing both dry a nd 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 th e preamble, renewable fuel produced from new
facilities which commenced cons truction 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, fa cilities that commenced construction in 2008 or 2009 are grandfathered if they burn natural ga s, 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 fina l 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 pl ants that were operational,
idled or under construction at th e time of our November 2009 assessment. As shown in Table 1.5-7, excluding the planned facilities, this am ounts 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 biofue l 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 mi nor 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 construc tion prior to December 31, 2009 or they burn coal but commenced construction prior to De cember 19, 2007. A summary of grandfathering assessment logis we applied is f ound 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

No146 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 Energy b Pekin, IL 100 1981 Chief Ethanol Fuels Inc. Hastings, NE 62 1985

Corn LP c Goldfield, IA 50 Dec-05 Grain Processing Corp Muscatine, IA 20 May-00 Heron Lake BioEnergy, LLC Heron Lake, MN 50 Oct-07 Lincolnway Energy LLC Nevada, IA 50 May-06 Red Trail Energy, LLC Richardton, ND 50 Jan-07

Riverland Biofuels d 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 a nd 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 Ethanol147 In order to assess the potential for U.S. imported ethanol, we examined the chief countries that are currently producing or consum ing relatively large volumes of ethanol. In particular, we chose to focus on Brazil, the Eur opean Union (EU), Japan, India, and China to determine whether each country will likely be an im porter or exporter of ethanol in the future. The following sections first desc ribe the ethanol demands of e ach 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 differen t 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 po ol 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, wh ereas 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 ga soline 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 ga soline 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 th e historical production of hydrous and anhydrous ethanol in Brazil.149 Figure 1.5-7.
Historical Ethanol Produc tion of Hydrous and Anhydrous Ethanol in Brazil. 258

0 1,000 2,000 3,000 4,000 5,000 6,0001997199819992000200120022003200420052006200720082009Million Gallons Hydrous Ethanol Anhydrous Ethanol

*2009 data is up to date as of 12/01/2009

In contrast to Brazil, ethanol consumed in th e U.S. must first be converted to anhydrous
ethanol before its use in conve ntional 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 onl y 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, howev er, 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. Braz il’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 expa nsions. Estimates for the invest ment 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 do llars would be required.150 Figure 1.5-8. Estimated Brazilian Ethanol Production Volumes 262



### 0 5,000 10,000 15,000 20,000 25,000

2000 2010 2020 2030 2040Million 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 pr esident 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 produc tion 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 us e 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. 270151 One way of dealing with this lack of infrastructure is to invest in enlarging the pipeline network. Petrobras, Brazil’s largest petroleum refi ner 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 Transpor te 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 in itial 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 etha nol a year. In total, it is estimated that Brazil will need to invest $1 billion each year for the ne xt 15 years in infrastructure to keep pace with capacity expansion and export demand. 273

Another area that requires i nvestment is in R&D and e ducation. 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 requi re 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 grow ing demand in the biofuels industry.

Before ethanol can be exported to othe r countries, Brazil’s own domestic fuel consumption should be met. Brazil curr ently 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 vol ume 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 begi ns 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 2040Million Gallons 

### Canaplan, Director Carvalho

FAPRI 2007 Agricultural Outlook EPE (2007)

Unica

After domestic consumption is me t, the rest of the ethanol can be available for exports to
other countries. Potential worldw ide exports basically equal the total production minus the total consumption. Given the ava ilable 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 s een 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 time frame estimates from sugarcane analyst Datagro project international ethanol sales to grow to 6.6 billion gallons by 2025. 279153 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 2022Million Gallons 

### EPE (2007)

Unica

FAPRI 2007 Agricultural Outlook

The European Union (EU)

Although the EU market has largely focuse d 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 esta blished that by 2005 biofuels should cover 2% of the total fuel consumption (energ y 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 ta rget 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 si nce 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 gasolin e consumption volumes are po ssible 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
2022154 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 potenti al 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 not ed, however, that the EU production estimates in the FAPRI Agricultural Outlook does not reflect th e 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 et hanol 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 constr uction 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 et hanol production in the EU could gr ow. 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 dema nd 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 producti on 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 annua lly 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. 295,296155 The prospect for large domestic production of et hanol in Japan appears to be small due to
limitations on feedstock. In fact, Japan’s first biomass pl an, “Biomass Nippon Strategy” unveiled in December 2002 and updated in 2008 reveal s 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 di fferences 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 fu rther supports the argument that Japan could likely be heavily dependent on imports.

Table 1.5-18. Upcoming/Recent Plants in Japan 299
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 fina ncial support from Japan Bank for Inte rnational 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 lite rs (264 million gallons) of alcohol annually at five processing plants in the st ates 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 cont racts 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 distribu tion 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 en ergy 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, ha d 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 ot her 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 et hanol 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 Tam il Nadu, Andhra Pradesh, and Maharashtra. 306 The157 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 m odifications (e.g. twowheelers). Regardless, the government announced as part of its new biofuels policy to raise the blending level to 20% of total fu el usage by 2017 (i ncludes 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 etha nol manufacturing comp any (Bajaj Hindusthan) has tried to acquire ethanol produc tion plants in other countries with large sugarcane outputs (i.e. Brazil). This way, the company can increase its ethanol production. Ye t 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 de natured and 59.08% for undenatured ethanol. 309 The c.i.f. (cost, insurance, and freight) value re presents 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, im port 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 suga r industry). However, as India strives to meet its E10 goal, it may need to rely on imports fro m 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 c hooses 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 bl ended 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, Hebe i, and Hubei in 2006. To keep up with fuel demand, a National Plan ca lls for fuel ethanol to rise from approximately 330 million gallons of ethanol per year to 660 m illion 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 la rgest 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 f ood 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 providi ng 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 Commiss ion (NDRC), China has stopped a pprovals for industrial corn processing for three years (until 2010) and has su spended 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 co rn into industrial products like et hanol) will be restricted to 26 percent of China's total corn consumption.

The National Development and Reform Commission (NDRC) stated in their 11 th Five Year Plan (2006-2010) that the production of ap proximately 2 billion gallons of grain-based ethanol will not threaten the country’s grain secu rity. 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 Comp any 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 re ach 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 China 318

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 et hanol, especially if the E10 blend is extended across the country. W ith 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 net159 importer of ethanol in the fu ture (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, Neth erlands, 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 im ports from Canada and Mexico.

In addition, there may also be other countri es that are beginning biofuels programs and
could demand smaller volu mes of ethanol in the future. We provide a list of the potential mandates and goals for other countri es 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 Countries 325,326,327,328,329,330

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 fro m 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 de mand by 2020/2022. Total impor t potential demand from all these countries would range from approximately 5- 15 billion gallons. If these countries decide
to meet their mandated ethanol bl ends or enact new mandates, th is could greatly increase the amount that each country would demand from othe r 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 potentia lly demanded by other countries in the future. Therefore, it is161 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-cellulo sic 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 fo r imported cellulosic feedst ocks 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 th e 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 Indi a. Based on this hist orical data, it does not seem likely that volume of ethanol exports will change drastically in the future.

52 Ranges are calculated assuming the potentia l values for production and consumption162 Figure 1.5-11. U.S. Ethanol Exports (includes hydrou s, dehydrated, and denatured volumes). 331

0 20 40 60 80 100 120 140

2001 2002 2003 2004 2005Million 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-denatu red ethanol and a 1.9 percent tax for denatured ethanol). A key reason for estab lishing a tariff was to offset a tax incentive for ethanol-blended gasoline, which is set at 45 cen ts 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 fi rst shipping ethanol to count ries 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. Legislatio n 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 count ries 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 gallon163 Under the Caribbean Basin Economic Recove ry Act (CBERA), which created the CBI,
countries in Central America a nd the Caribbean have had duty-free access to the United States since 1989 for ethanol produced from regional feedst ocks. Although most analysts believe there is sufficient land available for sugarcane pr oduction in some CBI nations, there has been insufficient economic potential to spur su garcane 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 Tr ade 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 othe r Mediterranean count ries 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 m illion 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 im ported 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 dr awback claim is based does not contain ethyl
alcohol or a mixtur e 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 anticip ated 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 5001990199219941996199820002002200420062008Million 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, a nd 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 compan ies have expanded plants or announced new plants as described below:

• Jamaica - In 2005, Petrojam Ethanol Limited (PEL), up graded 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 dehydra tion 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. JB G 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, wh ich 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. 345165 • El Salvador and Panama - In 2004, it was reported that Cargill and Chevron Texaco had announced plans to construct new dehydration pl ants 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 in clude 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 bu ild an ethanol dehy dration operation at the Petrotrin Refinery in Point-a-Pierre, a sout hern 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 Ma rch and April of 2007. 348 The cost to build the plant is estimated at $20 million. 349 It is probable, however, that not a ll 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 milli on 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 Domi nican 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 etha nol plant capacity for dehydra tion 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, ha ve expressed concern that th e 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 surplu s 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 et hanol 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 bey ond 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, Pantleon166 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 opport unity prices and simila r 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 not ed above, however, as dehydration capacity gets close to the US CBI quota, processors will need to c onsider blending indigenous ethanol.

As a result of the economic benefit of sh ipping 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 c ontrol 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 fo r the volumes from cellulo sic 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 th ese 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 pr oduction 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 expa nd biofuel production, bot h volumetrically and geographically. Research and development on cellulosic biofuel technol ogies 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 (D OD) and state agencies are helping to spur industry growth.

1.5.3.1 Current Stat e of the Industry

There are a growing number of biofuel pr oducers, biotechnology companies, universities and research institutes, start-up companies as well as refiners investigating cellulosic biofuel production. The industry is currently pursuin g 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 ga soline blending. There is also great promise and growing interest in synthetic hydrocar bons 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 bi ofuel production is beginn ing to materialize.

