## 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

January 19, 2010

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. Deleted: December 30, 2009¶2 

## Table of Contents

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

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

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

Chapter 1: Renewable Fuel Production and Consum ption........................................11

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

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

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

Chapter 5: Economic Impacts and Be nefits.............................................................. 642

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

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

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

Endnotes.....................................................................................................................77 1 Deleted: .3¶

Deleted: .4¶

Deleted: .6

Deleted: Final3 

## 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 a nd 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

The displacement of gasoline and diesel with renewable fuels has a wide range of environmental and economic impacts. This Re gulatory Impact Analysis (RIA) utilizes case study approaches to assess the impacts of an in crease in production, distri bution, and use of the renewable fuels sufficient to meet the RFS2 volumes established by Congress in the Energy Independence and Security Act of 2007 (EISA). This reflect s our updated assessment compared to the draft RIA conducted in support of the Notice of Proposed Rulemaking (NPRM). Because the standards were mandated by Congress in EISA, the impacts we are assessing are not being used to justify or support the decisions for the RF S2 volume standards, but rather to provide an assessment of the projected impacts of these standards when fully implemented. This information can then be used in future public policy decisions. As explained below, the estimates contained in this RIA should not be in terpreted as the impact of the RFS2 standards themselves because market forces may lead to increased producti on of renewable fuels even in the absence of the RFS2 standards. Rather, the impacts estimated in this RIA must be understood to refer to the consequences of an e xpansion of renewable fu el use, whether caused by the RFS2 program or by market forces.

The analytical approach taken by EPA in this RIA is to predict what the world would be like, in terms of a range of economic and environm ental factors, if renewa ble fuel use increases to the level required by the RFS2 standards. We then compare this to two reference cases in which the RFS2 standards are not met. The prim ary reference case is a projection made prior to EISA by the US Energy Informa tion Administration (EIA) in their 2007 Annual Energy Outlook (AEO2007) of renewable fuel volumes that would have been expected in 2022 (13.56 billion gallons). We then combined this with AEO2009 energy consumption and cost estimates. While AEO2007 is not as up-to-date as AEO2009, we could not use later projections by EIA for renewable fuel use because they already include th e impact of the RFS2 standards as required by EISA as well as fuel economy improvements under CAFE as required in EISA. Upon completion of our fuel cost analyses as describe d in Chapter 4, however, it became apparent that by 2022, we are projecting that renewable fuel production costs will decline and crude oil prices rise to the point that renewable fuels are less expensive than gasoline and diesel fuel, even in the absence of any tax subsidies. One of the prim ary drivers for this is the fact that AEO2009 projects $116 per barrel of crude oil in 2022 (i nstead of the $53 per barrel projection in AEO2007). This implies that market forces will lead to a greater increase in renewable fuel volumes than was projected in AEO2007, even in the absence of the RFS2 standards.

However, it is difficult to estimate the extent to which these market forces, in the absence of the RFS2 standards, would indeed spur inve stments to increase renewable fuel production and usage. Given the magnitude of the capital inve stment needed for the RFS2 renewable fuel volumes, the risk associated with these investment s due to the fact that for the bulk of the volume we are relying on new cellulosic biofuel technology, and the uncer tainty in future crude oil prices, market forces alone may result in a level of investment insufficient to achieve the renewable fuel volumes mandated by RFS2. EPA believes that cellulosic renewable fuels are least likely to achieve the RFS2 mandates due to market forces alone. While current DOE and USDA programs are helping to stimulate the market for cellulosic renewable fuels, investment in Formatted: Indent: First line: 0"

Deleted: The analyses in t

Deleted: the

Deleted: d

Deleted: assuming compliance with

Deleted: ¶

Deleted: ¶ An RIA typically assesses the impacts of a new regulatory program and serves as the technical basis for the final standards that are being established.

Deleted: going forward

Deleted: We assessed the impacts of the EISA mandated volumes relative to two reference cases; t

Deleted: first

Deleted: prior to EISA

Deleted: , and where possible a second reference case consisting of the RFS1 mandated volume. ¶ ¶ The quantified impacts resulting from our analyses, however, may not be entirely attributable to the standards in the rulemaking. The primary case analyzed in the RIA and carried out across all of our analyses was to assess the impacts of the mandated RFS2 renewable fuel volumes relative to the volumes projected by EIA in AEO2007.

Deleted:

Deleted:

Deleted: If the AEO2007 forecast represents an accurate projection of the renewable fuel volumes that would have happened absent the RFS2 mandate, then the results of our analysis can properly be viewed as the impacts of the RFS2 standards. However, upon

Deleted: , resulting in a cost savings

Deleted: The fuel cost savings from the increased use of renewable fuels calls into question the degree to which the renewable fuel volumes mandated by

Deleted:

Deleted: As a result,

Deleted: ascertain how much of the impacts quantified in this RIA might be

Deleted: as crude oil prices rise versus what might be forced by the RFS2

Deleted: we believe it is unlikely that these investments would occur anytime in

Deleted: the

Deleted: mandate ... [3]

... [4] ... [2] ... [1]5 this segment of the fuels market is still very limited. The limitations of market forces are reflected in the projections of AEO2009, which de spite projecting large increases in oil prices still projects that renewable fuel volumes will be less than those required by RFS2.

Given the difficulty in projecting renewable fuel volumes in the absence of the RFS2 standards, EPA chose to rely on the projections in AEO2007 as its primary reference case. EPA believes that the actual renewable fuel volumes achieved in the absence of the RFS2 standards would fall somewhere between its reference cas e projections and the volumes mandated by RFS2. The impacts estimated in this RIA theref ore cannot be interpreted as the impact of the RFS2 program itself. Rather, they are an estimate of the impact of an increase in use of renewable fuels, whether caused by RFS2 or by market forces.

Another important limitation of this analysis is that it does not consider certain offsetting effects. In particular, for our emissions (GHG and non-GHG) a nd air quality analyses we have assumed that the production of renewable fuels to satisfy the RFS2 results in an energy equivalent decrease in production of petroleum-derived fuels. This is despite the fact that our other analyses predict that increased renewable fuel use will reduce worldwide crude oil prices, which in turn could lead to an increase in the quantity of crude oil demanded. Thus, there may be offsetting effects that are not completely captured by our analysis. For example, an increase in world demand for crude oil resulting from depressed prices caused by the increased use of renewable fuels in the U.S could partially offset some of the decrease in GHG emissions we have projected. At the same time, there may be other indirect impacts as well that might go in the opposite direction, since cr ude oil is used for more than just the gasoline and diesel fuel being displaced by renewable fuels.

The table below provides the results of many of the analyses contained throughout this RIA. Only shown are the results for the RFS2 volume control case relative to the AEO2007 reference case, and only the results for 2022 when the program is fully phased in. Deleted: Third, the bulk of the increase in volume and the bulk of many of the impacts assessed relative to the reference case are due to the impacts of the mandated use of cellulosic biofuels; those least likely to occur due to market forces alone. Finally, it is worth noting that even with $116 per barrel crude oil and the RFS2 mandate in place, EIA in their AEO2009 forecast still projected a shortfall in cellulosic biofuel and overall renewable fuel volumes relative to the RFS2 volumes required in EISA. Presumably AEO2007 would have projected higher renewable fuel volumes than it did had it assumed $116 per barrel instead of its assumption of $53 per barrel. However, it clearly would not have projected full compliance with the RFS2 volumes.

Deleted: We also note that the projected fuel cost savings results in additional sources uncertainty in some of our analyses that we were not always able to evaluate.

Deleted: additional

Comment [A1]: It is difficult for someone who only reads the Overview to understand the impacts listed in the table. OMB would like EPA to write several paragraphs, explaining what each of the rows in the table represent. A few sentences about each row in the table, explaining why an increase in renewable fuel use results in such an impact, would greatly enhance the Overview.6 Impact Summary of the Renewable Fuel Volu mes Required by RFS2 in 2022 Relative to the AEO2007 Reference Case (2007 Dollars) Category Impact in 2022 Chapter Discussed Emissions and Air Quality GHG Emissions -138 million metric tons 2.7 Non-GHG Emissions (criteria and toxic pollutants) -1 to +10% depending on the pollutant 3.2

Nationwide Ozone +0.12 ppb population-weighted seasonal max 8hr average 5.4

Nationwide PM 2.5 +0.002 μ g/m 3 population-weighted annual average PM 2.5 5.4

Nationwide Ethanol +0.409 μ g/m 3 population-weighted annual

average 3.4

Other Nationwide Air Toxics -0.0001 to -0.023 μ g/m 3 population-weighted annual average depending on the pollutant 3.4

PM 2.5 -related Premature Mortality 33 to 85 additional cases of adult mortality (estimates vary by study) 5.4

Ozone-related Premature Mortality 36 to 160 additional cases of adult mortality (estimates vary by study) 5.4

Other Environmental Impacts Loadings to the Mississippi River from the

Upper Mississippi River Basin Nitrogen: +1.43 billion lbs. (1.2%) Phosphorus: +132 million lbs. (0.7%) 6.4

Fuel Costs Gasoline Costs -2.4¢/gal 4.4 Diesel Costs -12.1 ¢/gal 4.4 Overall Fuel Cost -$11.8 Billion 4.4
Gasoline and Diesel Consumption - 13.6 Bgal 4.4

Capital Costs Total Capital Costs Thru
2022 $90.5 Billion 4.4

Food Costs Corn +8.2% 5.1 Soybeans +10.3% 5.1 Food +$10 per capita 5.1

Economic Impacts Formatted: Font: Bold Deleted: Standards

Deleted: Total Capital Costs Thru 2022

Deleted: $90.5 Billion

Deleted: 4.47 Energy Security +$2.6 Billion 5.2 Monetized Health Impacts -$0.63 to -$2.2 Billion 5.4

Monetized GHG Impacts (SCC) a +$0.6 to $12.2 Billion (estimates vary by SCC assumption) 5.3

Oil Imports -$41.5 Billion 5.2 Farm Gate Food +$3.6 Billion 5.1 Farm Income +$13 Billion (+36%) 5.1 Corn Exports -$57 Million (-8%) 5.1 Soybean Exports -$453 Million (-14%) 5.1

Total Benefits in 2022 b +$13 to $26 Billion (estimates vary by SCC assumption) 5.5

a The models used to estimate SCC values have not been exercised in a systematic manner that would allow researchers to assess the probability of different values. Therefore, the interim SCC values should not be considered to form a range or distribution of possible or likely values. See Section 5.3 for a complete summary of the interim SCC values.

b Sum of Overall Fuel Costs, Energy Security, Monetized Health Impacts, and GHG Impacts (SCC) in 2022. This measure does not include the costs of the investments needed to increase renewable fuel production. Those capital costs through 2022 total to $90.5 billion.

The document is organized as follows:

Chapter 1: Renewable Fuel Production and Consumption This chapter describes the various feedstocks a nd renewable fuel types th at could potentially be used to meet the renewable fuel volumes required by EISA. The availability and challenges of harvesting, storing, and transporting these feedst ocks are discussed, as well as the different renewable fuel production technologies, i ndustry plans, and potential growth projections for future facilities. A discussion of renewable fuel distribution and consumption is included. Chapter 1.2 defines the reference and RFS2 control cases that were used throughout the rest of this Regulatory Impact Analysis to assess the impacts of the increased renewable fuel volumes needed to reach the RFS2 mandated volumes.

Chapter 2: Lifecycle GHG Analysis This chapter describes the methodology used to determine the lifecycle greenhouse gas (GHG) emissions of the renewable fuels requi red by EISA, and to determine which fuels qualify for the four GHG reduction thresholds esta blished in EISA. Future incl usion of other feedstocks and fuel is discussed, as well as the ov erall GHG benefits of the RFS program. It also contains our assessment of the GHG emission reductions projected to result from the increased use of renewable fuels.

Chapter 3: Impacts on Non-GHG Pollutants This chapter discusses the expected impacts of increased renewable fuel volumes on emissions of hydrocarbons (HC), oxides of nitrogen ( NOx), carbon monoxide (CO), particulate matter (PM10 and PM2.5), sulfur oxides (SOx), ammoni a (NH3), ethanol, and ai r toxic emissions of benzene, 1,3-butadiene, acetaldehyde, formaldehyde, acrolein, and naphthalene. Emissions from Comment [A2]: OMB is concerned that “net benefits” might be misleading, since a quick reader might misunderstand the fact that the capital costs associated with the necessary investments are not reflected in this number for 2022.

Deleted: Net

Deleted: biofuel standards

Deleted: bio

Deleted: bio

Deleted:

Deleted: of the Program

Deleted: this proposed program8 vehicles and off-road equipment, as well as emissions from the entire fuel production and distribution chain are considered. . This chapter also presents the projected impacts of increased renewable fuel volumes on ambient concentrations of PM 2.5 , ozone and air toxic pollutants, and describes the health and environmental effects associated with these pollutants.

Chapter 4: Impacts on Cost of Renewable Fuels, Gasoline, and Diesel The impacts of increasing the use of renewable fuels on the production and distribution costs of transportation fuels are discussed. Renewable fuel production and distribution costs are presented along with their impact on gasoline and diesel fuel costs. Per-gallon and nationwide costs are presented.

Chapter 5: Economic Impacts This chapter summarizes the impacts of increased renewable fuel use on the U.S. and international agricultural sector, U.S. petroleu m imports, and the consequences of reduced oil imports on U.S. energy security. It also examines the greenhouse gas benefits and the copollutant health and environmental impacts from the wider use of renewable fuels in the U.S. needed to meet the RFS2 mandated volumes

.
Chapter 6: Impacts on Water This chapter discusses the impacts of increased renewable fuel volumes on water quality and quantity. Changes in the Upper Mississippi River Basin watershed were modeled.

Chapter 7: Final Regulatory Flexibility Analysis The Final Regulatory Flexibility Analysis ( FRFA ) evaluates the impacts of the RFS2 standards

on potential small entities. In developing the FRFA , we conducted outreach and held meetings with representatives from the various small entities that could be affected by the rulemaking. Small business recommendations and final rule provisions are discussed.