We are currently aware of 36 small cellulosic biofuel plants operating in North America. This includes process development units w ith 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 plan ts 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 ce llulosic biofuel is both technologically and economically feasible.168Table 1.5-23. Current Cellulosic Alcohol PlantsAR EC W UWAbengoa Bioenergy CorporationdYork, NE Pilot 0.02 Sep-07 Ethanol Bio X XAE Biofuels Butte, MT Demo 0.15 Aug-08 Ethanol Bio X XArkenol Technology Center Orange, CA Pilot N/A 1994 Ethanol Bio XAuburn University / Masada Auburn, AL Pilot N/A 1995 Ethanol Bio XChemrec & Weyerhaeuser New Bern, NC Pilot N/A 1996 Ethanol Thermo XClearFuels / Hawaii Natural Energy Institute Honolulu, HI Pilot N/A 2004 Ethanol Thermo XCobalt Biofuels Mountainview, CA Pilot 0.01 N/A Butanol Bio X XCornell University Biofuels Research Laboratory Ithaca, NY Pilot N/A Jan-09 Ethanol Bio X XCoskataeWarrenville, IL Pilot N/A Mar-08 Ethanol Thermo XCoskataeMadison, PA Demo 0.04 Oct-09 Ethanol Thermo X X X XDOE National Renewable Energy Laboratory Golden, CO Pilot N/A 2001 Ethanol Bio XEnerkem Sherbrooke (CAN) Pilot N/A 2003 Ethanol Thermo X XFiberightfLawrenceville, VA Demo (C) N/A 2005 Ethanol Bio XFulcrum Bioenergy - Turning Point Ethanol Plant Durham, NC Demo N/A Mar-09 Ethanol Thermo XGulf Coast Energy Livingston, AL Demo 0.20 Sep-08 Ethanol Thermo XINEOS Bio (formerly BRI)eFayetteville, AR Pilot 0.04 1998 Ethanol Thermo X X XIogen Corporation Ottawa (CAN) Pilot N/A 1985 Ethanol Bio X XIogen Corporation Ottawa (CAN) Demo (C) 0.50 2004 Ethanol Bio XKL Energy Corp / WBE Upton, WY Demo (C) 1.50 Sep-07 Ethanol Bio XLignol Energy Burnaby, BC (CAN) Pilot N/A Jun-09 Ethanol Bio X XMascoma Corporation Rome, NY Pilot 0.20 Dec-08 Ethanol Bio XPan Gen Global (formerly Colusa Biomass) Colusa County, CA Pilot N/A 1995 Ethanol Bio XPearson Technologies Inc. Aberdeen, MS Pilot N/A 2001 Ethanol Thermo X XPOET Project BelldScotland, SD Pilot 0.02 Nov-08 Ethanol Bio XPureVision Technology, Inc.fFort Lupton, CO PDU N/A Mar-09 Ethanol Bio X XRange Fuels K2A Optimization Plant Broomfield, CO Pilot N/A Mar-09 Ethanol Thermo XSunOpta BioProcess Inc. Norval (CAN) Pilot N/A 2003 Ethanol Bio XVerenium Jennings, LA Pilot 0.05 2006 Ethanol Bio XVerenium Jennings, LA Demo 1.40 Feb-09 Ethanol Bio X X XCell. FeedstockscCompany/Plant NameaPDU = Process development unit, Pilot = pilot-scale plant, Demo = demonstration-level plant, Demo (C) = Commercial demonstration 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.dCellulosic ethanol plant is co-located with an existing corn ethanol plant.ePlant also processes non-cellulosic/renewable feedstocks, e.g., natural gas, coal.fPlant is not currently operational and/or producing fuel.Cell.Tech.bOnlineDateMax Cap(MGY)PlantTypeaPlant LocationCell.Biofuel169Table 1.5-24. Current Cellulosic Hydrocarbon Fuel & Pyrolysis Oil PlantsAR EC W UWCello EnergydFort Stewart, GA Pilot 0.01 Dec-08 Diesel Bio X XCello EnergydBay Minette, AL Demo (C) 20.00 Dec-08 Diesel Cat X XClearfuels / RentecheCommerce City, CO PDU N/A 2008 Diesel, Jet Thermo X XDynamotive West Lorne (CAN) Demo (C) 3.55 N/A Py Oil Thermo XDynamotive / Evolution Biofuels Guelph (CAN) Demo (C) 5.46 Sep-07 Py Oil Thermo XTerrabon Advanced Biofuels Research Center Bryan, TX Pilot 0.13 Apr-09 Gasoline Bio X X XThermoChem Recovery International (TRI) Durham, NC Pilot 0.02 Jun-09 Diesel Thermo X X XCompany/Plant NameaPDU = Process development unit, Pilot = pilot-scale plant, Demo = demonstration-level plant, Demo (C) = Commercial demonstration 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.bOnlineDateM ax Cap(MGY)PlantTypeaPlant LocationCell.BiofuelCell. Feedstocksc170 As shown in Tables 1.5-23 and 1.5-24, toda y’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 invest igated 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 (for est 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 ha ve 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 c onversion technologies
and biofuels. Most of the t echnologies fall into one of tw o categories: biochemical or
thermochemical. Biochemical c onversion involves the use of acids and/or enzymes to hydrolyze
cellulosic materials into fermenta ble sugars and lignin. Thermo chemical 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 curren tly being considered are capable of producing cellulosic alcohols or hydrocarbons for the transpor tation 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 conve rsion technologies, refe r to Section 1.4.3.

1.5.3.2 Setting the 2010 Standard

The Energy Independence and Security Ac t (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 th at year. EPA is required to set the annual cellulosic standard by November 30 th each year and should consider the annual estimate made by EIA by October 31 st 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 charac terized by a wide range of companies mostly focused on research, development, demonstration, and financing their deve loping technologies. In addition, while we are finaliz ing a requirement that producers a nd importers of renewable fuel171 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 biof uel production potential is re latively small, and the number of actual potential producer s 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 asse ssment of the cellulosic biofuel industry to arrive at the conclusion that it was possibl e 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 demons tration 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 fa cility twice in 2009 to confirm that the first-ofits-kind commercial plant was mechanically comple te 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 th at three more 50 MGY ce llulosic diesel plants planned for the Southeast could be brought online by the end of 2010.

At the time of our assessment, we were al so anticipating cellulo sic 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 e nd 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, co ntractual, financial a nd 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 perm anently 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 bi ofuel 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 Administra tor 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 Pl ant 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 in formation, obtain confiden tial 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 lands cape 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 th at it is difficult to rely on commercial production from small pilot or de monstration 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 co mmercial plant. Small plants are cheaper to build to demonstrate the technology than large commercial plants, but th e 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 fu el 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 Administrator173 cellulosic ethanol plant in Upton, WY. This plan t 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 dem onstration 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 bu ilding demonstration plants in the U.S. and Enerkem, a company building a demonstration pl ant in Canada. Cello Energy’s Bay Minette, AL plant continues to offer a dditional potential for cellulosic bi ofuel in 2010. And finally, Dynamotive, a company that currently has two bi omass-based pyrolysis o il production plants in Canada is another poten tial 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 conver t wood products and wood waste products into ethanol. Since the end of construction in Sept ember 2007, equipment commissioning and process revisi ons 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-qua lity volumes of ethanol and lignin co-product. The company’s current 2010 production goal is for WBE to ge nerate RINs under the RFS2 program.

Iogen is responsible for opening the firs t commercial demonstra tion cellulosic ethanol plant in North America. Iogen’s plant located in Ottawa, Cana da 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. Accordin g 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 cellulo sic 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 Prin ce Albert, Saskatchewan in the 2011/2012 timeframe. Based on the company’s location and operating status, Iogen cer tainly has the potential to participate in the RFS2 program. However, at this time, we ar e 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-etha nol production. According to DDCE, construction commenced in October 2008 a nd the plant is now me chanically 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 va lidate 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 ce llulosic ethanol producti on. 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 Pontot oc, 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 schedul ed to come online around the middle of 2010.
While it’s unclear at this time whether the cellu losic ethanol produced will be exported to the United States, Enerkem has expressed interest in selling its fuel commercially.

Additional cellulosic bi ofuel 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 pr oduction 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 onl y fractionates MSW but biological ly converts the non-recyclable portion into cellulosic ethanol a nd 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 curre ntly 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. Fi beright’s long-term goal is to expand the Blairstown plant to a 5-8 MGY capacity and build other small comme rcial 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 re cent 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 pr oduction 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 a nd Guelph, Ontario that produce biomass-based pyrolysis oil (also known as “BioOil”) for i ndustrial 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 year175 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 toward s meeting the cellulosic biofue l standard in 2010.

As for the Range Fuels plant, construction of phase one in Sopert on, 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 metha nol catalyst they are not expected to produce qualifying renewable fuel in 2010. During phase two of their project, cu rrently 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 biofue l production potential.

Overall, our most recent indus try assessment suggests that th ere are six companies that could potentially produce cellulosi c biofuel next year. Together these seven plants, summarized in Table 1.5-26, could have over 30 MGY of cellu losic biofuel plant capacity online by the end of 2010. However, the actual volume of cellulosi c 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 2010.176Table 1.5-26EPA’s Cellulosic Biofuel Plant Assessment – Projected Capacity Online by End of 2010Cello Energy Bay Minette, AL Demo (C) 20.00 Currently Off-Line Mar-09 Diesel Wood chips, hayDuPont Dansico (DDCE) Vonore, TN Demo 0.25 Undergoing Start-Up Jan-10 Ethanol Corn cobs then switchgrassDynamotive West Lorne, Ontario (CAN) Demo (C) 3.55 On-Line Py Oil Waste woodDynamotive Guelph, Ontario (CAN) Demo (C) 5.46 On-Line Py Oil Waste wood, wood chipsEnerkem Westbury, Quebec (CAN) Demo 1.30 Under Construction Jun-10 Ethanol Treated woodFiberight Blairstown, IA Demo (C) 2.00 Under Construction Mar-10 Ethanol Sorted MSWKL Energy Corp / WBE Upton, WY Demo (C) 1.50 On-Line Ethanol Wood chipsCompany/Plant NameMax Cap(MGY)PlantType Cellulosic FeedstocksCellBiofuelPlant LocationOperationalStatusProj. Op.Date177 Since most of the plants in Table 1.5-26 ar e still under construction today, the amount of cellulosic biofuel produced in 2010 will be continge nt upon when and if these plants come online and whether the projects get delayed due to fundi ng or other reasons. In addition, based on our
discussions with the deve loping 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 dem onstration plants, are not operate d 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 achievabl e. 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 somewh ere in the 6-13 million gallon range for 2010.

In addition, it is unclear how much was can re ly on Canadian plants for cellulosic biofuel in 2010. Although we currently receive some conventional biofuels im ports 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 coul d keep much of the cellulosic biofuel produced from coming to the United States, e.g., Iogen. Fi nally, it’s unclear whethe r 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 deta iled registration information. Factoring in these considerations, the cellulosic biofuel potential from the six more likely companies descri bed 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 cellulosi c 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 othe r cellulosic biofuel projects in addition to those de scribed 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 biof uel production in 2010 ma y 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 bi ofuels 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 wher e they are at, many have fallen behind their original commercializati on schedules. As with any new t echnology, there have been delays associated with scaling up capacity, i.e., bugs to work out going from p ilot to demonstration to commercialization. However, most are saying it’s not the technologies that are delaying178 commercialization, it is l ack 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 biorefiner ies employing advanced technol ogies 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 demonstra tion plants including cellulosic ethanol projects by Enerkem and INEO S New Planet BioEnergy, LLC. DOE has also issued grants and loan guarantees to help f und some of the first comme rcial cellulosic biofuel plants. Current recipients include Abengoa Bi oenergy), BlueFire Ethanol and POET Biorefining in addition to previously-menti oned 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 bl ender credit to give preference to ethanol and other biofuels produced from cellulosic feedstocks. Effective Ja nuary 1, 2009, corn ethanol receives a reduced tax credit of $0.45/gal while cellulosi c biofuel earns a credit of $1.01/gal. 60 In addition, the FarmBill contains provisions that enable USDA to assist with the commercialization of secondgeneration biofuels, explaine d in more detail below.

Section 9003, also known as the Biorefin ery Assistance Program, promotes the development of new and emerging technologie s 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 m illion per project. The program is designed to create energy-related jobs and economic developm ent 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 US DA 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. S ection 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 acr oss 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 a nd 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 effi cient 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 th ree bioenergy research centers dedicated to accelerating research and development of cellulo sic ethanol and other bi ofuels. The centers,
which will each focus on different feedstocks and biolog ical research challe nges, 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 grasse s, stover, and other cell ulosic 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 bioche mical 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, biofue ls, bioenergy, and related

processes. ccclxvii And, as mentioned above, on Decemb er 4, 2009, DOE announced that it would provide $564 million in stimulus funding to 19 pr ojects 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, technol ogies 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 in centive for advanced biof uels, including but not
limited to those made from cellulosic materials. The incentives range from grants, loan guarantees and tax breaks for advanced biofue l producers to support for technology development to support for feedstock development.

In addition to the production incentives describe d 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 Associ ation (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 refu eling stations by 2025. They also want to reduce the energy intensity of ethanol producti on 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 ce llulosic biofuel producers. General Motors and other vehicle/engine manu facturers are also providing financia l support to help w ith 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 1.5-29.181Table 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 0.020.020.0216.0216.0216.02AE Biofuels Ethanol 0.150.1515.1520.1520.1520.15BlueFire Ethanol Ethanol -----21.90Cello Energy Diesel -20.0020.0020.0020.00120.00CMEC / SunOpta Ethanol -----10.00Coskata Ethanol 0.040.040.0450.0450.04100.04DynamotiveaBioOil 9.009.009.009.009.009.00Enerkem Ethanol -1.3011.3021.3021.3041.30Fiberight Ethanol -2.006.506.506.506.50Flambeau River Biofuels Diesel ---8.008.008.00Fulcrum Bioenergy Ethanol ---10.5010.5010.50Inbicon / Great River Energy Ethanol ----20.0020.00INEOS Bio / New Planet Energy Ethanol --8.008.008.008.00Iogen Ethanol 0.500.500.5023.5023.5023.50KL Energy Ethanol 1.501.501.501.501.506.50Mascoma Corporation Ethanol 0.200.200.202.2020.2080.20New Page Diesel ---2.502.502.50Ohio River Clean Fuels / BaardbDiesel, Naphtha -----17.00POET Biorefining Ethanol 0.020.0225.0225.0225.0225.02Range Fuels Methanol, Ethanol -4.004.0030.0030.00100.00RentechcDiesel --0.157.157.157.15Vercipia (Verenium/BP JV) Ethanol 1.401.401.4037.4037.4037.40Maximum Plant Capacity (MGY) 12.83 40.13 102.78 298.78 336.78 690.68Capacity Expansion Plans (MGY)Biofuel(s)Cellulosic CompanyaCapacity has been estimated.bPlant will co-process biomass and coal. It is unclear at this time how much fuel would come from biomass and potentially qualify ascellulosic biofuel.cIncludes Clearfuels demo plant and Silvagas commercial plant.*Capacity, not actual production182Table 1.5-28.Promising New Cellulosic Alcohol PlantsCap(MGY)OpDateCap(MGY)OpDate AREC W UWAbengoa Bioenergy CorporationacHugoton, KS 16.00 2012 Ethanol Bio X XAE Advanced Fuels - Keyesc,dKeyes, CA 15.00 2011 20.00 2012 Ethanol Bio X XBlueFire Ethanol Lancaster, CA 3.90 TBD Ethanol Bio X XBlueFire Ethanol Fulton, MS 18.00 TBD Ethanol Bio XCentral Minnesota Cellulosic Ethanol PartnerscLittle Falls, MN 10.00 TBD Butanol Bio XCoskata / U.S. Sugar Corp. Clewston, FL 50.00 2012 100.00 TBD Ethanol Thermo XEnerkem Pontotoc, MS 10.00 2012 20.00 2015 Ethanol Thermo X XEnerkem GreenField Alberta Biofuels (EGAB) Edmonton (CAN) 10.00 2011 20.00 TBD Ethanol Thermo XFiberight (former Xethanol plant) Blairstown, IA 2.00 End-2010 6.50 2011 Ethanol Bio XFulcrum Bioenergy - Sierra BioFuels Plant McCarran, NV 10.50 Mid-2012 Ethanol Thermo XInbicon / Great River Energy Spiritwood, ND 20.00 2013 Ethanol Bio XINEOS Bio / New Planet Bioenergy, LLC Vero Beach, FL 8.00 End-2011 Ethanol Thermo X XIogen Corporation Prince Albert (CAN) 23.00 2012 Ethanol Bio XKL Energy Corp Kremmling, CO 5.00 TBD Ethanol Bio XMascoma Corporation / Frontier Resources Kinross, MI 2.00 2012 20.00 2013 Ethanol Bio XPOET Project LibertycEmmetsburg, IA 25.00 End-2011 Ethanol Bio XRange FuelseSoperton, GA 30.00 2012 100.00 TBD Methanol Thermo X XCell. FeedstocksbCell.BiofuelCell.Tech.aaConversion technology. Bio = Biochemical, Thermo = Thermochemical.bFeedstocks. AR = Ag residues, EC = Energy crops, W = Wood waste, chips, mill waste, etc., UW = Urban waste including sorted MSW and C&D debris.cCellulosic ethanol plant will be co-located with an existing corn ethanol plant.dWill start off processing corn and then transition to cellulosic feedstocks.eWill start off producing methanol and then switch catalysts and shift to producing a mix of methanol and ethanol.Company/Plant NameProduction GoalCurrent PlanPlant Location183Table 1.5-29Promising New Cellulosic Hydrocarbon PlantsCap(MGY)OpDateCap(MGY)OpDate AR EC W UWCello Energy Georgia (TBA) 50.00 TBD Diesel Cat X XCello Energy Alabama (TBA) 50.00 TBD Diesel Cat X XFlambeau River BiofuelscPark Falls, WI 8.00 2012 Diesel Thermo XNew Page - Project IndependencecWisconsin Rapids, WI 2.50 Early-2012 Diesel Thermo XOhio River Clean Fuels, LLC / BaarddWellsville, OH 17.00 2014 Diesel, Naphtha Thermo X XRentech / Rialto Renewable Energy Center Rialto, CA 7.00 End-2012 Diesel Thermo XCell. FeedstocksbCell.BiofuelCell.Tech.aaConversion technology. Bio = Biochemical, Thermo = Thermochemical.bFeedstocks. AR = Ag residues, EC = Energy crops, W = Wood waste, chips, mill waste, etc., UW = Urban waste including sorted MSW and C&D debris.cCapacities excludes heavy distillate/wax production.dPlant 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 NameProduction GoalCurrent PlanPlant Location184 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, followe d 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 beco me 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 plan t construction, such that engi neering 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 c onstruct cellulosic plants in time to meet the standards in Table 1.2-1, and we co mpare this to the historic build rate of capacity in the starch ethanol industry. Figure 1.5-13 de picts these construction trends.

Figure 1.5-13. Historic and projected plant star ts and projection capacity 2001-2022. a

0 5 10 15 20 25 30

2 00

2 20 0 4 2006 2 00

8 20 1 0 2 012 20 1 4 2016 2 01

8 20 2 0 2022Plant starts/yr

0 5 10 15 20 25 30 35Bgal 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 etha nol 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 ar e expected to be operating by 2022.185 For cellulosic biofuel plant construction, we assumed new plan t 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 biof uel 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. Ta ble 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 render ed fats. The industry capacity has expanded rapidly, going from a sparse network of sma ll 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 histori cal aggregate capacity, sales volumes, and other informa tion 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 ap parently 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 ha ve 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 capac ity 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. Beside s fuel, some plants may also produce oleochemicals for use in detergents, lubr icants or other products, providing additional sources of revenue for part of the industry.

In order to conduct our emissions and dist ribution 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 feasibilit y of sustained over-capaci ty and the variety of
useable feedstocks. In the absence of other information, we made the assumption that the187 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 incen tives. We estimated how many plants would continue to produce biodiesel and where they mi ght 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 surviv e over those that had fewe r. We also projected that a number of very small plants processing wa ste greases/fats would con tinue 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 feed stock 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 specia lized 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 Rene wable 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 be ef 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 rene wable diesel products be ing coprocessed with petroleum at refineries.

In fall of 2008, Dynamic Fuels, LLC (a jo int venture of Syntroleum Corp. and Tyson Foods, Inc.) announced construction of a 75 milli on 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. 375188 However, it is not co-located with existing petroleum production, a nd 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 alread y 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 va rious locations around the world and summarized a basic description of their tec hnologies for algae production. S ee 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 info rmation is available on a near daily basis, it is possible that we have not in cluded 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 informa tion 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 Technologies JJJ

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 representative s. 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 airenvironments, 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 Florida190 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 usingonly 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, Iowa191 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, Arizona192 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 Hawaii193 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, California195 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, Kansas196 Seambiotic Produces marine algae for a variety of applications, health foods, chemicals, medical products, and biofuels. Usesraceway/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, California197 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 inGuelph, Ontario in midSept 2009198systems; 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 infrastru cture has been optimized to facilitate the movement of petroleum-based fuel s. Consequently, there are very efficient pipeline-terminal networks that move large volum es of petroleum-based fuels from production/import centers on
the Gulf Coast and the Northeast into the heartland of the country. In c ontrast, 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 di rection of petroleum-based fuel s. The location of renewable fuel production plants is often dict ated 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 ex isting 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 te rminals. All biofuels currently are blended with petroleu m-based fuels prior to use. Mo st biofuel blends can be used
in conventional vehicles. Howe ver, E85 can only be used in flex-fuel vehicles, requires specially-constructed retail dispensing/storage equi pment, and may require special blendstocks at terminals. These factors limit the ability of bi ofuels to utilize the existing petroleum fuel
distribution infrastruct ure. Hence, the distribu tion of renewable fuels ra ises 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, indus try associations, indepe ndent 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 suppor t 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 ar e discussed in Section 4.2 of this RIA. The importation of ethanol into the U.S. is di scussed 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.htm200 1.6.2 Biofuel Shipment to Petroleum Terminals

Pipelines are the preferred method of shippi ng 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 ca n result in product cont amination 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 po ssible 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 a nd Hazardous Materials Safety Administration (PHMSA), and the Association of Oil Pipelines (AOPL) are conducting research to address the safety and technical challe nges 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 woul d need to be addressed before construction on such a pipe line could proceed, including t hose associated with securing new rights-of-ways and establishing sufficient su rety 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 fu el distribution infrastructure. Thus, there may be more opportunity for these biofuels to be sh ipped 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, th e 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 c oncerns that it may contaminate jet fuel that is shipped on the same pipeline and potential incompatibility with pipeline gaskets and seals. Segments of Kind er 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 wh ere 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, dies el-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 biodies el plants and the widespread location of such production facilities ma y tend to limit the extent to which biodiesel may be shipped by pipeline. Rail cars, barges, an d tank trucks that transport biodiesel over long
distances will need to be heated/insulate d 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 petrol eum terminals as the vast majority of biofuel volumes are today. To the extent that pipelines do play an increasin g role in the distribution of ethanol, this may improve reliability in supply and reduce distribution costs.