Appendix EPA conducted a comprehensive analysis of the NOx, PM, HC, and CO emission impacts of biodiesel blends based on heavy-duty, in-use diesel chassis a nd engine exhaust em issions data. Deleted: impact of

Deleted: proposed program

Deleted: ethanol, biodiesel, gasoline and diesel

Deleted: with and without ethanol subsidies

Deleted: and Benefits of the Program

Deleted: the RFS2 proposal

Deleted: Also, it

Deleted: bio

Deleted: from this proposal

Deleted: The impacts of this proposed program on different bodies of water are discussed. Aspects include feedstock production, ecological impacts, climate change, ethanol production, biodiesel production, and drinking water and public health issues.¶

Deleted: Initial

Deleted: IRFA

Deleted: potential

Deleted: proposed

Deleted: IRFA

Deleted: using

Deleted: The emission impacts on NOx, PM, HC, and CO of 20 volume percent biodiesel fuels produced from various animal- and plant-based feedstock materials tested under several cycles in this analysis.9 

## 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 Area10 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)11 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 Hydrocarbons12 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 Group13 RSM Response Surface Model RVP Reid Vapor Pressure S Sulfur SBA Small Business Administration SBAR Panel, or ‘the Panel’ Small Business Advocacy Review Panel SBREFA Small Business Regulatory Enforcement Fairness Act (of 1996) scf Standard cubic feet SER Small Entity Representative SI Spark Ignition SOA Secondary Organic Aerosol SOC Secondary organic carbon SOC Soil organic carbon SOx Oxides of Sulfur SULEV Super ultra low emission vehicle SVOC Semi-volatile organic compound T50 Temperature at which 50% (by volume) of fuel evaporates (ASTM D 86) T90 Temperature at which 90% (by volume) of fuel evaporates (ASTM D 86) TAME Tertiary Amyl Methyl Ether
Ton 2000 lbs Tonne Metric tonne (equivalent to 1.1 tons); also metric ton TRQ Tariff rate quotas ULEV Ultra low emission vehicle U.S.C. United States Code USDA U.S. Department of Agriculture VGO Vacuum Gas Oil (a refinery stream) VMT Vehicle Miles Traveled VOC Volatile Organic Compound vol% Percent by volume, volume percent WDGS Wet Distillers Grain w/ Solubles wt% Percent by weight, weight percent yr, y Year14 

## 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 technologies improve, we expect more emphasis on using cellulosic feedstocks such as agricultural residues, forestry residues, etc. However, limitations may occur due to concerns over sustainable removal rates for initial cellulosic feedstocks. Thus, dedicated energy crops which are touted as requiring low fertilizer and energy inputs as well as having the ability of being grown on marginal lands may also enter the market. The following sections discuss the current and potential availability of biofuel feedstocks and the potential challenges that must be overcome in order for enough feedstock to be collected and converted to biofuel to meet the EISA requirement of 36 billion gallons of renewable fuel by 2022.

1.1.1 Starch/Sugar Feedstocks

The following sections describe starch and sugar feedstocks that can be used to produce ethanol. Currently, the majority of ethanol that is produced in the U.S. is from corn. Recently, there have been plans to convert sugarcane gr own in the U.S. into ethanol as well as the introduction of relatively ne w crop varieties for biof uel 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 billion gallons of corn ethanol could be produced by the 2016-18 timeframe, see Table 1.1-1. 1 For the final rule, we modeled 15 billion gallons of corn ethanol to meet the EISA standards. We used the Forestry and Agriculture Sector Optimization Model (FASOM) and the Farm and Agricultural Policy Research Institute (FAPRI

CARD ) model to assess the impact of increased renewable fuel volume from business-as-usual on crop acreage, crop allocation to fuel vs. other uses, costs, etc. See Section 1.2 for more discussion on the renewable fuel volumes assumed for our analyses and Chapter 5 of the RIA for more details on the agricultural modeling. Impor tant modeling parameters considered include crop yields and ethanol yield pe r 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.15 Table 1.1-1. Corn Ethanol Production Fo recast 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/ 81 a 185 41% 2.85

EPA FRM Analysis (Higher Yield Case) 15/2022 77/71 a 233 36% 2.85

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, Miss ouri, Nebraska, Ohio, South Dakota, and Wisconsin. 2 See Table 1.1-2.

Table 1.1-2.

U.S. Corn for Grain Area Harvested by St ate 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 185 bu/acre in 2022, with speci fic yields calcula ted at the regional level. The national average depends on crop pr oduction in each region in a given year (see Chapter 5 of this RIA). These yield increases over time are consistent with the United States Department of Agriculture (US DA) projections. 4 As further described in Chapter 5, we also investigated a

A Calculated from 1977-2007. Deleted: 87 a

Deleted: 183

Deleted: 35%

Deleted: XX

Deleted: 230

Deleted: XX

Deleted: XX

Deleted: 18316 higher corn yield scenario of 233 bu/acre in 2022, developed in c onsultation 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 etha nol (33 percent), exports (16 percent), and human food and seed (9 percent). 5 For the final rule, the FASOM projects that approximately 41 percent of corn would need to be allocated to the ethanol industry by 2022 under the base corn yield assumption and 36 percent of corn under the higher corn yield assumptions to produce 15 billion gallons of corn ethanol.

The amount of corn allocated to fuel vs. other uses has cause d much controversy over the production and use of corn-based etha nol in the past few years. Th ere is concern that the use of corn for fuel could potentially dive rt 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 coul d decrease the amount of land necessary for a fixed amount of renewable fuel produced. We rely on our modeli ng 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 industr y optimization of cooking, mashing, and fermentation conditions has incr eased the amount of ethanol produced from a bushel of corn. According to USDA reports, by about 2010 we can e xpect all plants on-line to yield an average of 2.76 gallons per bushel. 6,7 In addition, based on discussi ons with USDA, we believe it is reasonable to expect an increase in corn kernel starch content of 2-4 percent over the next decade Deleted: 230

Deleted: 35

Deleted: XX17 through advances in plant breeding and new corn va rieties. Combining these figures, we project industry average denatured ethanol yields to r each 2.85 gallons per bushel by 2022 for dry mills and 2.63 gallons per bushel for wet mills. See Section 1.4 of this RIA for more information on corn ethanol biofuel production technologies, e.g. dry mill vs. wet mill.

Other grains that can be processed into et hanol include grain sorghum (milo), wheat, and barley. The production of ethanol from these grains generally involv es the same processes as the production from corn, and can be used together in the same plant.

1.1.1.2 Imported Sugar Ethanol

After corn, sugar crops (i.e. sugar beets and sugarcane) are the world’s next largest feedstock sources for ethanol. 8,9 Sugar beets are mainly grown in France, Germany, and in the U.S., with the majority of the feedstock typical ly used to produce sugar for food and feed. Compared to sugar beets, sugarcane is produced in much higher volume and has been able to support a growing sugar and ethanol market. Due to a higher availability of sugarcane feedstock for ethanol production, we expect that imported ethanol to the U.S. will likely come from

sugarcane.

World production of sugarcane is approximately 1.4 billion metric tons (MT) and is concentrated mainly in tropical regions, particularly in Latin America, Africa, and South and Southeast Asia. Roughly 100 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 arable land is cultivated, totaling 156 million acres. The following Table 1.1-3., describes the land available/used in 2007. As there are 494 million acres of pastureland and a considerable area of unused arable land (190 million acres), it is believed that there could be a large expansion in sugarcane. 12

Table 1.1-3. Brazil Land Areas in 2007. 13

Brazil (Total Area) 2100

Total Preserved Areas and Other Uses* 1260
Total Arable Area 840

Cultivated Land (All Crops) 156

Soybeans 51 Corn 35 Oranges 2 Sugar Cane 19

Sugar Area 11
Ethanol Area 8 Pastureland 494 Available land (ag, livestock) 190 Million Acres

*Areas include Amazon Rain Forest, protected areas, conservation and reforestation areas, cities and towns, roads, lakes, and rivers.

The statistics above, however, do not indicate whether the land available requires any additional usage of water or has the proper soil and climate conditi ons for sugarcane. According18 to one study, there is at least 148 million acres of additional land available with proper soil and climate conditions for sugarcane without utilizing environmentally protected land (i.e. Amazon and native reserves) and w ithout the use of irrigation. 14 This translates to approximately 90 billion gallons of ethanol potential (using a yield of approximately 600 gal/acre which is a conservative estimate based on existing technology). Although it is not probable that all this land will be converted to sugarcane ethanol, the estimate puts into prospective the large potential for sugarcane ethanol to be produced in Brazil.

Another study commissioned by the Brazilian 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 an estimate of the available land that could be used for sugarcane expansion . The potential fuel volume from these acr es is dependent on whether or not irrigation takes place. Overall, with greater irrigation, more acres are available that fall in the higher potential yield categories than without irrigation

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

Table 1.1-4. Potential Volumes Utilizing Availa ble 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 sugarc ane 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 Laborat ory (ORNL) Biofuel Feedstock Assessment for Selected Countries report suggests that perhaps more than 30 billion gallons of ethanolequivalent fuel could be produced from available sugarcane supply by 2017. Brazil is estimated to produce approximately 2/ 3 of the potential supply. The majority of this supply would likely be consumed within the country, with the leftover potentially available for export to the U.S. and other countries. Recent government and industry estimates indicate that approximately 3.8-4.2 bgal of ethanol could be ava ilable for export 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 of

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. Deleted: calculated

Deleted: at various crop yields with and

Deleted: and the potential volumes that could be attained.

Deleted: .119 this RIA for further details on Brazilian ethanol production and consumption. Thus, there appears to be a large enough pot ential for Brazil to increase produc tion 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 res ources, appropria te 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 r eallocation of arable la nd for biofuel production. Although Argentina and Columbia have significant underutilized lands available, these resources generally do not have suitable soil and climate characteristics for sugarc ane production. Due to these factors, Brazil is the most likely country able to produce substan tial volumes of sugarcan e 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 produc ing ethanol from sugarcane, suga rbeets, and molasses, showing that it is economically feasible to convert th ese feedstocks into et hanol (see Section 1.1.1. 2 ). However, the economics of producing ethanol from sugar feedstocks in these countries is not directly comparable to the ec onomics of producing ethanol from su gar 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. Suga rbeets, on the other hand, are grown in more northern states, with the major ity of production in Minnesota, Mi chigan, and Idaho as shown in Table 1.1-6. As noted, these feedstocks are not currently us ed for commercial production of ethanol, however, this may change in the near future.

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

State Total Harvested 2008 (1000 Acres) Total Harvested 2009 (1000 Acres)

Florida 384 372
Hawaii 20 20
Louisiana 380 375
Texas 37 39

Total 821 806 Deleted: 320 Table 1.1-6. Sugarbeet Area Ha rvested 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 can e’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 facility that produces 60 million gallon per year of sugarcane ethanol and 50 me gawatts 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 will replace forage crops like alfalfa, Bermuda grass, Klein grass, etc. Harvesting is expected to be fully mechanized . Another company is Pacific West Energy LLC which plans to produce 12-15 million gallons per year of ethanol on the island of Kauai in Hawaii, perhaps as early as 2010. Hawa ii is well suited for sugarcane ethanol production due to several f actors, including lower costs fo r 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 Sugarc orn 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 beve rages, crystal sugar, etc. Th e interest in bi oenergy production from sweet sorghum comes from the easy accessibilit y of readily fermentable sugars combined with very high yields for biom ass. Yield varies with location and variety and ranges from 8-49 tons/acre. After extraction of the juice, the bagasse can also be used as cellulosic feedstock or other purposes. Groups interested in building facilities in the U.S. that can process sorghum juice21 include the Tampa Bay Area Etha nol 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 dedicat ed energy crops. We describe each type in the following sections.

1.1.2.1 Agricultural Residues

The harvesting of agricultural residues coul d 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 produ ce 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 operati on. We discuss harvesting limitations due to maintaining soil health below, while mechanical efficiencies, storage, and transport issues are discussed in Section 1.3 of this RIA. Feedstock costs are discussed in Section 4. 1.1.2 of the RIA.

Sustainable Removal

In terms of soil health, residues perform many positive functions for agricultural soils. Recent studies and reviews have attempted to address these issues. Existing research can be used to some extent to guide practices or make estim ates, 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 Resear ch Service (ARS) scientists, Wilhelm et al. acknowledged the complexity of interactions between soil type, climate, and management when considering crop residue effects on soil. They recommended that remo val rates be based on regional yield, climatic conditions and cultu ral practices, with no specific rates given. 25 Using the Revised Universal Soil Lo ss Equation (RUSLE) technology and the Wind Erosion Equation (WEQ), Nelson predicted safe residue removal rates for minimizing soil loss in the Eastern and Midwestern U.S. These predictions varied widely over time and location as a result of the complex interactions disc ussed 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 informati on was needed on the long term effects of residue harvest, including: 1) water quality; 2) soil biota; 3) transformations of different forms of soil organic carbon (SOC); and 4) su bsoil SOC dynamics. 28 Current USDA Natura l Resource Conservation Service (NRCS) practice standards for residue management do not recommend specific residue quantities and point to the use of the RUSLE2 model for guidance. 29 Despite broad recognition of the need for specific guidelines for residue remo val, 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. Deleted: XX22 Residues have not yet been removed at the contemplated rates over a period sufficiently long for the effects to be clearly determined. Another difficulty is that while the effects of removing a residue may appear to one observer to have affect ed the soil in a certain manner, it may not be completely clear that the observed effects were fully related to the residue removal or, were in fact related to a change or to combinations of 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 differe nt interactions among them th at assigning effects is very difficult at best. There simply are no real-world data available for determining long-term effects. Nevertheless, we can describe some of the interactions that take place and how they can potentially affect soil health.

Soil erosion is an extremely important national issue. Most, if not all, agricultural cropland in the United States experiences some de gree of soil erosion each year due to rainfall (water) and/or wind forces. Rainfall erosion (sheet and rill) occurs when rain directly strikes the soil, dislodging particles in the top layer. C When soil becomes saturated, particles are transported down the slope of the field. Soil erosion due to wind occurs in much the same manner as rainfall with wind forces dislodging soil particles a nd carrying them along and above the field surface (creep and saltation) or suspending them above the field. D While eroded soil does not disappear, the erosion pro cess moves soil particles 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 preparation for the next crop, timing of field operations, present throughout the year, soil type, field characteristic s such as field slope, and the amount of residue (cover) left on the field from harvest until the next crop planting. Crop rotation cover provided by agricu ltural crop residues, both fallen and standing, helps to minimize rainfall and wind energy as it strikes or blows ac ross the ground as well as helping to keep soil particles from being transported after they have been dislodged. Climatic conditions such as rainfall, wind, temperature, etc. must be accounted for. Studies predict that up to 30% of surface residue can be removed from some no-till systems without increased erosion or runoff.

The NRCS has established tolerable soil loss limits (T values) for all soil types in all counties throughout the United States. The tolerable soil loss valu es 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. Tole rable soil loss limits take into account the rate of topsoil formation, role of topsoil formation, loss of nutrients, erosion rate at which gully erosion would commence, and potential erosion-control fact ors that farmers would be able to implement. However, T values are not a function of the type of crop grown.

Another important aspect associated with soil conservation involves soil tilth. Soil tilth is defined as the physical condition of the soil as related to its ease of tillage, fitness as a seed bed, impedance to seedling emergence and root penetration, and all other physical conditions that

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 blowing23 influence crop development. Tilth depends upon soil granulation and its stability (soil workability) as well as organic matter content, moisture content, porosity, water retention, degree of aeration, rate of water infiltration, drainage, and capillary-water capacity, all of which are affected by crop residue removal. Preliminary values of required tilth have been estimated by the NRCS.

Various tillage operations are associated with management of agricultural crop residues and planting preparation throughout the year. Type and number of tillage operations employed for any particular crop from the time of harvest un til the next planting have a tremendous effect on the amount of soil lost to erosion during the year, and hence, the amount of residue that can possibly be removed for energy purposes. It mu st be noted that even though crop residues may be used for energy purposes, the farmer is, firs t and foremost, in the bus iness 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 whic h nearly any crop is grown within a particular county can exhibit a wide variation in soil erodibility, field slope and length, climate conditions, and management practices. Within any one particular county there can be ma ny 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 ag ricultural crop production. Some soils possess characteristics that make them highly susceptible to erosion that may not be able to sustain certain cropping practices . Production of conventional agri cultural crops on these lands may severely and/or perm anently 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 contribut or to new SOM, making residues less important for carbon accrual. Residue removal leading to higher erosion and runoff rates would greatly decrease SOM and nutrients. Residue harvest may also require increased fertilizer inputs to make up for nutrients removed in the plant materi al. When returned to the land, crop residue also replenishes soil organic carbon (SOC) that t ypically has already been reduced 30 to 50% of precultivation levels through crop production activities. Soil organic carbon retains and recycles nutrients, improves soil struct ure, enhances water exchange characteristics and aeration, and sustains microbial life within the soil. It’s been reported that crop yield and the value of environmental services (C and N sequestration) were greater for soils with greater SOC. Limited research has shown that removing stover reduces grain and stover yield of subsequent crops and further lowers soil organic matter levels. 31

Residue removal can result in detrimental changes in many biological soil quality indicators including soil carbon, microbial activ ity, fungal biomass a nd earthworm populations, indicating reduced soil function. Some disease- producing organisms are enhanced by residue removal, others by residue rete ntion, depending on crop and region. Residue cover can also reduce evaporation from the soil surface, thereby conserving moisture and increasing the number of days a crop can survive in drought conditions. Improved soil physical properties related to24 crop residues, such as reduced bulk density, e.g. , the soil is looser and lighter, and greater aggregate stability, also lead to better water infiltration and retention.

In colder climates, residues are linked to reduced yields due to lower soil temperatures resulting in poor germination. Stubble mulching, as opposed to residue chopping, can help overcome this problem. Even though residue-a ssociated yield reducti ons have been found on poorly drained, fine-textured so ils, these soils often have low erosion risk and residues might safely be removed.

Despite the many important be nefits of crop residues, res earch 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 reported higher yields when soil moisture is limiting. Other studies suggest that residues do not contribute significantly to soil carbon. Many studies found that additional N fertilizer is needed when residues are left on soils to avoid N uptake (immobilization) from soil or allow for soil carbon accrual. Fo r appropriate residue removal recommendations, the cond itions 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 rem oval. Wrong decisions, carried out over extended periods could have far reaching deleterious effects. Sustainable residue removal rates for biofuel production vary by system, according to such fact ors as management and cropping practice, crop yield, climate, topography, soil type and existin g soil quality. Keeping in mind that gravimetric rates are not the same as percent soil cover (% mass is not the same as % coverage), appropriate conversion is necessary and varies by crop and region. While areas with low slopes and high yields may support residue harvest, in many ar eas the residue amounts re quired 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 dete rmination also depends on soil type and other cropping practices. Removal rates will need to be reduced as climates become warmer or more humid, for lower C:N residue or lower yielding crops, as soil disturbance (e.g. tillage) increases, or as soils become coarser textured, compared to the conditions in which most studies occurred (in the U.S. Midwest Corn Belt for no-till corn). 32 The most important aspect of this is that any or all of the interacting variables that determine how much residue can be removed, can, and usually do, change from year-to-year, across both wide regions of the country as well as across single counties and farms. A change in one variable nearly always changes how all the variables interact.

Given all the issues we’ve discussed regarding residue removal and soil health, rather than try to predict, county-by-county how much re sidue 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 discussed are settle d. We based the amount removable based on the tillage practice: 0% removed for conventional tillage, 35% removed for conservational tillage, and 50% removed for no-till for corn stover. 33 Removal rates for wheat straw were based on the Billion Ton study. 34 We believe that given the uncertainties in removal rates, our assumptions are reasonable.25 Agricultural Residue Summary

Corn and wheat are currently receiving the most attention across the industry due to their concentrated production areas and because they gene rate the majority of total residue produced. This also means they will more likely be able to support commercial scale production. In aggregate, the other residues provide fairly significant quantities of material, but because they are spread out, e.g., less densely planted both in the field and in a county or state, they are less likely able to support commercial operations.

We analyzed various reports on the availability of agricultural residues. These are summarized in Table 1.1-7. The agricultural residue estimates in Table 1.1-7 are based on historical/recent data, and thus, could be consid ered conservative in comparison to the future (2022) which would typically have higher crop yi elds or increases in acres harvested.

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

Source Total Available Total Removable Sustainably Crops Analyzed

USDA >500 million tons not specified Eight leading U.S. Crops, e.g. corn, wheat, soy, oats, barley, rice (did not specify other two)

NREL 495 million tons 173 million tons Corn, wheat, soybeans, cotton, sorghum, barley, oats, rice, rye, canola, beans, peas, peanuts, potatoes, safflower, sunflower, sugarcane, and flaxseed

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

Walsh not specified 144 million tons at $40/dry ton, ~150 million tons at >$40/dry ton for corn; 7 million tons at $40/dry ton, ~10-11 million tons at >$40/dry ton for wheat Corn and wheat

Graham 216 million tons 65 million tons at 30% removal rate and current conditions; 112 million tons at 50% removal rate using no-till conditions Corn

Based on our FASOM modeling for the final rule, corn st over was the most economical agricultural residue projected to be used to produce ethanol in order to meet the 16 Bgal EISA cellulosic biofuel requirement. We estimate that by 2022 greater than 400 million tons of corn stover could be produced. Approximately 53 million tons of corn stover would be needed to produce the 4.9 billion gallons of cellulosic biofuel estimated to be used by our agricultural modeling in 2022. E See Table 1.1-8. Smaller amounts w ill be required from sugarcane bagasse, wheat residue, as well as sweet sorghum pulp (bagasse) to produce another 0.8 billion gallons of cellulosic biofuel. F Thus, the residue collected to meet EISA would be a small fraction of the total residue produced nationwide – though potentially highe r fractions in some local areas . See Section 1.8.1.3 for more details on the use of ag ricultural residues for our cellulosic plant siting analysis developed for the air quality modeling

.

E Assuming conversion yield of 92.3 gal/dry ton as updated by NREL yields.

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.26 Table 1.1-8. FASOM Estimated Agricultural Residue Feedstock Availability in 2022 (million tons) G

State/Region Total
A labama 0.0 1.9 0.0 0.0 0.1 0.2 2.2
A rizona 0.1 0.1 0.0 0.0 0.0 0.4 0.7
A rkansas 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 t on/bu for wheat.27 1.1.2.2 Dedicated Energy Crops

Crops developed and gr own specifically as a renewable source of cellulosic material for biofuel production are not yet commercial, but have significant potential. Currently, crops such as corn that are grown and harvested for energy uses in the United States are also used for agricultural purposes and serve many important uses other th an biofuel production. This competition could be reduced by the use of non-agricultural feedstocks for cellulosic biofuel production. Urban wastes and fore st and agriculture residues could likely be the first feedstocks used in cellulosic biofuel production due to lower feedstock costs and availability; However, there are many uncertainties over land availability and sustainable removal rates for residues.

Many of the energy crops investigated are perennial species grown from roots or rhizomes that remain in the ground after harv esting the above-ground biomass. While most agricultural crops are annual speci es, perennials are considered beneficial in many ways. Dedicated perennial energy crops have the potential to grow on marginal lands, produce high yields, and may have low input needs. Once a pe rennial crop is establishe d costs are reduced, as the need for tillage is lowered. The root system that remains in the soil can also facilitate the acquisition of nutrients thus decreasing the need for large fertilizer inputs. In southern climates, perennials have the potential for hi gher yield per acre of land than annual crops. This is due to the fact that perennial plants de velop 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. Perenni al energy crops also increase soil productivity, sequester carbon, and provide refuge for wildlife.

The following sections desc ribe several of the most commonly discussed dedicated energy crops (switchgrass, miscanthus, and hybrid poplars) as well as some less familiarly known crops and the potential marg inal lands on which they can be grown. While not all of these energy crops were specifically modeled in our agricultural models, switchgrass (which is often used as the main “model” energy crop), was projected to be a likely and significant feedstock for the production of re newable fuel to meet EISA. H,40 For the final rule, FASOM projected that 7.9 ethanol-equivalent billion gallons out of the 16 billion gallon cellulosic biofuel required would come from switchgrass. See Chapter 5 for more details on the agricultural modeling.

Switchgrass

The energy crop that has received the most attention is switchgrass. Switchgrass is a perennial warm season grass that is native to the United States. It typically reaches heights of 3- 5 feet, but can grow to more than 10 feet in some southern regions. It has a deep root system that extends many feet below the earth. It may be the ideal energy crop mainly because it can tolerate many soil types and climates from drought conditions to floods. It is also resistant to many pests and diseases. Th e photosynthetic pathway of switc hgrass (and other perennials) allows it to produce high biomass yields with low amounts of chemical input. In the spring, switchgrass develops a photosynthe tic canopy of biomass more qui ckly, 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.28 longer in the fall than annual plants, allowing for a high net conversion of solar energy per

year. 41

Highly variable yields have been estimated at 1-12 dry tons/acre per year depending on soil, location, and variety. A yield of 4-5. 5 dry tons/acre is a reasonable average today. 42 In a long term study sponsored by the DOE, average yield after 10 years of growth was 4.8-7.6 tons/acre for switchgrass when harvested annually. I,43 Biannual harvests were also done experimentally to try and achieve the maximum yields possible but the harvests showed little difference in total yield. Bia nnual harvests resulted in approximately 70% of the yield for the first cut and 30% for the second. 44

Water and nitrogen availability are the main resources that limit production of warmweather grasses such as switchg rass. Nitrogen accessibility for these plants depends on many factors. Harvesting frequency, soil content, and removal rates all affect the nitrogen available to the plant. In a study by S.B. McLaughlin, initial nitrogen fertilization rates were 40-120 kg/ ha (36-107 lbs/ acre ) ; however they discovered that a reduction to only 20 kg/ ha (17.8 lbs/ acre ) of nitrogen was sufficient to produce similar yields in single cut systems in the mid-Atlantic region. 45 Reduced nitrogen amounts were sim ilar in other regions of the country.

Miscanthus

Miscanthus is a tall perennial grass that has been evaluated as a potential energy crop most extensively in Europe where it is alread y being grown for biofuel purposes. The genus is primarily tropic or sub-tropic in origin but there is a wide climactic range at the species level. 46 This characteristic makes it more suitable for establishment over the ranging climates of North America. Giant miscanthus ( Miscanthus x gigantus ) is a hybrid variety that can grow 12-14 feet tall. It is a cold-tolerant warm season grass and has similar characteristics to switchgrass with high yields and low amounts of input. 47 In the Midwest, the growing season of Miscanthus is April to October. The plant grows large green foliage that maximizes in approximately late August. As the temperature falls the foliage fades and drops off leaving the stem. The stem is the commercially important part of the plant and resembles bamboo. Stems can reach nine feet in length, 1⁄2 to 3⁄4 in diameter, and are 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 establ ished 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 fo r 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 conversi on to biofuel improves by dela ying harvesting until after the winter months and the plant has time to dry sufficiently. However, this reduced yields by 30 percent. 50 In comparison to switchgrass, research out of Illinois also concluded that miscanthus can yield more biomass for conversion to biofuel because of its even higher photosynthetic efficiency and longer growing season. 51 In terms of input, miscanthus uses nitrogen extremely

I Switchgrass variety used in this study was Alamo. Other varieties could result in different yields.29 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 y ear, and potentially high water needs. European cost estimates are similar to other perennial pl ants at approximately $64 per dry ton; however they estimate that a growing cycle of 10-12 years is required to recover the start-up costs of $267 per planted acre. 53 The bulk of the high initial cost comes from planting and harvesting machinery. Establishment of a stronger market for growing these energy crops, as well as increased knowledge of propagation of the species, will inevitably lower overhead costs. 54

Hybrid Poplar

The poplar tree is another option being investig ated for use as a dedi cated energy crop. Woody perennial plants have some of the same ch aracteristics of the pere nnial grasses that make them suitable for possible use as an energy crop. They reta in significant amounts of root biomass below ground, require little tillage, grow fast large canopies, and require less fertilization than their agricultural counterparts.

Technological advances in harvesting and gene tics may help produce species that will be more suitable for use as an energy crop. Ge netic information has he lped to understand the characteristics the poplar tree. The complex genetic information obtained from the genome of this plant will make possible the engineering of faster growing trees with more biomass available for harvest. 55

Other Potential Feedstocks

Several other perennial plants have the possibility to be used as dedicated energy crops. As previously described, the characteristics of perennial species make so me 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 about further knowledge of basic biology which will lead to advances in breeding and eventual domesti cation of the species that have promise. The DOE along with university researchers have identif ied several other plants as potential energy crops. These include additional ty pes of grasses such 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. Gu lf Coast, as commercially grown varieties can produce up to 40 dry tons per acre under optimal conditions. 57 Hybrid willow, silver maple, black locust, sweetgum, and eucalyptus are other perennial woody plants that are possibilities. 58

Significantly accelerated testing and selection for populations will be necessary in establishing these plants. Breeding for desired traits and adaptability across a wide array of environments in multiple physiologic and geographic regions will be necessary. No single species of dedicated energy plant will be optimal for all areas of the country, especially30 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 estimated where the possible growing areas could occur (see Figure 1.1-2). 59

Figure 1.1-2. Possible Geographic Distribution of Dedicated Energy Crops

Marginal Land Assessment

One of the benefits of perennial species is their suitability for growth on marginal lands. A study by Elliot Campbell of Stanford University assessed abandoned land availability and the potential for this land to be used for energy crops. 60 Because of the increased demand for biomass energy, using abandoned cr op or pasture lands to grow so me of these crops could be a better alternative than converting forested areas or using agricultu re lands. This study estimated the amount of global abandoned la nd available, the amount of bi omass 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 a nd not converted to urba n or forested areas. Historical land use data was obt ained from the History Database of the Global Environment 3.0 (HYDE) which consisted of gridded maps which show the fraction of crop and pasture land within each grid cell for decades between 1700 an d 2000. The Center for Sustainability and the Global Environment (SAGE) land use database was used to check and supplement the HYDE database. They used a MODIS satellite map to exclude areas that have transitioned into forest or urban areas. Two different mathematical approaches were then used to estimate a conservative and a high estimate of total land available. Bioma ss production was estimated using the Carnegie-Ames-Stanford Approach ecosystem mode l which takes into acc ount climate data, soil31 texture, land cover and the nor malized difference vegetation i ndex (NDVI), but does not take into account fertilizer use or irrigation, 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 natural growth on these lands, approximately 321 million tons/year of biomass could be produced. At just 80 gallons of ethanol per ton of biomass, there could be the potentia l 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 California each contribute over 5 million abandoned acres to the total. Midwestern states including Iowa, Wisconsin, Illinois, and Ohio have approxi mately 3-4 million acres of ab andoned 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 th at could be grown on these lands. Also, in the DOE assessment previously referenced, most of the Western states are not implicated as areas of possible biomass growth (above Figure 1.1-2).32 Table 1.1-9. Abandoned Agriculture Land and Potential Production by State 61

Area Area Production Ethanol Production Rate (Million ha) (Million acres) (MM tons biomass/yr) (gallons/tons)
A labama 1.4 3.46 13.2 3.82
Alaska 0.3 0.74 0.4 0.54
A rizona 1.9 4.69 2.4 0.51
A rkansas 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 Jersey 0.2 0.49 1.9 3.85
New Mexico 3 7.41 5.4 0.73
New York 1.7 4.2 10.2 2.43
North Carolina 0.7 1.73 6.2 3.59
North Dakota 1 2.47 4.4 1.78
Ohio 1.4 3.46 8.9 2.57
Oklahoma 1.1 2.72 8.8 3.24

Oregon 2.2 5.43 8.2 1.51 Pennsylvania 1 2.47 8.2 3.32
Rhode Island 0 0 0.2 0
South Carolina 0.8 1.98 7.3 3.69
South Dakota 0.3 0.74 2 2.7
Tennessee 1.1 2.72 10.3 3.79

Texas 4.2 10.37 25.3 2.44
Utah 2.6 6.42 4.7 0.73
Vermont 0.1 0.25 1 4.05 Virginia 0.7 1.73 6.7 3.88 Washington 0.9 2.22 4 1.8 West Virginia 0.1 0.25 0.5 2.02

Wisconsin 1.4 3.46 9.9 2.86 Wyoming 2.8 6.92 6.1 0.88

Totals 58.9 145.5 321

25.68 Bgal Ethanol/yr State

Total Ethanol Volume a a. Assuming a conservative 80 gal/ton conversion rate33 The estimates of abandoned agricultural la nd do not include land enrolled in the Conservation Reserve Prog ram (CRP), which could be an add itional source of land available for energy crops. Land in this program is farmland that is converted to trees, grass, and areas for wildlife cover, but is consid ered 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 gr ound 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 bene fits of producing energy crops will have to be weighed against the benefits of having the land in the CRP.