Apart from increased shipment by pipeline, biof uel distribution, and in particular ethanol distribution, can be further optimized primaril y 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 se rvice 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 ex isting 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 di stant 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 produc tion and demand centers ha ve 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.htm202 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 facilitie s for waterborne fuel shipments.

Our analysis of the shipment of ethanol and cellulosic distillate fuels to petroleum terminals is based on the Oakridge Nationa l 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 configura tion and projected evolu tion of the distribution system, and cost considerations for the differe nt 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 th e RFS2 requirements. However, due to the timing of the various analyses for the FRM, th e 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 w ould 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 distributi on 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 regist ered 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 mo re 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 fi nal 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). Th e 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 wh ere it was produced up to the point where the
State’s entire diesel fuel pool contained 5% biodi esel. We believe that this should provide a somewhat conservatively high es timate of biodiesel di stribution 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 c ould find a market. It is likely that some fraction would not need to travel quite as far. Therefor e, 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 concentr ated to justify shipment by unit train. Where distances are beyond 300 miles, shipment by ma nifest 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 bi odiesel 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 frei ght 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, ta nk 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 majo r fraction of all biofue l 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 substa ntial resources that seem likely to be focused on this cause, we
believe that overall fre ight rail capacity would not be a limiting factor to the successful implementation of the biof uel requirements under EISA.

1.6.3 Changes in Freight To nnage 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, a nd potential distribution c onstraints for the North American freight rail system. 383 The analysis found that biofuels transport is expected to constitute approximately 0.4% of the total freigh t 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 incr ease in freight traffic due to the transport of the biofuels needed to comply with the RFS2 standards204 For the analysis, we provided the estimat ed 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 di esel fuel that would be used. Due to the uncertainty associated with non-ethanol biof uels, 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-et hanol 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 baseli ne approximation of the current da y freight rail system unstressed by the transport of EISA-mandate d biofuels volumes. Freight rail activity for the unstressed baseline model was projected for 2012, 2014, a nd 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 commodi ty 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 superim posed onto the unstressed Infrastructure Network model for 2012, 2012, and 2022. For each forecast year, total biofuels demand include s biodiesel and non-coprocessed renewable diesel fuel demand. As such, total biof uel 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 fro m 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 move ments are estimated to occur from the Midwest producing regions to high-demand regions, such as the north east, 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. Shipme nts originating and term inating 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%)205constitute 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 tran sport under EISA would ha ve minimal impacts on transportation infrastructure overall since freight associated with biofuels constitutes only a small portion of the total freight tonnage for all commoditie s. The results of this analysis suggest that
it should be feasible for the dist ribution 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 ra il 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 groups UUU and governmental agencies in discussions with EPA, and in testimony provided for the Surface Transportati on Board (STB) expressed concerns about the ability of the rail system to keep pace with la rge 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 bottlene ck 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 ra il connections through the city , federal, state, and local officials announced an agreement in 2006 to i nvest $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 fo r the creation of five rail corridors to aid in alleviating the bottleneck.

Significant private and public resources ar e 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) Program VVV , administered by Federal Railroad Administration (FRA), as well as Section 45G Railroad Track Ma intenance 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 th e private markets. Under this program, FRA is authorized to provide direct loans and loan guar antees 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 th e remainder would have to come from other sources including, but not limited, to loans, tax cr edits, sale of assets, a nd other forms or publicsector participation. Given the reported historical i nvestment in rail infrastructure, it may be
reasonable to assume that rail carriers would be able to ma nage the $7.1 billion in annual investment from rail carriers that AASHTO projec ts would be needed to keep pace with the projected increase in freight demand.

The Association of American Railroads (AAR) estimates 386 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 Cl ass I railroads' share is projected to be $135 billion, with $13 billion projected for s hort 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, a nd reliable ethanol transportation services as well as to resolve past freight rail capacity difficulties. Presumably, this commitment extends to the projected three-percent increas e in overall freight tonna ge envisioned herein.

However, the Government Accounting Offi ce (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 regardin g allocation of these i nvestments, with the Alliance of Automobile Manufacturers, Amer ican Chemistry Council, National Industrial Transportation League, and others expressing co ncern 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 competitiv e 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 Transp ortation Board (STB) agreed to undertake a rigorous analysis of competition in the freight railroad industry. XXX

Given the broad importance to the U.S. ec onomy of meeting the anticipated increase in freight rail demand, and the substan tial resources that seem likely to be focused on this cause, we
believe that overall fre ight rail capacity would not be a limiting factor to the successful implementation of the biofuel re quirements 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 indi cation 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 gatherin g 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 volum es 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 lo cated at petroleum terminals and existing rail terminals. Based on industry input regarding th e 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 Cl ass 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 Observati ons 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 th e low-ethanol control sc enarios that all unit train and manifest rail receipt f acilities would be capable of handling th e receipt of both ethanol and cellulosic distillate fuel. There is no cellulosic distillate fuel under the high-ethanol scenario, thus all unit train receipt facilitie s would be dedicated to handling ethanol under the high-ethanol
control scenario.

In the NPRM, we assumed that some new ma nifest rail receipt f acilities fo r biofuels would be located at petroleum te rminals. Since the NPRM we re ceived 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 fa cilities 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 pe troleum 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 distributi on 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 num ber of unit train receipt facilities fo r the NPRM control case is still very useful in estimating th e 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-e thanol control scenario in this final rule (FRM), we estimate that 33.24 BGal/yr of ethanol woul d be used by 2022. Given thei r similarity, we assumed that the ORNL results for the NPRM would be applic able to the FRM high-ethanol scenario for estimating the number of unit trai n receipt facilitie s required.

Based on our analysis of a spreadsheet used in the ORNL analysis, we determined that ORNL estimated that there would be approx imately 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 justif y 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 industr y 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 circumst ances 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 minimu m 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 fac ilities 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 somewh at 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 scen arios relative to the high-ethanol scenario. However, we believe that this is an appropria te approach since it pr ovides 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 bi ofuels 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 ma ny of these type of facilities were in place
or under construction when historic ethanol consumption levels we re consistent with the RFS1 case. Under the RFS1 reference case, we attributed the need for 37 additional biofuel unit train receipt facilitie s (40-3) to the implementation of the EI SA. Under the AEO reference case, we
attributed 31 additional un it train receipt facilities (40-9) to the EISA.

The construction of each of these unit tr ain receipt f acilities w ould 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 load ing of tank trucks, biofue l storage tanks and/or pipelines to ship biofuel to n earby petroleum terminals, and ot her miscellaneous biofuel handling equipment. For our analysis, we assumed that all unit train rail receipt facilities would construct biofuel storage tanks. Biofue ls would be unloaded from unit trains into these storage tanks before being loaded into tank trucks for shipment to petroleum terminals. To the extent thatsome facilities are able to link to nearby petroleum terminals by pipeline or employ transloading, there would be less need for stor age 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 cel lulosic 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 4.2.2.1.3210 A spreadsheet used in the ORNL analysis indicates that ORNL estimated that there
would be 56 manifest rail r eceipt 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 subt racting the number of manifest ra il 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 mi scellaneous equipment to support the trans-loading process.

A substantial number of additi onal 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 ra il 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 to tal volume of biofuel projected to be used under a given control scenar io. 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-etha nol 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 determin e 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 referen ce case was calculated by volume weighting.211 Table 1.6.4-1. Additional Rail Cars Needed by 2022 for Shipm ent 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 exp ect would be shipped by manifest rail and the assumed rail car volume and cycle time. We assu med a cycle time of one month for shipment by
manifest rail car. We believe this is a c onservatively 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 attr ibute the construction of an additional 1,130 biodiesel rail cars to the implementation of th e 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 represen t 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 increas ed demand for ethanol tank cars, rail car212 producers converted existing boxcar production facilities to tank production facilities and brought on additional work shif ts 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 ex pressed 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 be en 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 sh ifted 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 sta ndards. We assumed the use of tank barges with a carrying capacity of 10,000 barrels (42,000 ga llons). We understand that the tank barge industry is trending towards the use of tank barg es 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 interp olation of the results from the ORNL analysis for the NPRM control case (34.14 BG/yr of et hanol by 2022) and AEO reference case (13.18 BG/yr of ethanol by 2022). The underlying assu mption 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 scenar io. 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-etha nol 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 in cremental 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 transp ort the volume of biodiesel that we project will be used to satisfy the RFS2 st andards. We estimate that 7 ba rges 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 attribut e 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 add itional 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 Shipme nt 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. Give n 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 RI A, 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
Counties EEEE according to company-level historical fuel import data from the Energy Information Administration (EIA). 391 Additional ports were select ed from those that have a history of receiving finished gasoline imports. Port s were selected in States that could not satisfy
their internal ethanol demand from in-State production and from thos e ports that were closest to large demand centers. We estimate that a total of 30 ports would receiv e imported ethanol by 2022. The list of ethanol import ports was provi ded 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 di d 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 insta ll additional ethanol storage tanks. We proj ect that under the primary mid- ethanol scenario that 15 new ethanol import locations would be added and that under the low et hanol scenario there would be 14 new ethanol import locations. We used thes e 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 et hanol would be imported would be incorporated into existing petroleum te rminals. Hence, the need for additional ethanol storage as well as outgoing ethanol shipping fac ilities 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 distributi on 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 ha s 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 scen ario 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 as sumed that 57 manifest ra il receipt fac ilities 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 ex emptions 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 facilitie s 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 facilitie s 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 facilitie s. Such fac ilities woul d 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 additiona l facilities needed at petroleum terminals and unit
train facilities.