Figure 1.1-3. 2008 CRP Enrollment

1.1.2.3 Wood Residues

There is a substantial amount of forestland here in the U.S. It is estimated that 749 million acres, or one-third, of the U.S. land area is forested. Of this forested land, two-thirds (504 million acres) is considered timberland which contains more than 20 ft 3 of woody material per acre – the other one-third of the fore st land contains less than 20 ft 3 of woody material per acre. Most of this forested land, 58 percent, is privatel y owned, another 29 percen t of the forest land is publicly owned, and 13 percent is owned by the forest industry. A higher percentage of the land is privately owned in the East, and a higher per centage of the land is publicly owned in the West.34 Of the 749 million acres of forestland, 77 are reserved as parks or wilderness and would likely be considered off limits for harvesting for biomass. Also, 168 million acres of timberland is considered not suitable for harvesting for biomass because of poor soil, lack of moisture, high elevation, or rockiness. 65

The U.S. forestry industry harvests a portion of this forest land to produce its products, and in the process of doing so, it generates woody re sidues that can be recovered for the purpose of producing cellulosic biofuels. Major source s of solid waste wood generated in the U.S. include forestry residues, primary and secondary mill residues, and urban wood residues. All this material is being produced through the ever yday practices of the fo restry industry providing its products to the various industries it supplies. In addition, forests which are not currently harvested for wood could be thinned. This thinni ng of the forests would not just be to provide biomass, but as part of a strate gy which may be beneficial for th e forests, or to avoid external costs such as forest fires. Each of th ese categories is furt her 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 dead 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 other products such as millwork, containers and pallets, buildings and m obile homes, furniture, flooring a nd paper and paper products. While primary and secondary mills are typically separate facilities, both primary wood processing and secondary conversion to finished consumer products can occur in the same facility. 67 Both primary and secondary mills produce residue and woody waste material. For example, the residue generated by primary mills includes bark, slabs and edgings, sawdust and peeler cares. This waste material could be used as feedstock to produce biofuels.

Urban wood residues

The two principal sources of urban wood re sidues are municipal so lid waste (MSW) and construction and demolition (C&D) debris. Municipal solid waste contains solid wood from both wastewood and yard trimmings. Yard tri mmings include herbaceous material and woody35 trimmings. Construction waste is made of contemporary building materials with little contamination. Sources incl ude new residential construction, new nonresidential building construction and repair and remodeling of existing buildings. Demolition waste, on the other hand, is a heterogeneous mixture of material from demolishing bu ildings and structures and is difficult to remove uncontaminat ed portions. The potential cont ribution of urban wood residues to the production of biofuels is discussed in the Secti on 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 ma terial can provide a source of fuel for forest fires that are expensive to fight or contain. Over the previous 10 years forest fires have consumed 49 million acres and cost the U.S. taxpayer $8.2 billion. 68 This cost does not include the additional cost due to the loss of human life , the loss of personal property and the impact on the environment. Thinning forests involves the removal of excess forest material from the forests that could help to prevent some of these forest fires, or at least help to reduce their impact. Also, thinning these forests to prevent them from becoming overly dense could potentially help them to remain healthier. Th ere are many thinning operations today, but the material is burned or left to decompose inst ead. 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-use benefits (e.g., wildlif e habitat, recreation, and ecological and e nvironmental services). 69 This in effect makes it more difficult to take steps to increase the productivity of forest areas. Also, there are factors or site conditions that can affect tree growth, including poor soils, lack of moisture, high elevation, and rockiness. The limits caused by some of these factors would likely not be overcome, resulting in lower productivity than what could be theoretically possibl e. Also, a couple of th ese factors, the high elevation and rockiness, results in areas of forestland which is inaccessible by forestry equipment. Forestry residues are also demande d for other purposes other than for production of a transportation fuel (e.g. for process fuel). Th ese 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 bene fits to the use of woody residues. One example is the removal of excess forestry biomass to reduce the risk of fires and/or to improve forest health. In addition, resources such as primary and secondary mill residues and urban wood residues are already collected at the processing facility and it seems probable that some cellulosic facilities could be co-located to mills and/or landfills to increase the likelihood of having close and steady feedstocks readily available. Some states may also be endowed with larger wood resources than agricultural residues.36 In making estimates of potential forest re sidue availability, certa in assumptions about accessibility and recoverability are typically made. For example, some studies assume that residue collection is completed at the same time as harvesting, meaning that all residues are regarded as one hundred percent accessible. 70 This might become possible due to integrated harvesting systems which could harvest forest biomass in a single pass operation such that residual forest residue for producing biofuels c ould be produced along with conventional forest products. 71 Other estimates for accessib ility 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 re port 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 practi ces for crop residues, there has been less review on the topic for w oody 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 re iterated 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 ex ample, a district for one study on the removal of forestry residues require d about 5 tons per acre be left wh ereas other distri cts had no such requirements. 74 In a different source, a summary of na tional forest land management plans from 1995 indicated about 60 percent of western nationa l forest timberland base to be suitable for timber producti on 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 yet to be consensus over the optimal amount.

Some recent long-term soil productivity studies are beginning to provide some useful data post-harvesting. One study, which assessed the soil conditi on 5 years after harvest of the woody biomass, showed that for most of the s ites there was not a significant impact on soil carbon and nitrogen and compaction, while at one site there was a significant reduction of soil carbon and nitrogen. Another study which tracked the soil quality 10 years after harvesting the forest biomass came to some interesting conclusions. 77 Complete removal of the surface organic matter did lead to declines in the concentration of soil carbon, however, this effect was attributed to the loss of the forest floor. Soil compaction did reduce productivity in clay soils, but increased the productivity in sandy soils, and wa s not a factor if an understory was present. 78 Thus, these two studies suggest that forestry operations, if they are designed for the soil type and37 the area that the operations are taking place, may be designable to protect the sustainability of forests. However, add itional studies and data review is like ly necessary to fully understand these impacts.

Yet another issue regarding sustainable removal is the affect of forest residue extraction on biodiversity. The removal of forest residue may affect biodiversity because lower amounts of wood in the forest imply fewer habitats for speci es using wood for breeding. Species may also be threatened because certain insects colonize in wood that may be burned for energy purposes. Several forestry management methods, such as lower planting densities, aggressive thinnings, prescribed burning, and longer rota tions have been suggested as ways to maintain biodiversity in actively managed forests. 79 Quantitative predictions about how much habitat loss various species can tolerate are almost impossible to make. Instead, one study recommended making qualitative predictions on which types of habitats or wood types are most threatened. For instance, this study examined Swed en’s forest fuel ex tractions and conclude d that coniferous wood can be harvested to a rather large extent, whereas deciduous tree speci es should be retained to a larger degree. 80 Another study in the southern Appa lachians suggests that selective harvesting to maintain a forest with regions of ma ny different ages and st ructural classes is key to maintaining biodiversity. 81 As different regions will certainly have species specific to their own regions, more research is necessary to determine appropria te recommendations on maintaining biodiversity.

Another issue that has been considered is the occurrence of soil disturbance due to the use of forest residue collection equipment. Studi es have shown that the growth of woody plants and yields of harvestable plant products are decreased by soil compaction from residue collection equipment, because of the combined effects of high soil strength, decreased infiltration of water and poor soil aeration. 82 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. 83 Thus, it is important to limit the severity of soil disturbances with minimal passes and relatively low ground pressure.

Energy Content of Fore st Residue and Biofuel

Woody material obtained by the harvesting or thinning of forest is somewhat more energy dense compared to other forms of biom ass. On its Biomass Program webpage, the Department of Energy lists the higher heating va lues (lower heating values were not available) for many different types of biomass for dry samples. 84 These values for woody biomass are summarized in Table 1.1-10.38 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 potential for higher carbohydrate compositions and thus more sugars available for conver sion 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 di fferences 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. 85

Availability of Forest Residue

The quantity of forest resi due available to produce biof uels was estimated by two different studies. We summarize those two studies, and then summarize data which we received directly from the U.S. Forest Service. In addition, we were able to incorporate the forestry sector component in the FASOM model, as further descri bed in Chapter 5. As these feedstocks are now allowed to compete with the various agricultural feedstocks and energy crops in the market, we believe it is a more robust analysis than our prior proposal method of analyzing the agriculture and forestry sectors separately. 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). 86 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 summ arizing 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 production

.39 The total forest inventory is estimated to be about 20.2 billion dry tons. The report authors estimated that about 2.2 percent of the total forest inventory is harvested each year, which corresponds to 444 million dry tons. This removal rate is estimated to be less than the annual average forest growth, which suggests, at l east on an aggregate basis, that this removal rate is sustainable. It is estimated that 78 per cent of this removal was for roundwood products (sawlogs, pulpwood, veneer logs and fuel w ood), 16 percent was logging residue and about 6 percent was classified as other removals. Thus , the Billion Ton study authors estimate that 67 million dry tons of logging residue could potentially be available for biofuel production, which is comprised of 49 million dry tons of primary logging residue, and 18 million dry tons of other removals. The Billion Ton study estimates that 65 percent of the total logging and other residue would be recovered for use. The two reasons 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, a nd 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. To qualify under RFS2 , the biofuel producer would need to show that the forest residue is from a qualifying planted forest as specified under RFS2.

Additional forest residue is available downstream of the logging operations at mills. In the process of making their products, primary wood processing mills create some wood residue. However, almost all of this waste wood is rec overed or burned for process heat. For example, the bark from the logged wood is burned as fuel or converted into mulch. The Billion Ton authors estimated that just under 2 million dry tons per year of residue would be available from the primary wood processing mills as feedstock for producing biofuels.

The Billion Ton study estimated that additional wood waste could also be available from secondary wood processing mills, which refine crude wood into more refined products. The report authors could not find an y data on how much residue is produced by these secondary wood processing mills, however, a study of these facilities did provide an estimate. Approximately 15.6 million dry tons per year were estimated to be available from the smaller of these secondary wood processing mills, however, the report estimated that only 40 percent, or 6 million dry tons per year, would be available for biofuels production. To qualify under RFS2, the biofuel producer would need to show that the mill residue which was processed by the mills is originally from a qualifying plante d forest as specified under RFS2.

Another industry which proce sses harvested wood is the pul p and paper mill industry. These companies process wood into fiber to ma ke paper and cardboard. Most of the pulp and paper mills use the Kraft process or sulfate pulping process which converts half of the woody material into fiber, while the other half is a byproduct termed black liquor. The black liquor contains a substantial amount of biomass. The 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.40 The Billion Ton study estimated that anot her 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 wh ich contain excess woody material. The forests which contain excess woody material are candidates for providing a dditional biomass for producing biofuels. The Forest Service estimated the tota l amount of excess woody material to be 8.4 billion dry tons.

The Forest Service next estim ated 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, woul d be used for feedstock for the logging industry. Thus, the remaining 30 percent would be resi due that would serve as feedstoc k for the biofuels industry. Finally, the last assumption made is that of the excess woody material harvested, 15 percent would be lost between harvesting and use, thus the total amount of woody biomass was adjusted to be 15 percent lower. These assumptions result in 18 million dry tons of additional woody biomass that could be used to supply the biofuels industry annually, and 42 million dry tons that would supply the logging industry.

As shown below in Table 1.1-11, the Billion Ton Study estimates that a total of 67 million dry tons per year would be available from non-urban forests. It is important to note that not all of the forest biomass in the Billion Ton Study, specifically wood from national forests and perhaps much of the fuel wood, would be eligible to be used as a qualif ying biofuel feedstock under the RFS2 program. Despite th is limitation, the Billion Ton Study is an important source of information, especially when considering the maximum amount of sustai nably removable forest biomass.

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 incr easing the amount of forest residue s that would be available for producing biofuels. The authors estimated the fu ture forest residue supply in the year 2050 and concluded that the logging residue is expected to increase from 41 million dry tons to 64 million41 dry tons. Also in 2050, the primary and secondary mill residue quantity is projected to increase from a total of 8 million dry tons per year to a total of 24 million dry tons per year. No estimate was provided for any increase, or decrease, in th e amount of forest woody material that would be available from thinning forests. If the projected 39 million dry ton increases in forest residue comes to fruition, then the total amount of forest residue that would be available for producing biofuels in 2050 would be 106 million dry tons per year. We are primarily interested in compliance with the RFS2 biofuels standa rd in 2022, which is just over 1/3 rd of the way between today and 2050. Thus, by inter polating the projected future fo rest residue in 2022 relative to current levels and those in 2050, the report supports the conclusion that 79 million dry tons of forest residue would be available in 2022.

U.S. Cellulosic Biomass Study

Another estimate for the amount of forest re sidue that could be used to produce biofuels was made by Marie Walsh in a report titled “US Cellu losic Biomass Supplies and Distribution”. 87 This report also uses the Forest Service data base for its estimates, so its conclusions resemble those of the Billion Ton study. However, an important difference between this Cellulosic Biomass Study and the Billion Ton Study is that Marie Walsh estimated a cost curve for the amount of biomass available for her Cellulosic Biom ass study for multiple future

years.

In this report, Marie Walsh estimates that 63 million dry tons of logging residue is created in the lower 48 states. Of this total amount of logging residue, 65 percent is estimated to be accessible by roads, and not all the accessi ble 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 futu re years for five year intervals through 2030. The amount of logging residue available at diffe rent price points and fo r different years is summarized in Table 1.1-12.

Table 1.1-12. Quantity of Logging Residue Available at Varying Prices (million dry tons)

$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

To qualify under RFS2, the biofuel producer would need to s how that the forest residue is from a qualifying planted forest as specified under RFS2. This could limit the quantity of biomass available under RFS2 to lower levels that those shown in the table.

Marie Walsh also identified the quantity of woody material that would be available at specific prices from other removal supplies – tree s removed to make way for the construction of Deleted:42 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 produc tion. Marie Walsh added the other removal supplies to the logging residue and estimated their availability at different price points, increasing the available biomass by 25 percent. The combined to tal is summarized in Table 1.1-13.