1.6.6 Road Transportation System Accommodations

A substantial number of tank tr ucks would be needed to di stribute the additional volume of biofuels that we project woul d 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 us ed 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 interp olation of the results from the ORNL analysis for the NPRM control case (34.14 BG/yr of et hanol by 2022) and AEO reference case (13.18 BG/yr of ethanol by 2022). The underlying assu mption 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 scenar io. 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 fa cilities 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 facilitie s that we consolidated into the remaining 40 such facilities from the ORNL analysis to the lo cation 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 un it train would need to be shippe d 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 unit216 train facility to the petroleum terminal. FFFF The majority of the number tank trucks which ORNL
estimated would be needed are attributed to the tr ansport of biofuels from rail receipt facilities to petroleum terminals. Conseque ntly, we believe that a reasona ble (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 consolidat ed 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 fu el/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 tr ucks which ORNL estimated would be needed
under the two reference cases to determine the in cremental 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 need ed 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 widesp read dispersion and the fact that some would be located at petroleum terminals. We estimat e 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 transp ort the volume of biodies el projected under the
RFS1 reference case and 35 ta nk 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 implementa tion of the EISA is presented in Table 1.6.6-2.

Table 1.6.6-2.
Additional Tank Trucks N eeded 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 Butane a

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 pre ss 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 woul d 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. Simila r 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 finish ed 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 th e 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 ex periencing a national shortage of 20,000 truck drivers and, if the current trend continues, that s hortage of long-haul truck driv ers 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 re train 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 resu lt 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 w ith transport industry officials support this conclusion. However, specially-certif ied 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 nu mber of such speciall y-certified drivers to transport biofuels. The trucking industry is invol ved 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 ha ul routes the keep the driver away from home overnight. Thus, driving a tank tr uck (with typical 8 hour shift) ma y be relatively more attractive compared to a long haul truck driving position.

Truck transport of biofuel feedstocks to pr oduction plants and finished biofuels and coproducts from these plants naturally is concen trated 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 implem entation of the RFS2 sta ndards. 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 additiona l 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 maintenan ce 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 placemen t of new biofuel production facilitie s. 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 woul d 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 a dditional 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 le vel of 15% of the annual consumption of a given biofuel at the terminal level in order to provide a suffi cient 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 temporar y disruptions in biofuel delivery compared to petroleum-based fuels. We believe that this is appropriate due to the re liance 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 additiona l 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 biof uels. 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 need ed 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 th e 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 accommoda te 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 proj ect 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 di stillate/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 ta nks previously used to store gasoline involves lining the tank and other misce llaneous 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 heat ed 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 th at we project would be needed as a result of the implementation of the EISA under the 2 refe rence cases is presented in Tables 1.6.7-2 and
1.6.7-3.221 Table 1.6.7-2.
Additional Biofuel Stor age Capacity at Petroleum Terminals by 2022
to Meet the EISA Volumes Relative to the RFS1 Reference Case a

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, Ne w Construction 6.2 4.4 NA

Cellulosic Distillate Fuel/Renewable Diesel Fuel, Rededicated Tanks 36.8 25.9 NA

Biodiesel, New Constr uction 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 Stor age Capacity at Petroleum Terminals by 2022
to Meet the EISA Volumes Relative to the AEO Reference Case a

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, Ne w Construction 6.2 4.4 NA

Cellulosic Distillate Fuel/Renewable Diesel Fuel, Rededicated Tanks 36.8 25.9 NA

Biodiesel, New Constr uction 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, Rededica ted Tanks 36.8 25.9 0

a“ Retrofitted” refers to tanks that need significant change s 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 cap acity due to space constraints and difficulties in securing permits. 397 We acknowledge th at 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 in stall 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 ca pacity 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 industr y would be able to keep pa ce with the projected demand.

Petroleum terminals would need to inst all additional equipmen t to blend ethanol, cellulosic distillate fuel/renewable diesel fuel, and biodiesel into petroleum-based fuels. In the
case of ethanol other mi scellaneous 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) woul d install E10 blending equipment absent the implementation of the RFS2 requirements in or der to support the consumption of 13.18 BGY of ethanol by 2022 under the AEO reference case. Th is is based on 85% of the gasoline needing to
be blended with ethanol in order to consume 13.18 BGY of et hanol considering the projected use
levels of E10 versus E 85 and total motor vehicle fuel consumption in 2022. 399 We project that essentially all ga soline would be either E10 or E85 by 2022 under the RFS2 standards. Thus, we223 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 term inals would need to in stall 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. Th e 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 termin als 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 reasona bly available in 70% of the nation in order to support the use of the projected volume of E 85 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 ha ve reasonable access to E85 under the mid-ethanol scenario relative to the high-eth anol scenario. By multiplying our 90% estimate of the number of
terminals that would need to install E85 under the high-etha nol 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 lo w-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 bl ending fac ilities to accomm odate 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. I nput from terminal operato rs indicates that the modification of E10 blending e quipment to handle E85 primaril y 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 specia l 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 extrapola tion of the analysis conducted for the NPRM.
We estimate that 853 termin als handle di esel 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 appr oximately 73.2 MGY. In the NPRM analysis, we estimate that on a national average basis biodiesel w ould 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 fu el 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 te rminals would need to blend bi odiesel 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 pr oportion to volume of biodi esel that we project would be used in the FRM by 2022 relative to th at 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 stor e/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 IF TOA suggested that EPA should consider reducing and or slowing the pace of the implemen tation of the RFS2 standa rds 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 sh ould be feasible for terminals to adapt sufficiently within the time frame established by the EISA.

1.6.8 Potential Need for Special Blends tocks 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 stat ed that the current proposal to lower the minimum ethanol concentration to 68 volume percent may not be su fficient for this purpose. ASTM International may consider an additional propos al to further decrease the mini mum ethanol concentration. Absent such an adjustment, a high-vapor pressu re petroleum-based blendstock such as butane would need to be supplied to most petroleu m 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 termin als and storage and blending e quipment 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 denature d 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 vol atility specification for the finished product. The analyzer, variable frequency butane pump, a nd supporting equipment are self-contained on a skid-mounted unit, and requires at leas t one 60,000 gallon butane storage tank.

We estimated the number of automated inlin e butane blending syst ems, butane storage tanks, tanks trucks, railcars, trans-loading facilities, and other facility changes needed for butane blending as follows. Of the existing 1,063 termin als, two-thirds (709 term inals) 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. Ofthese 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 tankstorage. 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 ble nding system and two 60,000 gallon butane tanks. Usable tank volumes are assumed to be 51,000 ga llons per tank. Tank trucks are assumed to carry 8,200 gallons of butane. Railcars are a ssumed to carry 31,500 gallons of butane.

Our estimates of the number of tank trucks a nd 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 mini mum 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 w ould 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 mi nimum volatility considera tions 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 thei r manufacture. Nevertheless, petroleum terminals may find it a dvantageous 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 substantia lly depending on the control cas e. 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 E8 5 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 offe r gasoline. We selected one in four based on a
review of the number of facilities that have be en postulated to be needed to support the
introduction of altern ative 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 of fering 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 E 85 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 st orage 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 le ss 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 compar ison 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 thenumber 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 th roughput 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 da ta for gasoline throughput per refueling position.
We believe that this a pproach 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 St ores (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 approx imately 142,000 to 164,000 gallons per refueling position. These data include repor ts on the sales of all fuels including premium, mid-grade, and regular gasoline, diesel fuel and other fuels. The most appropria te 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 ove r 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 reta ilers 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 responde nts 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 estimat e 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. “N EAR85” 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 th e 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 sta ndards. 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 ha ve a single E85 dispen ser (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 scenario s to the E85 refueling fa cilities 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. U nder the high ethanol case and to a lesser extent under the primary case, th is 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 reta il equipment. Underwriters Laboratories requires that E85 refueling dispenser systems must be certified as complete
units. TTTT To date, no complete E85 dispenser sy stems have been certified by UL. We

TTTT See http://ulstandardsinfonet.ul.com/outscope/0087A.html230 understand that all the fuel dispenser components w ith the exception of the hoses that connect to the refueling nozzle have successfully passed the n ecessary testing. There does not appear to be a technical difficulty in fi nding 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 th eir 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 flexib le 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 scen ario, 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 incen tives are under consideration. VVVV Given the projections regarding ethanol pricing relative to ga soline 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 th e 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, ther e 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 intr oduction of E15. A number of ch anges/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 standa rds 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 re latively 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 specia l low-RVP gasoline blendstock
would be needed at terminals to allow the form ulation of mid-level et hanol blends that are compliant with EPA RVP requireme nts. Providing such a separa te gasoline blendstock would present significant logistical challenges and cost s to the fuel distributi on system. It should be possible for refiners to formulate a gasoline ble ndstock that would be suitable for manufacturing
both mid-level ethanol ble nds and E10 at the terminal. While this would avoid the logistical problems associated with maintaining separate bl endstocks, there could be additional refining

costs.

Assuming that refiners develop a common gaso line blendstock for both E10 and E15, the
accommodations that would be needed to the fuel distribution infrastruct ure to facilitate the
introduction of a mid-level etha nol 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-leve l ethanol blend. However, in mo st 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 rece ipt 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 co mpatible with the subs tance 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 Administrati on (OSHA), many local fire mars hals, tank insurance and state tank fund policies, and the provi sions contained in many business loan agreements.

Underwriters Laboratories (UL) is the leadin g 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 EP A’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 ha ndle a mid-level ethanol blend. One potential approach in lieu of requi ring a UL certification might be for AHJs to require that fuel retailers have records to esta blish what type of equipment is present and to
obtain manufacture certifica tions that the equipment is suitabl e for a mid-level ethanol blend.

Documenting the manufacturer and model num ber of the various components of their fuel storage and dispensing equi pment 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 asse mble 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 inst alled 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 compar ed 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 grante d 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 th e 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 gaso line 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 expe nsive E10 fuel to custom ers that do not require the use of premium but are not covered by a par tial 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 ma y be possible for a subs tantial number of retail
facilities to introduce a mid-level ethanol blend at a modest cost. If some components of the above ground existing retail hardwa re are found to be incompatib le with a mid- level ethanol blend, it may be possible for them to be repl aced 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 modifi cations 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 mi d-level ethanol blend. The potentia l 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 impli cations 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 a dditional 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 Imports b 

### Total a



### 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 percen t ethanol, although a sma ll 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 bl ending 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 y ear 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 en ergy demand in the future due to vehicle improvements, but AEO 2009 also shows an a dditional 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 cons umption calculations utilized in this analysis.

Figure 1.7-1 Projected Gasoline Energy Demand

0 5 10 15 20 25

20

04

20

05

20

06

20

07

20

08

2009 20

10

20

11

2012 2013 20

14

2015 2016 2017 2018 2019 2020 2021 2022 20

23

2024 2025 20

26

20

27

20

28

20

29

20

30

YearMotor 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 spec s, 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 hy drocarbon fuels is that there’s virtually no blend wall issue, they are fungib le 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 di esel. However, like all second- generation biofuels, there are technological and financial hurdl es 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 co ntrol cases with varying levels of ethanol as part of this final rule. As s hown 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 Figu re 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 20 11 2012 20 13 2014 20 15 20 16 20 17 20 18 20 19 20 20 20 21 20 22

YearBillion 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 exp ected, the more aggressi ve the ethanol usage,
the sooner the nation hits the blend wall. As show n 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 contro l 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 refue ling 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 FF V/E85 infrastructure and refueling whereas the high-ETOH case would require very dram atic 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 CaseTotal 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 subse quent ethanol growth would come from E85. Furthermore, we assumed that no ethanol cons umption 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 he lp the nation postpone the bl end wall in Section 1.7.6.

1.7.2 Projected Growth in Flexible Fuel Vehicles

Over the years there have been several po licy attempts to increase FFV sales including Corporate Average Fuel Economy (CAFE) credits a nd government fleet alte rnative-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 th e auto industry, automakers are incorporating more and more FFVs into their light-duty produc tion 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 th ree 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 ve hicle sales would follow AEO 2009 tr ends. 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 20 09 20 10 20 11 2012 2013 2014 2015 20 16 20 17 20 18 2019 2020 2021 20 22

Model YearLight-Duty Vehicle Sales

Trucks

Cars

NPRM

Although we assumed total ve hicle and car/truck sales would be the same in all three cases, we assumed varying levels of FFV product ion. 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 in creased 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 foll ow 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 Detro it 3 appear to still moving forward with their voluntary FFV commitment. KKKKK And finally, for our high-eth anol control case, we assumed a theoretical 80% FFV mandate based on the Open Fu el Standard that was recently reintroduced in Congress. Based on reduced vehicle sales and gasoline demand, we be lieve 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. A ll three sets of FFV production assumptions are presented in Table 1.7-5 (below) and more informa tion on our primary case is presented below.

We estimate that the cost to produce FFV s could be anywhere from $50 to $100 per vehicle, depending on the vehi cle and how many FFV-capable systems the automaker is producing. Current estimates s uggest that the per-FFV cost c ould 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 Detr oit 3 would continue to comprise 45% of total vehi cle 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 tr uck sales and car sales would gradually increase to allow The Detroit 3 to con tinue to maintain 45% marketshare in future years. With respect to FFV sales, we assumed th at the Detroit 3 would fo llow 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 ve hicle 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 c ontinue to maintain 55% marketshare in 2009 and beyond (based on adjusted 2008 pr oduction levels). Although non-domestic automakers have not made any official FFV production commitments, Nissan, Toyota, Mercedes, Izuzu, and Mazda all included at leas t 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 sa les (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 VM T and scrappage, and projected ve hicle fuel economy (based on the recently-proposed Vehicle Greenhouse Gas Rule NNNNN ), we estimate that the maximum percentage of fuel (gasoline/et hanol mix) that could feasibly be consumed by FFVs in 2022
would be about 20% under our mid-ETOH contro l 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 su mmary 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 Coalitio n, 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

YearGasoline 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

YearGasoline Fuel Fraction

Nonroad, Motorcycles, etc. Legacy NonFFVs 2001+ NonFFVs FFVs243 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

YearGasoline 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/ve hicles 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 stat es plus the District of Columbia. OOOOO While this represents significant industry growth, it still only translates to 1.3% of U.S. re tail stations nationwide carrying the fuel. PPPPP As a result, most FFV owners cl early do not have reasonable access to E85. For our FFV/E85 analysis, we have defi ned “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 implica tions 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 gr owing number of states are also offering infrastructure grants to help expand E85 availability. Currently, 10 Midwest states have adopted a progressive Energy Security a nd Climate Stewar dship Platform. SSSSS The platform includes a Regional Biofuels Promotion Plan w ith a goal of making E85 availabl e 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 improve ments to $100,000 or 50% of the total cost of needed alternative fuel equipm ent 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 etha nol 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 hi gh-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.pdf245 As explained in the NPRM, one way to provi de 70% of the nation with reasonable 1-in-4
access would be to make it available in urban areas. For an alysis 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 pot ential 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 ma jority of which are independentl y owned and operated and net around246 $30,000 per year) would not invest in more E85 infrastructure than what was necessary to meet the RFS2 requirements. For our primary mid-et hanol 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 compar ed 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%

2010 20 11 2012 2013 20 14 2015 20 16 2017 20 18 2019 20 20 2021 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 potenti al in 2008. Assuming that only 4% of the nation had reasonable onein-four access to E85 in 2008 (a s discussed above), this equa tes 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 lo w 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 flexib le fuel vehicle without making a conscious
decision to do so. And without effective cons umer awareness programs in place, these FFV owners may never think to refuel on E85. In addition, FFV owners w ith 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 increase d 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 refu eling on E85 over conv entional 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 presente d in Sections 1.7.2 and 1.7.3, our analysis suggests that FFV owners
with reasonable access to E85 would need to re fuel 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 c onsumers 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%

2010 20 11 20 12 2013 2014 20 15 20 16 2017 20 18 20 19 2020 2021 20 22

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 sta tion 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 assu mptions 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 comp uted 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 figu red 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 infrastruc ture 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 Gasoline249 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 gasoli ne based on its reduced energy content, increased time spent at the pump, and limited availability. On average, we es timate 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 shoul d be priced at about $3.20/gal.

78

. 0 / 000

, 115 90

. 0 / 012

, 77 10

. 0 / 000

, 115 26

. 0 / 012

, 77 74

. 0

10 85

= ∗ + ∗ ∗ + ∗

= gal BTU gal BTU gal BTU gal BTU
ity EnergyDens E ity EnergyDens E

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 Brownst one 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 Figu re 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 AvailabilityRefueling 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 n eed 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 bl end as E85, the more devalued ethanol becomes as a gasoline blendstock. Changes to state and Fe deral excise tax structur es could help promote ethanol blending as E85. But fo r 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 distributi on), ethanol would have to be priced around $2/gal in order for it to be a ttractive to refiners for E85 blending in 2022. The current ethanol rack price is around $1.80/gall on. 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 Marc h 6, 2009, Growth Energy and 54 ethanol manufacturers submitted an application for a waiv er of the prohibition of the introduction into
commerce of certain fuels and fuel additives se t 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 noti ce 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 n eed to continue to co-exist for legacy and non-road equipment based on consumer demand regard less 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-g rade 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 assume d that some E15-capable vehicles would continue to choose E10 or E12.5 based on today’s premium and midg rade 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 na tionwide. 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 ble nd 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

20 10 2011 20 12 2013 2014 20 15 2016 20 17 2018 2019 20 20 20 21 2022

YearBillion 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 c ould 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 requirement s under this scenario, it could provide interim relief while the country ramps up non-ethanol cellulosic biofuel production and/or expands E85/FF V 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 Comp ared to Low-ETOH Control Case

0 5 10 15 20 25 30 35 40

20 10 2011 20 12 2013 2014 20 15 2016 20 17 2018 2019 20 20 20 21 2022

YearBillion Gallons of Fuel (ETOH-Eq) Non-Ethanol Biofuels

Cellulosic Ethanol

Imported Ethanol

Corn Ethanol

E15 Blendwall (Partial Waiver)

E10 Blendwall254 Figure 1.7-14 Max E15 Ethanol Consumption Compared to High-ETOH Control Case

0 5 10 15 20 25 30 35 40

20 10 20 11 20 12 2013 20 14 20 15 20 16 2017 2018 20 19 20 20 2021 2022

YearBillion 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 th e fuel distribution analys es had to begin prior to this assessment being completed. As a result, they relie d 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 th e U.S. with a combined production capacity of255 9.2 billion gallons per year. EEEEEE413414 The majority of ethanol (nearly 89% by volume) was produced exclusively from corn. Another 11% ca me 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 combin ed. 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 Produc tion Capacity by Feedstock

Plant Feedstock (Primary Listed First) Capacity

MGY % of Capacity No. o f

Plants % o f

Plants

Corn a 8,141 88.8% 131 82.9% Corn, Milo b 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 Beverages c 13 0.1% 4 2.5% Waste Sugars & Starches d 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/sta rch ethanol plants burned natural gas (exclusively). FFFFFF In addition, three burned a combin ation of natural ga s 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 % o f Capacity No. o f

Plants % o f

Plants CHP

Tech.

Coal a 1,720 18.8% 18 11.4% 8 Coal, Biomass 50 0.5% 1 0.6% 0

Natural Gas b 7,141 77.9% 134 84.8% 15 Natural Gas, Biomass c 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 bi ogas, 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 Co rn 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 ga llons) 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 % o f Capacity No. o f

Plants % o f

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. Fo r 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 Locations258 Table 1.8-4 May 2008 Corn/Starch Ethanol Production Capacity by State

State Capacity

MGY % o f Capacity No. o f

Plants % o f

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 Pr oduction 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 pha ses of construction from conducting landstabilization 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 pla nning at the time of our May 2008 industry assessment.

Once all the aforementioned projects are comp lete, we projected th at 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 plan ts 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

Corn a 5,526 54 13,666 185 Corn, Milo b 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 Beverages c 0 0 13 4 Waste Sugars & Starches d 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. Total RFS2 Est. New Plants/Exp.

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 majori ty 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 existin g facility burning natura l gas and biomass. Our predictions also suggest two new coal-fired ethanol plants and thr ee 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

Coal a 740 4 2,460 22 12
Coal, Biomass 0 0 50 1 0
Manure Biogas 115 1 115 1 0

Natural Gas b 4,776 50 11,917 184 19
Natural Gas, Biomass c 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 me ntioned 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 u tilization of these technologies under the RFS2 program, refer to Section 1.5.1.3.