Table 1.1-13. Quantity of Forest Residue and Other Removals Available at Varying Prices (million dry tons)

$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

To qualify under RFS2, the biofue l producer would need to show that the “other removal supplies” that it is interested in purchasing would qualify under RFS2. Some of this category could quality as MSW while another portion of it may qualify if the trees are being removed to prevent a wildfire from damaging the nearby buildings. However, the RFS2 definitions could limit the quantity of this category of biomass that could qualify under RFS2.

This report also estimates the amount of primary and secondary mill residues available for biofuels production. Like the Billion Ton st udy, Marie Walsh also concludes that only a very small amount of primary mill residue is estimated to be currently unused and available for producing biofuels. She concludes that out of the 88.7 million dry tons of primary mill residue which are generated, that only 1.3 million dry tons is not used for fuel, fiber or other sources as discussed above. However, she provides an additional assessment that, at the right price, the primary mill residue could be drawn away from these other users of the primary mill residue. The assumption is that for fiber uses, the primary mill residue could be drawn away from the current users at 35% of the product price. For othe r uses, including for fuel, it is assumed that at 65% of the market price of the raw wood value, the primary mill residue could be purchased away from the current users. Table 1.1-14 below estimates the price that specific estimated primary mill residue volumes could be available for producing biofuels.43 Table 1.1-14. Quantity of Primary Mill Residue is Available at Varying Prices (million dry tons)

$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

To qualify under RFS2, the biofuel producer would need to show that the mill residue which was processed by the mills is originally from a qualifying planted forest under RFS2. This could limit the quantity of biomass that would qualify under RFS2 to lower levels that those shown in the table.

The author also attempted to estimate the amount of secondary mill residue that could be available for producing biofuels. She observed that data is scant on the amount of secondary mill residue. She referenced a study (Rooney, 1998) that estimated that only a very small volume of secondary mill residue would be available for producing biofuels. Of 12.5 million dry tons of secondary mill residue which is generated, only 1.2 million dry tons is available for producing biofuels. Unlike the analysis conducted for primary mill residue, the author did not attempt to estimate the extent that biofuels producers could bid the secondary mill residue away from the current users.

Marie Walsh also assumes that three very difficult-to-quantify sources of forest material could be available as biomass for producing biofuels. One of these potential sources is the forest material that could be available through the thinning of overgrown forests to help reduce the fire risk within these forests. Marie Walsh referenced one study which estimated that 100 to 200 million acres of overgrown forest could be harvested. No estimate, however, was provided for the amount of this forest ma terial that could be availa ble 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 fuel wood used to heat homes and to provide heat for industries. The author cited a report which estimated that fuel wood use decreased from 1986 to 2000, but began to increase again and is expected to increase through 2050. This presumably means that if the demand for fuel wood is lower than previously, that some of that fuel wood could be available for producing biofuels. However, in this report, Marie Walsh did not make any firm estimate for this.

The Marie Walsh report also discussed that forest pulpwood supply is exceeding demand in the Southeast. The demand of forest pulpwood decreased from 131 to 121 million tons per year from 1993 to 2003, and this demand is expect ed to further decrease through 2020, and some have projected that this decrease in demand will continue beyond 2020. During the period between 1993 and 2003, pulpwood acreage and mana gement intensity have increased, which Deleted:44 suggests that the Southeast is and will continue to be over supplied. This oversupply of forest pulpwood could potentially provide additional biomass to the biofuels industry, although she did not provide any firm estimate for this. It is important to note that, under RFS2, some of this material may not qualify under RFS2.

It is important to note that not all of the forest biomass in the US Cellulosic Biomass Study would be eligible to be used as a biofuel feedstock under the RFS2 program. Despite this limitation, like the Billion Ton Study, this study is an important source of information, especially when considering the maximum amount of sustainably removable forest biomass.

While both of these studies provide quality assessments for the total amount of forest residue available for producing bi omass, they both have an impor tant limitation as well. The 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 density assessment must also consider the feedstock availability requirements made by cellulosic plant investors or banks, which may choose to require that a certain excess amount of feedstock be available to jus tify the use of that biomass in a cellulosic ethanol plant. Without consideri ng these limitations, these studies may overestimate the quantity of biomass that would be truly usable and also the ultimate amount of biofuel that could be produced. Some of these issues were addressed in our cellulosic plant siting analysis in Section 1.8. Also, a study by the Western Governor’s Association, which was designed to account for local biomass density, assessed the quantity of forest and other biomass that could be used for producing biofuels. 88 Because this study was only conducted for the Western United States instead of the entire country, we did not su mmarize it here. However, the study is being expanded nationwide and onc e completed it will provide nationwide results based on this very robust, bottom-up approach.

U.S. Forest Service Data

To assess forest residue supply within the feedstock density and s upply constraints, we obtained county-by-county forest residue data from the U.S. Forest Service. 89 The information was provided by the subcategories of logging residue, primary mill residue, timberland thinnings, and other removals. The informati on also included urban fo rest residue, however, because that material is included with the other MSW, we did not consider it here (discussed later in Section 1.1.2.4). Like the studies discussed above, the national forest lands are omitted from consideration, and the urba n forest residue is not consid ered here, but in the section discussing MSW. Most, if not all, of this material, therefore, would be eligible to be used as a feedstock for the production of biofuels under the RFS2 program, with the possible exception of some of the unused mill residues. 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 da ta by state, and we are presenting the data at speci fic price points: $30/dry ton, $45/dry ton and $70/dry ton.45 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 35,476,67446 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 39,724,50247 Table 1.1-17. Tons of Forest Residue Available for Producing Biofuels Biomass available at $70/ton Logging Residue Other
Removals Timerland Thinnings Unused Mill Residue Total Quantity Alabama 1,202,541 253,620 581,654 7,117 2,044,933 Arizona 13,566 24,510 38,678 1,351 78,105 Arkansas 851,772 385,492 492,094 12,889 1,742,247 California 583,478 0 1,000,615 65,088 1,649,181 Colorado 10,056 11 30,619 2,302 42,988 Connecticut 4,301 16,095 10,465 3,949 34,810 Delaware 17,932 14,145 6,700 0 38,777 Florida 535,215 257,704 332,353 2,202 1,127,474 Georgia 1,556,954 496,631 776,911 45,138 2,875,634 Idaho 216,303 0 61,926 6,006 284,235 Illinois 139,153 117,589 115,431 18,523 390,696 Indiana 281,464 52,087 221,845 10,627 566,023 Iowa 56,050 27,607 49,551 159 133,367 Kansas 7,329 44,202 9,676 8,720 69,928 Kentucky 513,989 332,179 463,904 55,196 1,365,268 Louisiana 1,317,139 440,293 375,052 30,075 2,162,559 Maine 1,280,511 495 166,117 42,483 1,489,605 Maryland 94,579 421 40,994 17,067 153,060 Massachusetts 39,127 33,191 13,801 0 86,119 Michigan 391,732 128,600 533,107 13,763 1,067,203 Minnesota 358,518 341,894 200,599 26,878 927,889 Mississippi 1,548,534 355,071 516,598 95,138 2,515,342 Missouri 387,434 265,146 643,929 79,787 1,376,295 Montana 215,597 0 83,023 9,136 307,755 Nebraska 10,710 9,434 11,707 4,971 36,822 Nevada 22 71 0 0 93 New Hampshire 165,519 197 58,098 7,019 230,833 New Jersey 3,184 40 2,423 1,437 7,084 New Mexico 17,239 1,287 32,187 4,902 55,616 New York 384,457 56,552 192,851 27,390 661,249 North Carolina 1,013,165 629,632 800,455 12,811 2,456,063 North Dakota 1,454 7,601 3,822 265 13,142 Ohio 186,022 9,069 88,572 22,600 306,263 Oklahoma 173,869 98,794 81,634 495 354,792 Oregon 1,251,094 34 566,594 16,316 1,834,037 Pennsylvania 546,418 707 340,497 170,972 1,058,594 Rhode Island 957 25,039 2,800 389 29,185 South Carolina 714,551 348,289 395,555 1,051 1,459,446 South Dakota 11,872 15,581 4,129 2,294 33,875 Tennessee 316,706 244,920 516,550 187,583 1,265,759 Texas 616,777 218,464 253,670 3,021 1,091,931 Utah 3,758 7 14,717 4,437 22,918 Vermont 108,542 19,182 71,105 0 198,829 Virginia 741,673 406,800 630,366 39,366 1,818,206 Washington 1,067,587 23 1,029,985 21,446 2,119,041 West Virginia 488,356 24,714 287,639 118,779 919,489 Wisconsin 576,938 499,302 420,775 60,410 1,557,425 Wyoming 18,163 0 21,598 34,014 73,775 Total 20,042,304 6,202,722 12,593,373 1,295,560 40,133,95948 The U.S. Forest Service data reveals that there are large amount s of forest material in the Southeast, the far Northeast and th e Northwest portions of the U.S. The data also shows that the price curve for this forest material is fairly fl at over the range summarized here. This suggests that the forests which are already accessible by roads provide access to low cost forest material from the thinning of timberland. However, to access more and more of the timberland, the costs ramp up quickly. These numbers are also signif icantly different than those presented in the proposed rule. This is due to a misunderstandi ng in how the number shoul d be interpreted. According to our contacts at the US Forest Service whether logging residue or timberland thinnings would be available w ould depend on the type of loggi ng operation being used. We cannot, therefore, assume that 100% of the logg ing 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 operations would produce lo gging residue and that the rest would produce timberland thinnings. Based on suggestions from the US Forest Service we have assumed that 50% of logging operations would produce logging residue and 50% would produce forestry thinnings. Additionally, the US Forest Service data includes unused mill residue, which may not be qualifying biofuel feedstock under RFS2 depending on the source of the wood. While these changes result in a significan t decrease in the amount of wood residue available from current forestry operations they ha ve no impact on our analyses. This is due to the fact that the amount of wood residues used in cellulosic biofuel produc tion, as projected by the FASOM model, is still far less th an 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 c ontains much forest land that is not currently in active production due to insufficient demand and low prices for forestry products. If demand for cellulosic feedstock sufficiently increased th e demand for forestry products it is very possible that logging operations would expand to meet this need . In this sense, the data from the US Forest service is not an evaluation of the maximum amount of forest ry residue that could be sustainable removed, but rather a measure of how much residue c ould be recovered base d on current logging operations. Logging operations are financed based on th eir higher value products (i.e., lumber), not based on demand for lower value products (i.e., residues), so it is un likely investments would be made to harvest fore st residues absent demand for lumber operations. Nevertheless, this data is valuable, as the value for cellulosic biomass would likely have to be significantly higher than we are projecting in order to dr ive logging operation expansion.

Forestry Sector Modeling in FASOM

In addition to the agriculture sector, the FASOM model also contains a forestry component, which details forest acres across the U.S. as well as production of forestry products. Running the forestry and agri culture components of the model simultaneously shows the interaction between these two sectors as they co mpete for land, as well as the effect on products and prices in each respective sector. In total , FASOM includes a repres entation of seven major land use categories, including cropland, cropland pa sture, forestland, forest pasture, rangeland, developed land, and acres enro lled in the Conservation Reserve Program (CRP). More information on these land categories can be found in Chapter 5.1.2. Deleted: ry

Deleted: forestry service

Deleted: forestry

Deleted: [Need discussion from Jeff. C on how

Deleted: modeling is a subsection

Deleted: the

Deleted: available material] ¶49 Various products from the forest ry sector in the FASOM model can be used to produce cellulosic renewable fuel. These products incl ude hardwood and softwood milling, and logging residues. The FASOM model projected that 110 million gallons from forestry logging would be used to meet the cellulosic biofuel standa rd under EISA.

Wood Summary

We compared the quantity of potential biom ass supplies projected to be available in 2022 by the two studies and the data that the Fo rest Service provided us in Table 1.1-18.

Table 1.1-18. Forest Biomass Availability in 2022 at Different Prices (million dry tons) 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 110 million gallons of forestry biomass would be used to meet the cellulosic biofuel standard. This would require close to 1 million dry tons per year of forestry biomass. As noted by the studies and data from the US Forest Service , this amount is a sma ll fraction of the large amount of forestry biomass potentially available. Although there is additional forestry biomass available for cellulosic renewabl e fuel production, other sources of cellulosic renewable fuel (switchgrass and corn residue, in particular) are relatively more profitable for producers of cellulosic renewable fuel feedstoc ks. For details on the economic impacts of the RFS2 program, including prices of cellul osic feedstocks as modele d in FASOM, see Chapter 5.

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 gath ered 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 bi ofuel production involves understanding the types of materi als 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, gla ss, metals, plastics, wood, ya rd trimmings, food scraps, rubber, leather, textiles, etc. See Figure 1.1-4 for the percent composition of MSW generated Formatted: Centered, Don't keep lines together Deleted: ing

Deleted: 100

Deleted: biomass

Deleted: ¶

Deleted: /yr

Deleted: 100

Deleted: forestry service50 (before recycling) in 2008. 90 Construction and demolition debris is not included in the estimate and is discussed se parately below.

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 II.B. 4.d . The bulk of the biogenic portion of MSW that can be converted into biofuel is cellu losic material such as wood, yard trimmings, paper, and much of food wastes. Paper made up the majority of the total MSW generated in 2008, approximately 31 percent.

Although recycling/recovery rates are increas ing over time, there appears to still be a large fraction of biogenic ma terial that ends up unused and in la nd-fills. In order to project the portion of material that can potentially be used for biofuel purposes, we must understand how the composition of landfilled material changes over time. To do this, we first analyzed the trends from 2000-2007 for the percent composition of total MSW generated from paper/paperboard, wood, and yard trimmings over time as shown in Table 1.1-19 in order to project the percent composition of total MSW generated for the year 2022 for those categories (i.e. calculated to be 24.5% paper, 5.6% wood, and 12.8% ya rd trimmings and 15.1% food scraps). 91 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. Deleted:

Deleted: Pa g e Brea k

Deleted: I

Deleted: 1.b51 Table 1.1-19. Percent Composition of Total MSW Generated (including recyclable material): Paper, Wood, and Yard Trimmings

2000 2004 2005 2006 2007 ... 2022
Material Paper/paperboard 36.7 34.6 33.9 33.6 32.7 ... 24.5
Wood 5.5 5.6 5.6 5.5 5.6 ... 5.6 Yard Trimmings 12.8 12.7 12.8 12.7 12.8 ... 12.8 Food Scraps 11.2 11.8 12.1 12.2 12.5 ... 15.1

We also analyzed the trends from 2000-2007 for the percent composition of total MSW discarded (i.e. after recycling has occurred) to project the percent compositions for the year 2022 (i.e. calculated to be 8% paper, 8% wood, 3% yard trimmings, and 21.5% food scraps), see Table 1.1-20 and Table 1.1-21. Comparing Table 1.1-19 and Table 1.1-20, we note that historically there is a lower percent of paper and yard trimmings that is discarded than generated for MSW. This makes sense because a large percentage of these materials are recycled. Other than recycling, some MSW material is also combusted for energy use. This material we assume would be unavailable for 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 ma terial): 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 genera ted (prior to recycling) is assumed to increase over time due to population growth. Biocyc le magazine (2008) reports MSW estimates for each state in the U.S. based off of 2006 population data. 92 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. Th e 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 Formatted: Keep with next

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New Roman52 state from Biocycle in order to estimate the am ount of MSW potentially available to biofuels (after recycling).