HHHHHH We anticipate that all the coal-fired corn ethanol pl ants 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 pl ant 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 underRFS2 is expected to originate from PADD 2. For a summary of this and other forecasted PADDlevel production projections, refe r 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 co llective annual producti on 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 co rn 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 impor ts 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 distri bution 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 histori cal 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 throug h 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 1.8-11266 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 im ported ethanol might en ter the United States, we started by looking at histor ical ethanol import data and ma de assumptions as to which countries would likely contri bute 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 hist ories, 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 Et hanol Imports from Brazil and CBI Countries Based on 2006-2007 Import Data Destination of Ethanol Imports (% of imported volume) Origin
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 im ports 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 pr oducts to be replaced under th e proposed RFS2 rule. And presumably, these ports cities already have existing gasoline storage tanks that could be267 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 projecte d 2022 corn and cellulosic ethanol production (detailed in Sections 1.8.1.1 and 1.8.1.3, re spectively). 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 vehicl e 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 Lo cations 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, cellulosi c 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 biof uel 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 trad itional 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 cellulosi c 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 us ed, 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 Bagasse LLLLLL 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 t echnically 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 th e 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 3,955271 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 82272 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 89273 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 110274 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 16039275 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. Ba nks are anticipated to require excess feedstock supply as a safety factor to ensure that the pl ant 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 larg er 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 prospec tive 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 feedst ock 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 re sort 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 A g. Residue Plant Switchgrass Plant MSW Plant Bagasse Plant276 facility), as large transport distances are economical ly 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 locati ons of planned cellulosi c 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, infrastructur e 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 a nd wood residues) and could have many synergies with cellulosic biofuel production, such as shared steam and el ectricity 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 w ith 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 ethano l plant with sufficient feedstock. However,
where non-MSW and C&D wood waste feedstocks are not available, we need ed 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 etha nol plant. Using that cellulo sic 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 part s of the country using different capital cost factors that account for how capital cost s vary in different parts of the country. The different regions were Petroleum Administration for Defense Districts (PADDs) for which we277 have plant installation costs. In each part of the country, we estimated the cost of the ethanol produced processing the cellulosic feedstock assumi ng 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 larg e 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 cellulosi c 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 fro m the production of sugarcane, (1.2 bgal ethanol) and sweet sorghum pulp (0.1 bgal ethanol). At the tim e of the proposal, FASOM was able to model agricultural residues but not forestry biomass as po tential 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 produc e 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 yi eld; 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 2022279 states producing corn stover, and their project ed volume contribution to meeting the EISA cellulosic requirement by 2022.280Table 1.8-18.Projected Ethanol Produced to Meet EISA in 2022from Corn Stover (NPRM version for AQ Modeling)146TotalHarvestedAcresTotal ResidueYieldTotal ResidueAvailableSustainablyRemovable ResidueYieldSustainablyRemovableResidue Available Residue UsedPercentResidueUsedEthanolProducedState (in 2022) (tons/acre) (Million tons) (tons/acre) (Million tons) (Million tons) (Million gallons)Total 71,784,020 n/a 380 n/a 122 82 22% 7752Illinois 12,994,100 5.43 71 1.62 21 15 21% 1444Indiana 6,209,463 5.58 35 2.09 13 10 29% 922Iowa 14,482,313 5.47 79 1.59 23 17 21% 1557Kansas 3,026,615 5.33 16 1.65 5 3 19% 261Kentucky 1,473,023 5.08 7 2.04 3 1 13% 63Michigan 2,238,321 4.30 10 1.79 4 3 31% 246Minnesota 7,509,658 5.37 40 1.60 12 8 20% 750Missouri 2,732,875 4.73 13 2.93 8 5 39% 434Nebraska 10,135,162 5.88 60 1.28 13 9 15% 840Ohio 3,712,612 4.91 18 1.89 7 5 27% 453South Dakota 4,268,425 4.01 17 1.41 6 4 23% 350Wisconsin 3,001,454 4.74 14 2.33 7 5 35% 432146Corn 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 canbe removed after accounting for sustainable removal rates based on tillage practices. This table gives approximate averages bystate based on our April 2008version of the agricultural modeling, actual yields will vary greatly depending on specific soil type, slope, etc. The valuesabove are calculated using theFASOM 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. FA SOM, 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 suga rcane 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 sorg hum 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, ot her removal residues, thi nnings from timberland, etc.). This information suggested that a large portion of forest material could be available for producing biofuels (excluding fore st biomass material contained in national forests as required282 under the Act). See Section 1.1.2.3 for more inform ation on forest residue feedstock availability. However, much of the forest material is in sma ll pockets of forest whic h because of its regional low density, could not help to justify the esta blishment 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 cellu losic 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 economical ly 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 RF S2 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 assumpti ons 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 th e 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 si mplifying 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 ru le, outlined in Section
1.7.1.2.283 Table 1.8-20. Optimistic FFV Production Scenar io – FFV Production Assumptions

Tot FFVs FFV-Cars FFV-Trucks T ot 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 a nd 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 s hown below in Figure 1.8-5. For analysis purposes, we assumed that the percentage of gaso line energy consumed by nonroad, heavy-duty gasoline vehicles (HDGVs), and motorcycles would be about 8% based on historical information provided by DOE. cdxxi284 Figure 1.8-5. Optimistic FFV Production Scenario - Gasoline Consumption by Vehicle Type

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

20

10 201 1 20 12 2013 2 014 2015 20 16 20 17 20 18 20 19 202 0 20 21 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 ar eas 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 Areas286 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 (E 0 or E10) and b.) the nation does not exceed the RFS2 ethanol volume requirements analyzed fo r 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%

20 1 0 2011 20 12 20 1 3 2014 2015 20 1 6 2017 2018 20 1 9 2020 2021 20 2 2

YearNationwide Access to Fuel

E0

E10

E85287 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 eac h 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 pr ovided 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) rule cdxxiii to come up with the respective low-RVP and 9- lb conventional gasoline prices in these state s. 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 co mpetitive retail E85 prices by adjusting for the reduced energy density of E85, the increa sed 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 area s 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 emissi ons 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 wh ich suggests the industry may downsize in the long term.

We developed a method to determine wher e biodiesel producers were most likely to remain based on state incentives to biodiesel pr oducers 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 2022289 scenarios was generated choosing first from those pl ants with most favorable status of the four factors and working downward. Efforts were ma de 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 i nput in the inventory and air qua lity 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 dist ribution 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 offere d 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 th e distribution system, such that the blend level at the final point of use is not ty pically of concern and, in fact , would probably be difficult to determine. Because of its nature, and the rela tively 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-lo w 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 wit hout 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 fo r 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 w ith such mandates and incentives on record as of summer 2008, as well as the associated poten tial 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 g al/ y r ) ( million g al/ y r ) ( million g al/ y r ) IL per-gallon tax incentive(s) for B11+,

state fleet re q uiremen t 1,660 33.2

KS p er- g allon tax incentive ( s ) for B2+ 816 16.3

L A B2 mandate with some conditions 1,734 34.7 MA B2 mandate, increasing to B15 with

some conditions 491 24.5

MI p er- g allon tax incentive ( s ) for B5+ 1,071 53.5 MN B2 mandate; state fleet re q uiremen t 999 20.0 NC per-gallon tax incentive(s), B2 school

b us re q uiremen t 1,234 24.7

N D p er- g allon tax incentive ( s ) 358 7.2

N E p er- g allon tax incentive ( s ) 547 10.9

N M B5 mandate with some conditions 475 23.7

OH p er- g allon tax incentive ( s ) 1,556 31.1 OR B2 mandate, increasing to B5 with

some conditions 738 36.9

SC p er- g allon tax incentive ( s ) 764 15.3

SD p er- g allon tax incentive ( s ) 263 5.3

TX p er- g allon 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 ha ve 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 ma y 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
89.1 Total used for biodiesel in heating oil 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 stat es not included here. For more on biodiesel-rela ted 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, “Emerging Biofuels: Outlook of Effects on U.S. Grain, Oilseed, and Livestock Mark ets,” May 2007 (a revised version is available from July 2007); USDA Agricultura l Projections to 2018, Re port OCE-2009-1, February 2009 (also USDA Agricultural Projections to 2016, Repor t 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/Fiel d_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, Cr op Production and Grain Stocks; USDA, World Agricultural Outlook Board, World Supply and Demand Es timates; and U.S. Department of Commerce, Bureau
of the Census.

6 USDA Agricultural Projections to 2016, Re port 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 Market s: 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 http://english.unica.com.br/dadosCotacao/estatistica/ , Accessed December 8, 2009.

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 Et hanol 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 Et hanol 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 fo r 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 Emi ssions,” Ethanol Producer Magazine,
March 2009.

22 Voegele, Erin, “Sugarcane Economics,” Ethanol Producer Magazine, March 2009.

23 Voegele, Erin, “Sugarcane plays role in developmen t 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 Bioe nergy 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, USDA-ARS (retired), Morris, MN 56267-1065, and D. R. Linden, USDA-ARS (retired), St. Paul, MN 55108- 0000, Crop and Soil Productivity Response to Co rn Residue Removal A Literature Review; FORUM, © American Society of Agronomy, Madison, WI 53 711 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 Equation (RUSLE). United States Department of Agriculture, Agricultural Research Service, Agricultural Handbook Number 703, 1997.

27 Richard G. Nelson, Enersol Resources, Manhatta n, KS 66502, USA, Resource Assessment and RemovalAnalysis 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

28 Linda Mann, Virginia Tolbert, Janet Cushman, Environmental Sciences Di vision, Oak Ridge National Laboratory, Oak Ridge, TN 37831-6038, Potential Envi ronmental Effects of Corn Stover Removal With Emphasis on Soil Organic Matter and Erosion, Agriculture, Ecosystems and Environment 89: 149-166,
ISSN 0167-8809 Elsevier Scie nce, Amsterdam. June 2002.

29 http://www.nrcs.usda.gov/t echnical/Standards/nhcp.html293 30 Richard G. Nelson, Enersol Resources, Manhatta n, KS 66502, USA, Resource Assessment and RemovalAnalysis for Corn Stover and Wheat Straw in the Eastern and Midwestern United States—Rainfall and Windinduced Soil Erosion Methodology, Biomass and Bioene rgy 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 Ca rbon Further Constrains Biomass Supply, Published in Agron. J. 99:1665–1667 (2007); American Society of Agronomy, Madison, WI 53711.

32 Susan S. Andrews, Ph.D., Leader , Soil Quality National Technology Development Team USDA-Natural Resource Conservation Service Crop, White Paper: Residue Removal for Bi omass 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 Availabilit y in the United States,” NREL Report No. TP-560-39181, 2005.

37 Gallagher, P. et. al., “Supply and Social Cost Es timates 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., “S witchgrass (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 Bi oenergy 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 US DA, 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 US DA, 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 functi on of forest owner preferen ces 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 Compac tion and Growth of Woody Plants. S candinavian 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 Pr oject-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 Feed stock Supplies and Distri bution; 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 Mi ssouri 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 Ch aracterization 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 Sta te of Minnesota,” 2000.

93 R.W. Beck, “Statewide Waste Composition Study: Pennsylvania State-wide Waste Composition,” April
2003.

94 DSM Environmental Services, Inc, “Verm ont 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 Feedstoc k Supplies and Distribution, ” Unpublished Manuscript, January 10, 2008.