Knowing the total amount of MSW landfilled is only part of the picture. We also need to understand the types of cellulosic material likely to make up the MSW landfilled. For this, we were able to gather state com position data (i.e. percent wood vs. paper vs. other materials) of landfills for MSW generated , however, we were in fact interested in acquiring state composition data for the MSW landfilled

. 93,94,95,96,97,98,99,100,101,102,103 Using the state composition data, we estimated the percent composition of MSW landfilled by state using a ratio of percent composition of national material generated (estimated in Table 1.1-19) and landfilled (estimated in Table 1.1-21) and state percent compositi on data for MSW genera ted (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 estimated to be landfilled (provided in Biocycle) and by the percent composition of MSW landfilled by state. Some states did not provide composition data, therefore, we estimated average percentages based on the states within a similar location in the U.S. where data was provided (e.g. if Utah data was unavailable, we assumed compositions would be similar to other rocky mountain states).

Furthermore, the amount of MSW potentially available is limited by assumptions on percent moisture and per cent contamination. We assumed that paper, wood, yard trimmings, and food scraps have a 10%, 20%, 40%, and 70% moisture content, respectively. 104,105 We also assumed that wood is approximate ly 50% contaminated, due to objects such as nails, paint, chemicals, etc. typically associated with such feedstocks. 106 Paper and food wastes are assumed to be mostly uncontaminated, assuming 95% uncontaminated. 107 Yard trimmings are also assumed to be largely uncontaminated, a ssuming 75% uncontaminated. We account for contamination because it is likel y to affect the quality of th e 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 production. In addition, not all yard trimming can be assumed to be wood, 90% is assumed to be from wood. 108 We also estimated the amount of food waste that is cellulosic material to be 45%. 109 We estimate that 23.8 million tons could be available after accounting for these factors from paper, 0.9 million tons from yard trimmings, 5.3 million tons from wood, and 6.5 million tons from food waste.

Construction and Demolition (C&D) Debris

C&D debris mostly comes from building demolition and renovation, and the rest comes from new construction. Roughly equal percentages of building-related waste are estimated to come from the residential and commercial building sectors. The composition of C&D materials varies significantly, depending on the type of pr oject from which it is being generated. For example, materials from older buildings is likel y to contain plaster and lead piping, while new construction material s may contain significant amounts of dryw all, laminates, a nd plastics. For building materials, EPA estimates the overall percen tage of debris in C&D materials falls within the following ranges:53 Table 1.1-22. 110 Percentage Composition of C&D Debris (by volume) Concrete and mi xed rubble 40-50% Wood 20-30% Drywall 5-15% Asphalt roofing 1-10% Metals 1-5% Bricks 1-5% Plastics 1-5%

In 1996, total C&D debris generated was estimated to be approximately 124 million metric tons. 111 As seen in Table 1.1-22 above, only a portion of this, however, would be made of woody material. We based our estimate of C&D wood in 2022 on the equation adopted from Wiltsee’s analysis. 112 The equation estimated C&D w ood 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 po tential locations that could utilize this material. This is described in more de tail in Section 1.8.1.3, the cellulosic ethanol plant siting analysis. From this analysis we determined that of the 44.5 million dry tons of MSW and C&D wood waste available, approximately 26 million dry tons would be used to produce 2.3 ethanol-equivalent billion gallons of fuel. J We estimated urban wastes outside our agricultural modeling as the models do not focus on such feedstocks. The othe r 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, depe nding on the economic competitiveness. Refer to Chapter 5 more details on the FASOM and FAPRI -CARD modeling.

1.1.2.5 Imported Cellulosic Feedstocks or Biofuels

Cellulosic biofuel could also be produced internationally. One example of internationally produced cellulosic biofuel is ethanol produced from bagasse from sugarcane processing in Brazil. Currently, Brazil burns ba gasse to produce steam and genera te bioelectrici ty. However, improving efficiencies over the coming decade as well as mechanization of sugarcane harvesting (no burning of biomass in fields) may allow an in creasing portion of bagasse to be allocated to other uses, including cellulosic biofuel, as additional straw could potentially be collected and used to produce bioelectricity.

J Assuming 90 gal/dry ton ethanol conversion yield for urban waste in 2022 Deleted: ¶54 In fact, a recent study was performed under the Memorandum of Understanding to advance collaboration in biof uels, signed by Brazil and the United States on March 2007. 113 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 bioma ss feedstock potential for sel ected countries outside the United States and projected supply availa ble for export or for biofuel production. K,114 For thestudy’s baseline projection in 2017, it was estimated that approximately 21 billion ethanolequivalent gallons could be produced from cellulosic feedst ocks 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 cell ulosic feedstock producti on from both bagasse and forest products. Other countries including India, China, and those belonging to the Caribbean Basin Initiative (CBI) also have some potentia l although much smaller feedstock supplies are projected as compar ed to Brazil.

1.1.2.6 Cellulosic Feedstock Summary

Table 1.1-23 summarizes our internal estimat e of the types of cellulosic feedstocks projected to be used and their corresponding volu me 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 Assu med 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.55 1.1.3 Biodiesel & Renewable Diesel Feedstocks

In general, plant and animal oils are valuable commodities with many uses other than transportation fuel. Therefore we expect the primary limiting factor in the supply of both biodiesel and renewable diesel to be feedstock availability and price. Primary drivers for this are increasing worldwide demand for use as food as 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. Expansion of biodiesel market volumes beyond the mandates is dependent on it being able to comp ete on a price basis with the petroleum diesel being displaced.

The primary feedstock for domes tic biodiesel production in the U.S. has historically been soybean oil, with other plant and animal fats and recycled greases making up a varying portion of the biodiesel pool as commodity prices rise and fall. For example, following a rise in soy oil prices and then a decline in diesel prices, the share of biodiesel being produced from rendered or reclaimed fats or other cheap feedstocks increased steeply in 2008 and 2009. 115 Another feedstock we project to become a significant and economical alternative over the next decade is corn oil produced during ethanol production (see 1.1.3.2 below).

1.1.3.1 Virgin Plant Oils

Agricultural commodity modeling we have done for this proposal (see Chapter 5 of this document) suggests that soybean oil production will stay relativel y flat in the future, meaning supplies will be tight and prices supported at a high level as biofuel and food -related demand increases. Modeling scenarios conducted for the year 2022 with the EISA mandates indicates that domestic soy oil production would support about 660 million gallons of biodiesel production. This material is most likely to be processed by biodiesel plants (as opposed to renewable diesel hydrotreating processes) due to the large available capacity of these facilities and their proximity to soybean production. Compar ed to other feedstocks, virgin plant oils are most easily processed into biof uel via simple transesterificati on due to their homogeneity of composition and lack of contaminates.

1.1.3.2 Corn Oil Extracted During Ethanol Production

A source of feedstock which could provide 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 sepa ration, or corn oil extraction, these are a collection of processes used to get additional product streams of value from the corn. This idea is not new, as existing wet mill plants create several streams of product from their corn input, including oil. In a dry mill setting, the kernel can be separated into the bran, starch, and germ components ahead of fermentation, or alternatively, oil can be extracted from the dis tillers’ grains after fermentation. Both have advantages and disadvanta ges related to plant capital cost a nd energy consumption, as well as yield of ethanol and the other coproducts. For more informa tion on these technologies, see Section 1.4.1.3.56 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) re quires 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 resu lts 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 rate s, capital costs, and energy use of corn oil extraction systems is based on conversations with several tec hnology providers. Depending onthe 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 projected 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. 116,M We expect this material to be processed in biodiesel plants with pretreatment capabilities for handling feedstocks with significant free fatty acid (FFA) content. At this time it is uncertain whether there will be third party aggregators of this extracted oil, or whether individual ethanol plants will contract directly with nearby biodiesel facilities, which may ultimately impact where and how this feedstock is processed.

1.1.3.3 Yellow Grease and Other Rendered Fats

Rendered animal fats and reclaimed cooking oils and greases are another potentially significant source of biodiesel feedstock. The National Renderer’s Association gives a quantity of approximately 11 billion lbs of fats and greas es available annually fo r all uses, and suggests this will grow by 1% per year. 117 This figure is broken down into several categories, and includes “yellow grease” and “other grease” collected and processed by rendering companies each year. The NRA defines yellow grease as material primarily derived from restaurant grease or cooking oil (they do not define “other grease” but we can assu me this is trap grease or other reclaimed material). Adding together the NRA’s “yellow grease” and “other grease” categories, we arrive at 2.7 billion lbs per year (all figures there are for 2005).

Similarly, a 2004 report prepared for New York State Energy Research and Development Authority by LECG, LLC describes yellow grease as material produced by restaurants and food service. 118 (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 show s production of yellow grease by restaurants to be on the order of 9 lbs per capita per year, equivalent to about 2.7 billion lbs/yr. Unfo rtunately, it's not clear whether this quantity would include or be in addition to the NRA figures, but given the similarity of

M The projected fraction of plants doing corn oil extraction was based on a conversation with several technology providers and various people working in the ethanol industry.57 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 approximately 22% of this material for biofuel use in 2022 (= 380 million gallons x 7.5 lb/gal / 13 million lbs). In a written statement by David Meeker of the NRA, he asserts that it could be feasible for as mu ch as 30% of the 11 billion lbs to be directed to biofuel production on a long-term basis. 119 The feasibility of consumption of this volume of rendered material was also supported by comm ents 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 operations, taking advantage of volumes or prices of feedstock that may not typica lly be available on the open market to smaller, unaffiliated biodiesel plants.

Some comments submitted to the docket by Endicott Biofuels, LLC, suggest there are additional sources of waste greases and oils sufficient to produce an additional 2 or more billion gallons’ worth of biofuel (beyond what we account for above) if they could be collected and processed. We have chosen to ignore these volu mes in this analysis, as their use will likely require further pre-treatment and additional processing steps beyond the capabilities most of the installed biodiesel production capacity. However, it is conceivable that these materials may begin to be used in significant quantities as dictated by regulatory or economic conditions.

1.1.3.4 Algae

Algae are single-celled algae species that grow quickly and can be cultivated to produce biomass for the downstream production of fuel based on the oil and residuals found in the biomass. Many of these algae species are targeted for their high lipid content, and thus are a promising feedstock for biofuel production. Wh ile some algae companies are focusing on the use of algae for biodiesel production, it is important to note that algae can alternatively be used for producing ethanol or crude oil for gasoline or diesel which could also help contribute to the advanced biofuel mandate. N Some of the potential benefits of using algae as a biofuel feedstock are that algae can be grown on marginal land, can require low water i nputs, can recycle waste streams from other processes, does not compete with food production, a nd has high oil yield.

N Algenol and Sapphire Energy, see http://www.algenolbiofuels.com/ and http://www.sapphireenergy.com/58 Mass cultivation of microalgae has been ongoing since the 1950s for medical and pharmaceutical purposes. Since the 1980s, algae-to-biofuel res earch has been heavily funded by governments such as Japan, France, Germany and the United States. The research program in the US was especially large. The Aquatic Species Program, backed by the National Renewable Energy Laboratory, ran from 1978-1996 to look at the use of aquatic plants, specifically algae, as sources of energy. From about 1982 through the termination of the program, research concentrated on algae for biofuel production, specifically in open ponds. 120 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.” 121 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. 122 In the 1990s Japan’s NEDO-RITE Optical Fiber Bioreactor project obtained support from several private companies, laboratories, and academic institutions. However, the program was unsuccessful due to high co sts for producing algae. Most recently, universities and start-up companies have been conducting pilot studies on the cultivation and processing of algae. With the high price of oil in 2008 and increased intere st 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 bioma ss-based diesel standard. We believe this is reasonable given several announc ements from the algae industr y about their production plans which is further descri bed in Section 1.5.4.3. O

A recent report released in October 2009 entitled “Cultivating Clean Energy: The Promise of Algae Biofuels” is a good resource for understanding the basic pathways for algaebased biofuels and summarizes some of the areas that can be improved to further commercialization of algae-based biofuels. 123 We discuss some of the information contained in the report, below.

In addition, we have consulted with the National Renewable Ener gy Laboratory (NREL) on developing several reasonable pathway scen arios for algae producing oils for biodiesel. 124 While there are many different technologies and fuel combinations bein g considered for algaebased biofuels, we believe the analyses completed by NREL for the FRM are representative of what is possible for the algae i ndustry by 2022. As time permits, we hope to evaluate different configurations and their impact on production pa rameters. To provide 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 uncertain, and we have taken into account the best information we could acquire at the time.59 etc.). The following sections also summarize some of the assumptions and results from the NREL modeling for algae; see the technical document for more details. Also, refer to Chapter 2 for a discussion of how we used the modelin g 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 consider ed 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 clea r tubes that carry a circulati on 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. 125 PBRs can also be placed indoor or outdoor. Indoor closed PBRs usually require artificial illumination. Outdoor closed PBRs use natural daylight and in some cases also artificial light. There are also variations on cultivation systems such as hybrid (combined open and closed) cultivation, heterotrophic cultivation (without light), and integrated biofixation systems. P

Due to higher cell densities, the use of photobioreactors typically has lower land use in comparison to open pond systems producing the same volume of fuel. While other oil crops may need large amounts of agricultural land in order to meet a sizable portion of US liquid fuel demand, algae may limit the amount of land need ed due to its high productivity and do not require the displacement of agricultural crops. 126,127,128

When cultivated in enclosed photobioreactor s, evaporation of water is limited, and water extracted during the drying process can be mostly reclaimed. 129 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 magnitude lower than the 4,000 trillion gallon/year used to irrigate the entire US corn crop. 130

P For more information on these variations, refer to the recent report “Cultivating Clean Energy: The Promise of Algae Biofuels”. Deleted: such as soy, sunflower, rapeseed, and jatropha60 Algae can also thrive in brackish water, with salt concentrations up to twice that of seawater, which is often ava ilable in saline groundwater aquifers in the southwest. 131, 132 However, the salt, other minerals, and contamin ants may pose a problem to the dewatering and extraction process, depending on the method used.

Aside from sunlight, land, and water, algae require two main physical inputs for growth: CO 2 and nutrients. 133 Nutrients can be obtained from conventional fertilizers, or from domestic or industrial waste sources, such as farm refuse and manure. 134 Co-locating algae farms with animal husbandry, in order to directly use the manure as a nutrient, w ould reduce transportation

costs. 135 In addition, both of these inputs can be obtained from waste streams from other energy processes. They can be coupled with coal-burning power plants or even ethanol plants, and can effectively recycle between 50% and 90% of flue gasses, depending on the size of the algae farm. 136,137,138 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. 139

The US southwest is perhaps one of the most promising locations for economic algae-forbiofuel cultivation, due to its high solar insolation (see Figure 1.1-5), availability of saltwater aquifers, and relatively low current land use. 140,141 Ideally, algae farms could be co-located with coal-burning power plants in order to recycl e the carbon emissions. On e 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. 142

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. 143,144 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 (assump tions reasonable but still challenging in near61 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 Aggressive Case Max Case op PBR op PBR op PBR
2108 5271 6748 16863 12151 30395

Harvesting

Harvesting is necessary to recover biomass from the cultivation system. Commonly used techniques include flocculation, dissolved air flotation (DAF), centrifugation, microfiltration, and decantation. Additional techniques include di screte sedimentation, membrane filtration, phototactic autoconcentration, tilapia-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. Add itional 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 chem ical, mechanical, or electrical processes to separate the algal oil from the cell membrane. The TAGs (Triacylglycerides) are typically the main product which goes to biodi esel production. The remainder consists of carbohydrates, proteins, nutrients, and ash), usually referred to as algal residue.

The extraction step is commonly regarded as the most speculative in terms of large-scale feasibility. 145 Thus extraction is a critical area of research going forward to achieve practical algal lipid production. Some of the methods discussed are solvent extraction, supercritical fluid extraction, mechanical extraction, osmotic shock, and sonication.

The spent biomass (i.e. algal residue) can be used in anaerobic digestion and power generation via gas turbine which provides power to run the plant. The other method commonly discussed is its use as animal feed.

Oil Conversion to Biofuel

Algal oil can undergo transest erification to produce biodiesel or be hydroprocessed to renewable products (e.g. renewable diesel) depending on th e slate of products desired. In some cases, the entire algae biomass is converted using thermochem ical and biochemical methods such as pyrolysis, gasification, liquefaction, and fermentation to produce biofuels. See Figure 1.1-6 for the various pathways for the processing of algal biomass.

Q Only land required for pond/PBR, not including land necessary for processing equipment62 Figure 1.1-6. Pathways for Processing Algal Biomass 146

1.1.3.5 Other Potential Feedstocks

The following sections descri be several oil crops that ha ve also been discussed as potential biofuel feedstocks. Whil e 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 particular, some potential advantages include growth on marginal lands, tolerance to drought, low nutrient and labor inputs, and high oil yield.

J. curcas has been traditionally cultivated for living fences, to conserve soil moisture, reclaim soil, control erosion, and used locally in soap production, insecticide, and medicinal application. 147,148 Most recently , J. curcas has been investigated as an energy crop. J. curcas originated in Central America, mainly growing in arid and semi-arid conditions; now it is also found in the tropical regions of Africa, Asia, and North and South America. 149 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. 150,151 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 reve rse desertification. 152,153

As a wild plant which has not yet been domesticated, J. curcas has a large potential for improving many qualities, such as minimizing inputs, maximizing yields, and developing Deleted: However, J. curcas may not produce efficiently on marginal lands without significant expense.

Deleted: may be considered droughttolerant. However63 tolerance for various climates. For example , there is still little known on water use efficiency of
J. curcas as a crop. 154 Even though J. curcas can survive moderate droughts by dropping its leaves, the effect of water starvation on seed yield and oil content in the seeds is mostly unknown. Water use efficiency of sister species Jatropha pandurifolia and Jatropha gossypifolia are reported as 3.68 and 2.52 mol CO 2 /mol H 2 O, respectively. 155 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. 156 Thus, it is conceivable that water requirements of J. curcas will be similar to that of other oil seed species; although the plant may survive droughts, it may not produce efficiently or economically when it is water-deprived. 157 Obviously, further studies rela ting water use to crop production must be performed.

Because J. curcas has been observed growing on low quality soils with low nutrient amounts, it is often 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. 158,159 The long-term impact of monocultu res of jatropha on soil health has also not been studied thoroughl y. Some studies indicate that J. curcas may not be sustainable, unless specific st eps are taken to ensure the plantations’ long term health. 160,161

The seed of J. curcas , as previously mentioned, has a lipid content of roughly 25-45 percent by weight. 162,163 Thus, assuming a seed oil conten t of 35 percent and an extraction efficiency of 75 percent, this would yield 404-2040 kg oil/ha or 439-2217 liter oil/ha. 164 This is somewhat higher than other oil producing crops like soybean, sesame, sunflower, rapeseed, and castor with a range of 375-1200 liter oil/ha.

Currently, J. curcas is present in 2 states (Florida and Hawaii) in the U.S. 165 Because of
J. curcas’ intolerance to frost, only small portions of the United States are typically considered for cultivation with current crop varieties . Areas with the most suitable climate conditions for cultivation can extend as far as 30° N in latitude; this would include the s outhern parts of Texas and Louisiana, and most of Florida. 166 Assuming no irrigation (as J. curcas is assumed to be a low-input crop), an absolute minimum of 500 mm of rainfall is re quired for substantial production, this occurs in the easternmost portions of Texas, and all of Louisiana and Florida. 167 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. 168 As research progresses and new varieties are identified, future locations for growth of J. curcas may be possible than currently suggested.

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 canol a is grown in the United States. Canola can be grown as either a spring or winter crop, with yi elds for winter canola be ing significantly higher than those for spring canola (1,500 pounds per acre vs. 3,500 pounds per acre ). 170 The oil content of the canola seeds is approximately 40% . The oil produced from the canola seeds is low in saturated fat and high in omega-3 fatty acids, ma king it desirable for use as edible oil. These Deleted: can be

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.64 traits, combined with the higher price of canola oil result in very little canola oil being used in biodiesel production today. The hi gh oil yields and potential for ca nola to be grown as a winter 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 America and is most common in the northern Midwest. Recently there has been interest in the potential use of the oil extracted from camelina seeds as a biodiesel feedstock. Camelina’s suitability to northern climates, low moisture, and marginal soils allow it to be grown in areas that are uns uitable 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

. 172 Camelina can also be used to br eak the continuous planting cycle of small grains, effectively reducing the disease, insect, and weed pressure in fields planted with wheat the following year

. 174 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 th rough selective breeding are likely

. 175 Camelina is currently being grown on approximately 50 ,000 acres of land the U.S., primarily in Montana

, eastern Washington, and the Dakotas. 176

Pennycress

Pennycress is a winter annua l weed currently established in every state except Hawaii, but especially prevalent in the Midwest and northwest. It has several qualities that make it a potential feedstock source for biodiesel production. Pennycress germinates in the fall and grows as a winter cover crop. Pennyc ress 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

. 178 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 invasive 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 w ould be very difficult to remove. It has also not been grown as a commercial crop, and little is yet known about planting and cultivation requirements.

Pennycress is currently being grown on 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

. 180 While the initial attempts to grow pennycress were unsuccessful, more recent on farm trials have resulted in the successful establishment of pennycress

. 181 Pennycress has a large potential as a secondary crop if its cultiva tion proves to be profitable. Deleted: 171

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Deleted: ¶ ¶ ¶65 1.1.3.6 Imported Biodiesel

The European Union is expected to continue as the largest consumer of biodiesel, with use projected to be almost 3 billion gallons per year by 2018. 198,199,200 Given the E.U.’s limited land suitable for oilseed crops, it is likely that a significant portion of this fuel will be either imported or made fro m imported feedstock. 201 During this timeframe, other significant producers of biodiesel or its feedstocks, such as Argentina, Brazil, Indone sia, and Malaysia, are expected to increase domestic use of biofuels due to mandates or simp le economic advantage. 202

Our primary control scenario projects U.S. us e of biodiesel to rise to approximately 1.5 billion gallons by 2022. Given competition for imports by the E.U. and Asian markets where retail fuel prices are among the highest in the world, as well as the feasibility to produce this biofuel from domestically-sourced feedstocks (see discussion above), we do not expect imports to contribute to U.S. biodiesel for the foreseeable future. Thus, we are not assuming any imports of biodiesel for our analyses.

1.1.3.7 Biodiesel Feedstock Summary

Table 1.1-25 shows the volumes and uses of biodiesel and renewable diesel feedstocks as projected for the analyses in this rulemaking. Total volume here (1.67 billion gallons) fulfills the Biomass Based Diesel category requirements (1.0 billion gallons ) and contributes to the Other Advanced Biofuel (0.67 billion gallons), as projected for our primary control case (see Section 1.2.2).

Table 1.1-25. Estimated 2022 Biodiesel & Re newable 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 volume s required to meet th e Energy Independence and Security Act (EISA) necessitates establishi ng a primary set of fuel types and volumes on which to base our assessment of the impacts of th e new standards. 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. Deleted: In 2007, the EU produced 58 percent of worldwide biodiesel. Another 20 percent was produced in the U.S., with the remainder split between South America and the rest of the world. 182 ¶ ¶ EU biodiesel output increased from 200 million gallons in 2000 to 2.3 billion gallons in 2008. 183 According to some analysts, however, the EU does not have the agricultural capacity to expand oilseed production and in comparison to other climates, is not particularly good for oilseed production. 184 Estimates for future EU biodiesel production appear to be roughly 2.5 billion gallons by 2017. 185 ¶ ¶ 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. 186
Even with the increase in domestic production, however, it seems likely that the EU’s future biofuels consumption goals will not be met.¶ ¶ In 2007, the European Commission (EC) proposed a binding minimum target requiring 10 percent biofuel use for transport by 2020. 187,188 The International Energy Outlook forecasts OECD European countries will consume 147 billion gasoline gallons equivalent (gge) of transportation fuel in 2010, growing to 151 gge by 2020. Currently, approximately 60 percent of the EU’s transportation fuel demand is met by diesel. Assuming this split continues in the future, a 10 percent biofuel requirement would translate to roughly 8 billion gallons of biodiesel demand by 2017. Thus, it appears likely that the EU will not be able to produce enough biodiesel to meet its goals by 2020 and will need to depend on other countries to make up the remaining 5.8 billion gallon demand (after accounting for domestic production of 2.2 billion gallons as estimated from above). So not only will the EU, the largest current producer of biodiesel, not have any biodiesel available for export in the future; they will likely be a net importer competing with the U.S. for surplus biodiesel supplies.¶ ¶ As imports of finished biodiesel (or biodiesel feedstocks) are relatively new in the U.S. domestic market, volumes are currently small and not well-tracked by industry groups and EIA. Therefore, there is limited historical data from which

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- ... [5]66 The following subsections detail our rationale for projecting the amount and type of fuels needed to meet EISA. To assess the impacts of the increase in renewable fuel volume from business-as-usual (what is likely to have occurred without EISA), we have established reference and control cases. The reference cases are proj ections of renewable fu el volumes without the enactment of EISA and are described in further detail in Section 1.2.1. It is difficult to ascertain how much of the impact from the displacement of gasoline and diesel with renewable fuels might be due to the natural growth in renewable 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 relate d to renewable fuel production and use, climate cha nge, and national energy securi ty. The control cases are projections of the volumes and ty pes of renewable fuel that might be used to comply with the EISA volume mandates. For the NPRM we had focused on one primary control case whereas for the final rule we have expanded the analysis to include two additional sensitivity cases. We assume in each of the cases the same ethanol-equivalence basis as was used in the RFS1rulemaking to meet the standard. Volumes listed in the tables for this section are in straightgallons and allow for the reader to calculate ethanol-equivalent gallons if necessary (i.e. times 1.5 for biodiesel or 1.7 for cellulo sic diesel and renewable diesel). Sections 1.2.2 and 1.2.3 aim to describe the control cases in greater detail as well as provide fuel volumes and types for years prior to 2022.

The main difference between th e 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 hydrocar bon-based or so-called “drop-in” renewable fuels as well as butanol, and marketplace challenges for consuming high volumes of ethanol, we have included projections of more non-ethanol renewables in our primary control case for the final rule. 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 fuels or blendstocks such as biogas, jatropha, palm, imported cellulosic biofuel, and other alcohol s or ethers in our control cases. Although we have not included these renewable fuels and blendsto cks in our impact analyses, it is important to note that they can still be counted under our progr am if they meet the lifecycle thresholds and definitions for renewable biomass, and recent info rmation suggests that some of them may be likely.

1.2.1 Reference Cases

R Comments received from Advanced Biofuels Association, Testimony on June 9, 2009 suggesting a number of advanced biofuel technologies will be able to produce renewable diesel, jet fuels, gasoline, and gasoline component fuels (e.g. butanol, iso-octane). Similar comments were received from the New York State Department ofEnvironmental Conservation (Docket EPA-HQ-OAR-2005-0161-2143), OPEI and AllSAFE (Docket EPA-HQOAR-2005-0161-2241), and the Low Carbon Synthetic Fuels Association (Docket EPA-HQ-OAR-2005-0161- 2310).67 Our primary reference case renewable fuel volumes are based on the Energy Information Administration’s (EIA) Annual Energy Outl ook (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 renewa ble fuel volumes under EISA as well as fuel economy improvements under CAFE as required in EISA, whereas AEO 2007 did not.

For the final rule we also assessed a number of the impacts relative to the reference case assuming the mandated renewable fuel volumes under RFS1 from the Energy Policy Act of 2005 (EPAct). This allows for a more complete a ssessment of the impacts of the EISA volume mandates, especially when combined with the impacts assessment conducted for the RFS1 rulemaking (though many factors have changed si nce then). Table 1.2-1 and Table 1.2-2 summarize the renewable fuel volumes for years 2022 and prior, for the AEO 2007 and the RFS1 reference cases, respectively.

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.68Table 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.69Table 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/a2012 0.00 0.303 0.00 7.046 7.352013 0.00 0.303 0.00 7.046 7.352014 0.00 0.303 0.00 7.046 7.352015 0.00 0.303 0.00 7.046 7.352016 0.00 0.303 0.00 7.046 7.352017 0.00 0.303 0.00 7.046 7.352018 0.00 0.303 0.00 7.046 7.352019 0.00 0.303 0.00 7.046 7.352020 0.00 0.303 0.00 7.046 7.352021 0.00 0.303 0.00 7.046 7.352022 0.00 0.303 0.00 7.046 7.35aBiomass-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 the250-million galloncellulosicstandard set by EPActwould be met primarily by corn ethanol plantsutilizing 90% biomass for energy, thus actual production of cellulosic biofuel is zero.Formatted TableFormattedFormattedFormattedFormattedFormattedFormattedFormattedFormattedFormattedFormattedFormattedDeleted:0.25 billion gallonsof...biofuel... [6]... [12]... [7]... [13]... [8]... [14]... [9]... [15]... [10]... [16]... [11]... [17]70 1.2.2 Primary Control Case

Table 1.2-3 summarizes the fuel types and volumes for the primary control case for the years 2010-2022. Although actual volumes and feedstocks will likely be different, we believe the projections made here are within the range of expected outcomes when the standards are met and allow for an assessment of the potential impacts of the RFS2 rule. More details on contributions of differentfeedstock types within the renewabl e fuel categories here can be found in Section 1.1.71Table 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 0.040.22 0.29 11.24 12.482011 0.08 0.10 0.72 0.080.17 0.16 12.07 13.382012 0.15 0.20 0.92 0.080.12 0.18 12.83 14.482013 0.31 0.41 0.92 0.080.28 0.19 13.42 15.612014 0.54 0.71 0.85 0.150.39 0.20 14.09 16.932015 0.92 1.22 0.85 0.150.53 0.39 14.79 18.852016 1.31 1.73 0.85 0.150.56 0.63 15.00 20.232017 1.69 2.24 0.85 0.150.60 1.07 15.00 21.602018 2.15 2.85 0.85 0.150.64 1.51 15.00 23.152019 2.61 3.46 0.85 0.150.68 1.96 15.00 24.712020 3.23 4.28 0.85 0.150.72 1.88 15.00 26.112021 4.15 5.50 0.85 0.150.77 1.81 15.00 28.232022 4.92 6.52 0.85 0.150.82 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 to the amount needed to meet the biomass-based diesel standard.fMay not total due to rounding.72 1.2.2.1 Cellulosic Biofuel

As defined in EISA, cellulosic biofue l means renewable fu el 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 Admini strator, that are at least 60% less than the baseline lifecycle greenh ouse gas emissions.