101 Falk, Robert and McKeever, David. 2004. “Recoveri ng Wood for Reuse and Recycling A United States Perspective” USDA Forest Service

102 Fricke, K. (1989). “Technology and undesirable com ponents 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 op tions for advanced ethanol production in Brazilian sugarcane biorefineries” draft manuscript, anticipated to be available in Bi omass and Bioenergy soon.

109 Kline, K. et. al. Biofuel Feedstock Assessment fo r 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.chp centermw.org/pdfs/2007CornEethanolEnergySys.pdf

112 “Essential Rendering”, pub lished by the National Rende rer’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. Av ailable 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 analys is 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 Biodies el 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, a nd 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 recl amation, 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 Jong schaap, R.E.E, W.J. Corre, P.S Bindraban, and W.A. Brandenburg, “Cla ims and Facts on Jatropha curcas L,” Plant Research International

, Vers. Report 158, Oct. 2007.

148 Woltjer, Lyanne. Size does matter. Expertise Cent rum voor Duurzame Ontwikkeling (ECDO). Dec. 2006.

149 Jongschaap, op. sit.297 150 Li Guo, T. "The photosynthesis and water us e efficiency of eight garden tree species." Forest Research 15 (2002): 291-96. As sited in Jongschaap, R.E.E, W.J. Co rre, 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. Chikar a, S.N. Rao D. Kumar, G.N. Boricha, and A. Zala. Response of Jatropha curcas under different spacing to Jatropha de-oiled cake. Disc ipline 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, "S eed 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.ore gonstate.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 web site as of December 2009. See http://www.ebbeu.org/stats.php.

171 DTN Ethanol Center, ”EU Biodiesel Feedstock Challe nge,” 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, “2782 nd Council Meeting on Transport, Teleco mmunications, and Energy, February 15 th

, 2007, Brussels, Council of the European Uni on,” 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.” Pr esentation from Mauricio Tolmasquim, 2007.

178 Asian Palm Oil for Euro Biodiesel, 2005 as quoted in Ohga K. & Tatsuji K., “B iofuels Policies in Asia: Trade effects on World Agricultural and Biofuels Trad e,” 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-Fu els Biofuels Annual 2007,” June 13, 2007.298 181 USDA FAS, “Palm oil continues to dom inate 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 O il 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 ba sed on biomass portion available at $45-$55/dry ton.. Using POLYSYS Policy Analysis System, Agricultural Po licy 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 Pr oject-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 Labor atory, Environmental Scie nces 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 Inte rnational 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 Ce nter, 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 a nd Agri-Food Canada, Quebec, Canada; Harvest and Storage Of Wet and Dry Corn Stover As A Biomass Feedstock, Paper Number: 036088, 2003 ASAE A nnual International Meeting Riviera Hotel and Convention Center, La s 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 Di stributed Preprocessing of Biomass Feedstocks to a Bioenergy Industry, Paper No: 066151, 2006 ASABE Annual Intern ational Meeting, Oregon Convention Center, Portland, Oregon, 9 - 12 July 2006

cxcvi Biomass Research Development Board. The Economic s of Biomass Feedstocks in the United States. Occasional Paper 1, October 2008.

197 ICM website, Ethanol Producti on 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 Producti on 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 - BPX TM , 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 Saccharificati on: 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?incode n=iechad&indecade=3&involume=37&inissue=1]

205 Harris, E.E., Beglinger, E., Hajny, G.J., and She rrard, E.C., , Industrial and Engineering Chemistry , 37(1): 12–23 (1945) http://pubs3.acs.org/acs/journals/toc.page?incode n=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 En gineering 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. Tec hno-economic Modeling to S upport 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. Jechur a, K. Neeves, J. Sheehan, and B. Wallace National Renewable Energy Laboratory (NREL); L. Montag ue, 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. Departmen t of Energy Laboratory Operated by Midwest Research Institute • Battelle • Bechtel; Contract No. DE-AC36-99-GO10337

220 Graf, Angela, et. al., “Oregon Cellulo se-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, Lakewo od, 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 th e 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 a nd Bioprocessing, Orlando, FL, July 2006. As sited in Stephanopoulos, Gregory, et. al., “Challenges in Engine ering Microbes for Biofuels Production,” Science , 315, 801, February 9,
2007.

227 Genencor Launches First Ever Commercia l Enzyme Product for Cellulosic Ethanol, Rochester, NY, WorldWire, October 22, 2007 Copyright © 2007,. All rights re served. 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 W ood: Comparison of Hydrolysis Fermentation and Gasification Biosynthesis, Paper Number: 076036, Written for presentation at the 2007
ASABE Annual International Meetin g. Minneapolis Convention Center , Minneapolis, MN, 17 - 20 June 2007

234 J. Phillips, “Different Types of Gasifiers and Their In tegration with Gas Turbines,” EPRI/Advanced Coal Generation, http://www.netl.doe.gov/technologies/coal power/turbines/refshelf/handbook/1.2.1.pdf, October 30,
2008.

235 Ciferno, Jared P., Benchmarking Biomass Gasifi cation Technologies for Fuels, Chemicals and Hydrogen Production, National Energy Technology Labo ratory, 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., Th ermochemical 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 Renewa ble Energy. “The Co-Production of Ethanol and Electricity From Carbon-based Waste s,” 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 Conve rsion 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., Th ermochemical 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 curren t technology for Fischer-Tropsch fuels production, National Renewable Energy Laboratory for EPA, August 14, 2008.

242 DOE EERE Biomass Program. “Thermochemi cal Conversion Processes: Pyrolysis” http://www1.eere.energy.gov/biomass/thermochemical_processes.html , November 6, 2008.

243 Zeman, Nicholas, “Thermoche mical 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/SyntroleumI nvestorPresentation.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 Li ndfors 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 Abas tecimento (MAPA), “Brazilian Ethanol Production,” http://www.agricultura.gov.br/pls/portal/ docs/PAGE/MAPA/ESTA TISTICAS/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 Outlo ok; 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 (not e: 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 Expansio n, Czarnikow Says,” Bloomberg , June 19, 2008.

265 F.O. Licht GmbH, “89 New Ethanol Fac ilities 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: FA PRI 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 Us e 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 statistic s) Historical Data,” http://www.bp.com/statisticalreview.

284 Walter, A., op. sit.

285 Ayoub PM. Biofuels for Shell-bioma ss based blending components for tran sport fuels (gasoline and diesel). In: World biofuels symposium-China, Beijing, 2006. As sited in Walter, op. sit.

286 Ribeiro, F., “The New European Cha llenge for Brazilian Ethanol Exports,” Frost & Sullivan Market Insight

, February 7, 2008.

287 European Bioethanol Fuel Association (eBi o), “The Industry, Statistics: Production Data,” http://www.ebio.org/statistics.php?id=4, September, 2009.

288 European Bioethanol Fuel Association (eBio), “Pr oduction 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 9 th 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 Consumpti on 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 Shor tage 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.

312 Renewable 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 ar e 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,” La st 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 Austra lian Government Rural In dustries Research and Development Corporation, May 2007.

327 Roberts, Greg, “Rees sc raps 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 A nnual 2007,” USDA, FAS, June 1, 2007. http://www.fas.usda.gov/gainfiles/200706/146291386.pdf

330 Chavez, L., et. al., “Mexico Bio-fuels A nnual 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 (UST R), “Caribbean Basin Initiative,” November 12, 2008. http://www.ustr.gov/Trade_Development/Prefer ence_Programs/CBI/Section_Index.html

333 Bryan, Tom, “Entering Tariff-Free,” Et hanol 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 Help s 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, Or der 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 fo r California,” California Energy Commission, October 2003. http://www.ethanolrfa.org/object s/documents/100/castaffreport.pdf

342 Petrojam Limited, “Official Opening of Pe trojam 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 Stimul us,” 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 Etha nol Dehydration Plant,” Caribbean Net News, August 22, 2008.

355 Jamaica Gleaner News, “US$36m Etha nol Plant for Barbados,” Augu st 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 Et hanol Conversion Projects for $23 Million in Federal Funding” (Press Release), http://www.ener gy.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 & Attachme nts), 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.

ccclxviii Midwest Governors Association, “Energy Security and Climate Stewardship Platform for the Midwest 2007,” http://www.midwesterngovernors.org/resoluti ons/Platform.pdf, Publishe d November 2007.

369 Plant information taken from Nation Biodies el Board website as of November 2009.

370 Capacity data taken from National Biodiesel Board as of November 2009. Pr oduction, 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 Nati onal Biodiesel Board fact sheets at http://www.biodiesel.org/buyingbiodiesel/producer s_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 Mornin g 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 Mo rning News, article dated 10/ 6/08. Available in the
docket.

376 Syntroleum Investor Presena tion dated November 5, 2009. Av ailable in the docket or at: http://www.syntroleum.com/Presentations/SyntroleumI nvestorPresentation.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 Flor ida Pipeline from Tampa to Orlando ships batches of ethanol along with batches of gasoline. h ttp://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 Flor ida Pipeline from Tampa to Orlando ships batches of ethanol along with batches of gasoline. h ttp://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”, Associa tion 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 Infras tructure 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 Distribu tion 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 Distribu tion Constraints”, prepared for EPA by Oak Ridge National Laboratory, March 2009.

390 “Barge Transportation in the Unite d States”. Timothy Casey, Presenta tion at the MARE Forum USA, 2006, http://www.mareforum.com/ENERGY_TRANSPORTAT ION_USA_2006_PRESENTATIONS_files/CASEY. pdf

391 Energy Information Administration (EIA) historical company level ethanol and gaso line import data: http://www.eia.doe.gov/oil_gas/petroleum/data_publications/company_level_imports/cli_historical.html306 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 lo cations 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 Distribu tion 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 Fu el Ethanol Industry”, Downstream Alternative Incorporated, January 15, 2002.

399 A discussion of the volumes of biof uels 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 pr evalence 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 Reta ilers”, 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 Store s 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 Do cket A-99-06, Docket Item II-B-14.

407 National Petroleum News, “2008 marketfacts”, www.npnweb.com

408 National Petroleum News, “2007 mark etfacts”, 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/ estimat es http://www.e85refueling.com/

410 The “NEAR85” estimate of E85 re tail 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 Admini stration historical gasolin e 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 Fu ture 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 Labora tory, 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 plan t 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 S upplier Sales Volumes for No. 2 Diesel. Accessed 10/7/2008. http://tonto.eia.doe.gov/dnav/pe t/pet_cons_prim_a_EPD2D_P00_Mgalpd_a.htm

cdxxix Energy Information Administration, Fuel Oil and Kerosene Sales 2006, Ta ble 16. 2005 data column used. http://www.eia.doe.gov/pub/oil_gas/petroleum/data_publica tions/fuel_oil_and_kerosene_sales/current/pdf/table 16.pdf