When many people think of cellulosic biofuel, they immediately think of cellulosic ethanol. However, cellulosic bi ofuel could be comprised of othe r alcohols, synthetic gasoline, synthetic diesel fuel or hea ting oil, and synthetic jet fuel , propane, and biogas. Whether cellulosic biofuel is ethanol will depend on a num ber of factors, includi ng production costs, the form of tax subsidies, credit pr ograms, and issues associated with blending the biofuel into the fuel pool. For instance, under the Farm Bill of 20 08, both cellulosic ethanol and cellulosic diesel receive the same tax subsidies ($1.01 per gallon each). The tax subsidy, however, gives ethanol producers a considerable advantage over those producing cellulosic diesel due to the feedstock quantity needed per gallon produced (i.e. typically the higher the energy content of the product, the more feedstock that is required). On an energy basis, cellulosic ethanol would receive approximately $13/mmBtu while cellulosic diesel would receive approximately $8/mmBtu. It will also depend on the rela tive demand for gasoline and diesel fuel. For example, European refineries have been undersuppl ying the European market w ith diesel fuel supply and oversupplying it with gasoline, and based on the re cent diesel fuel price ma rgins 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 w ith gasoline, there could be a price advantage towards producing renewable fuels that displace diesel fuel rather than a gasoline fuel replacement like ethanol.

One large advantage that cellulosic diesel has over ethanol is the ability for the fuel to be blended easily into the current distribution infrastructure at sizeable volumes. There are currently factors tending to limit the amount of et hanol that can be blended into the fuel pool (see Section 1.7. of the RIA for more discussion). Th us, the production of cellulosic diesel instead of cellulosic ethanol could help increase consumption of renewable fuels.

Cellulosic biofuel could also be produced internationally. One example of internationally produced cellulosic biofuel is ethanol produced from bagasse from sugarcane processing in Brazil. Currently, Brazil burns ba gasse to produce steam and genera te bioelectrici ty. However, improving efficiencies over the coming decade as well as mechanization of sugarcane harvesting (no burning of biomass in fields) may allow an in creasing portion of bagasse to be allocated to other uses, including cellulosic biofuel, as additional straw could potentially be collected and used to produce bioelectricity. Although inte rnational production of cellulosic biofuel is possible, it is uncertain whether this supply would be available prima rily to the U.S. or whether other nations would consume the fuel domestically . Therefore, our analyses for cellulosic biofuel primarily focus on North Am erica, and for our impact analyses just on domestic supplies.

As discussed, there is uncertainty as to whic h mix of cellulosic biofuels will be produced to fulfill the 16 Bgal mandate by 2022. For a ssessing the impacts of the RFS2 standards, we used AEO 2009 (April release) ce llulosic ethanol volumes (4.92 billion gallons), as well as the cellulosic biomass-to-liquids (B TL) diesel volumes (1.96 billion gallons) using Fischer-Tropsch73 (FT) processes. We consider BTL diesel from FT processes as a subset of cellulosic diesel. In order to reach a total of 16 bil lion ethanol-equivalent gallons, we assumed that an additional 4.56 billion gallons of cellulosic diesel could be produced from BTL or other cellulosic diesel

processes.

1.2.2.2 Biomass-Based Diesel

Biomass-based diesel as defi ned in EISA means renewable fuel that is biodiesel as defined in section 312(f) of the Energy Policy Act of 1992 with lifecycle greenhouse gas emissions, as determined by the Administrator, that are at least 50% less than the baseline lifecycle greenhouse gas emissions. Biomass-based diesel can include fatty acid methyl ester (FAME) biodiesel, renewable diesel (RD) that has not been co-processed with a petroleum feedstock, as well as cellulosic diesel. Although cellulosic diesel produced through the FischerTropsch (F-T) process or other pr ocesses could potentially contribut e to the 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 cellulosi c biofuel category as discussed in the previous Section 1.2.2.1.

FAME and RD processes can make acceptable quality fuel from vegetable oils, fats, and greases, and thus will generally compete for the same feedstock pool. For our analyses, we have assumed that the volume contribution from FAME biodiesel and RD will be a function of the available feedstock types. For our analysis we assumed that virgin plant oils would be preferentially processed by biodies el plants. Other feedstocks a ssumed to be used by biodiesel plants are fuel-grade corn oil fro m corn oil extraction, fats, waste oils, and waste greases. For the FRM we have also included a small volume of oil feedstock fro m algae for biodiesel production. We note that there are a wide ra nge of new feedstocks being researched and developed for the production of biodiesel, e.g. camelina and pennycress. While these new feedstocks may prove to be commercially available in the future, we have not assumed that they are used for analyses purposes.

For RD, we assumed that the feedstocks used are from fats, waste oils, and waste greases. This is because the RD process involves hydrotreating (or thermal depolymerization), which is more severe and uses multiple chemical mechanisms to reform the fat molecules into diesel range material. The FAME process, by contra st, relies on more specific chemical mechanisms and requires pre-treatment if the feedstocks contain more than trace amounts of free fatty acids or other contaminates which are typical of recycled fats and greases. In terms of volume availability of feedstocks, supplies of fats, waste oils, and waste greases are more limited than virgin vegetable oils. As a result, our control ca se 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 furthe r classified as co-p rocessed or non-coprocessed, depending on whether the renewable material was mi xed with petroleum during the hydrotreating operation. EISA specifically forbids co-pro cessed RD from being counted as biomass-based diesel, but it can still count toward the total advanced biofuel requirement. What fraction of RD will ultimately be co-processed is uncertain at this time, since little or no74 commercial production of RD is currently underw ay, and little public info rmation is available about the comparative economics and feasibility of the two methods. Current industry plans indicate, however, that co-processing renewable diesel may not be as favorable as non-coprocessed RD, and therefore, we have chosen to assume zero volumes of co-processed RD. T Non-co-processed RD volumes are base d on production plans from Syntroleum.

1.2.2.3 Other Advanced Biofuel

As defined in EISA, advanced biofuel means renewable fuel , other than ethanol derived from corn starch, that has lifecycle greenhouse gas emissions, as determined by the Administrator, that are at least 50% less than baseline lifecycle greenhouse gas emissions. As defined in EISA, advanced biofuel includes the ce llulosic biofuel, biomass-based diesel, and coprocessed renewable diesel categories that were mentioned in Section 1.2.2.1 and Section 1.2.2.2 above. However, EISA requires greater volumes of advanced biofuel than just the volumes required of these fuels. It is entirely possible that greater volume s of cellulosic bi ofuel, biomassbased diesel, and co-processed re newable diesel than required by the Act could be produced in the future. Our control case assumes that the cellulosic biofuel volumes will not exceed those required under EISA. We do assume, however, that additional biodiesel than that needed to meet the biomass-based diesel volume will be used to meet the total advanced biofuel volume. Despite additional volumes assumed from biodiesel, to fully meet the total advanced biofuel volume required under EISA, othe r types of advanced biofue l are necessary through 2022.

We have assumed for the analyses conducted that for our control case the most likely source of advanced fuel other than cellulosic biofuel and biom ass-based diesel would be from imported sugarcane ethanol and perhaps limited amounts of co-processed renewable diesel. Our assessment of intern ational fuel ethanol production and de mand indicate that anywhere from 3.8- 4.2 Bgal of sugarcane ethanol from Brazil could be available for export by 2020/2022. If this volume were to be made available to the U.S., then there would be sufficient volume to meet the advanced biofuel standard. To calculate the amount of imported ethanol needed to meet the EISA advanced biofuel standards, we assumed it would make up the difference not met by cellulosic biofuel, biomass-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 plans for sugarcane ethanol to be produced in the U.S in places where the sugar subsidy does not apply. For instance, sugarcane has been grown in California’s Imperial Valley specifically for the purpose of making ethanol and using the cane’s biomass to generate electricity to power the ethanol distillery as well as export excess electricity to the electric grid. V There are at least two projects being developed at this time that

T On May 13, 2009 ConocoPhillips and Tyson suspended plans for building RD co-processing facilities. The tax credit for RD co-processing that helped fund the project was cut from $1 a gallon to 50 cents a gallon as part of the credit bill approved by Congress and signed by President Bush in late 2008. The non-co-processing tax credit remains at $1 a gallon.

U The exceptions were for the years from 2010-2015 in the control case, where we assumed AEO 2007 imported ethanol volumes; otherwise, imported ethanol volumes would be zero and lower than the reference case volumes.

V Personal communication with Nathalie Hoffman, Managing Member of California Renewable Energies, LLC, August 27, 200875 could result in several hundred million gallons of ethanol produced. The sugarcane is being grown on marginal and existing cropland that is un suitable 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 coul d be produced from biomass and used in lieu of ethanol to comply with th e RFS2 standard. Productio n of butanol is being pursued by a number of companies including a partnership between BP and Dupont. Other companies which have e xpressed the intent to produce biobuta nol are Baer Biofuels and Gevo. The near term technology being pursued for pr oducing butanol involves fe rmentation of starch compounds, although it can also be produced fro m 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 ble ndstock 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 w ould likely allow butanol to be blended with gasoline at high enough concentrations to avoid the need for most or all of high concen tration ethanol-gasoline blends, such as E85, that require the use of fuel flexible vehicl es. Thus, butanol would enable achieving most of the RFS2 standard by blendi ng a lower concentration of renewable fuel than having to resort to a sizable volume of E85 as in the case of ethanol. The need to blend ethanol as E85 provides some difficult challenges. Th e 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 hi gh 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 ha s 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 produc tion 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 combustib le 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 biologic al decomposition of organic matter, as in a landfill or wastewater treatment facility, as well as those produced via thermochemical processing of biomass.76 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 suitablefor use in heavy duty vehicle fleets. Current literature suggests approximately 24 billion ethanolequivalent gallons of biogas (re ferring to energy content) coul d potentially be produced in the long term, with about two thirds coming from bi omass gasification and about one third coming from waste streams such as landfills and human and animal sewage digestion. 203, 204 Because the majority of the biogas volume estimates assume bi omass as a feedstock, we have chosen not to include this fuel in our analyses since we are projecting most available biomass will be used for cellulosic liquid biofuel production in the long term. The re maining biogas potentially available from waste-related sources would come from a large number of small streams requiring purification and connecti on to storage and/or distribution facilities, which would involve significant economic hurdles. An additional and im portant 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 streams to continue to find mostly non-transportation uses such as electrical power generation or facility heating.

1.2.2.4 Other Renewable Fuel

The remaining portion of total renewable fuel not met with advanced biofuel is assumed to come from corn-based ethanol (including small amounts from ot her starch grains and waste sugars). EISA effectively sets a limit for participation in the RFS program of 15 Bgal of corn ethanol, and we are assuming for our analysis that sufficient corn ethanol will be produced to meet the 15-Bgal limit that either meets the 20% GHG threshold or is grandfathered. It should be noted, however, that there is no specific “corn-ethanol” mandated volume, and that any advanced biofuel produced above and beyond what is require d for the advanced biofuel requirements could reduce the amount of corn ethanol needed to meet the total renewable fuel standard. This occurs in our pr ojections during the earlier years ( 2010 -2015) in which we project that some fuels could compete favorably with corn ethanol (e.g. biodiesel and imported ethanol). Beginning around 2016, fuels qualifying as advanced biofuels likely will be devoted to meeting the increasingly stringent volume mandates for advan ced biofuel. It is also important to note that more than 15 Bgal of corn ethanol could be pr oduced 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 biofue l RINs, e.g. corn ethanol RINs.

We are assuming for our analysis that suffi cient 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 suffi cient corn ethanol production exis ts that is grandfathered and not required to meet the 20% threshold. Our curre nt 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. Deleted: 200977 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 im pact analyses conducted for the ru le. The first case, we refer to as the “ low-ethanol ” control case and assume only 250 million gallons of cellulosic ethanol (from AEO 2007 reference case). The rest of the 16 billion gallon cellulosi c 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 ce llulosic ethanol, see Table 1.2-5. Deleted: Low-Ethanol

Deleted: High-Ethanol78Table 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 0.040.22 0.29 11.24 12.472011 0.00 0.14 0.72 0.080.17 0.16 12.07 13.352012 0.01 0.29 0.92 0.080.12 0.18 12.83 14.422013 0.02 0.58 0.92 0.080.28 0.19 13.42 15.492014 0.03 1.01 0.85 0.150.39 0.20 14.09 16.722015 0.05 1.74 0.85 0.150.53 0.39 14.79 18.492016 0.07 2.46 0.85 0.150.56 0.63 15.00 19.722017 0.09 3.18 0.85 0.150.60 1.07 15.00 20.942018 0.11 4.05 0.85 0.150.64 1.51 15.00 22.312019 0.13 4.92 0.85 0.150.68 1.96 15.00 23.692020 0.16 6.08 0.85 0.150.72 1.88 15.00 24.852021 0.21 7.82 0.85 0.150.77 1.81 15.00 26.612022 0.25 9.26 0.85 0.150.82 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 to the amount needed to meet the biomass-based diesel standard.fMay not total due to rounding.Formatted:Font: (Default) TimesNew RomanFormatted:Font: (Default) TimesNew Roman79Table 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 0.040.22 0.29 11.24 12.512011 0.25 0.00 0.72 0.080.17 0.16 12.07 13.452012 0.50 0.00 0.92 0.080.12 0.18 12.83 14.622013 1.00 0.00 0.92 0.080.28 0.19 13.42 15.892014 1.75 0.00 0.85 0.150.39 0.20 14.09 17.432015 3.00 0.00 0.85 0.150.53 0.39 14.79 19.702016 4.25 0.00 0.85 0.150.56 0.63 15.00 21.442017 5.50 0.00 0.85 0.150.60 1.07 15.00 23.172018 7.00 0.00 0.85 0.150.64 1.51 15.00 25.152019 8.50 0.00 0.85 0.150.68 1.96 15.00 27.132020 10.50 0.00 0.85 0.150.72 1.88 15.00 29.112021 13.50 0.00 0.85 0.150.77 1.81 15.00 32.082022 16.00 0.00 0.85 0.150.82 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 to the amount needed to meet the biomass-based diesel standard.fMay not total due to rounding.Formatted:Font: (Default) TimesNew RomanFormatted:Font: (Default) TimesNew Roman80 

### 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 alre ady 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 pot ential 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 harv est, storage, and tran sportation 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 herbace ous energy crops, on the other hand, are not currently being harvested on a large scale and therefore new pr ocesses must be developed to make them available to be used in the production of biofuels.

1.3.1.1 Municipal Solid Waste (MSW) Collection

As discussed above, MSW is one of the potentia l sources of renewable fuel feedstock that already has a well developed collection system already in place. In many cases cities and municipalities are already recovering recyclable materials, such as metals, plastics, and paper, from the collected waste streams. After these valuable materials have been removed from the waste stream the remainder of th e 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 wit hout the potentially expensiv e separation process if the waste material is separated by the waste producer at the curbside. One potential producer of biofuels from MSW indi cated in a confidential conversati on that this was the method they planned to use to obt ain their feedstock.

In parts of the country where these recyclable materials are not currently recovered it will be necessary for the biofuel producer who wishes to use this material to first remove the metals, plastics, and other contaminated materials before this material may be used. This sorting can be done either by hand or with an automated proce ss. Cleaner streams are produced when the waste stream is sorted by hand, however this is a slow er and more expensive pro cess. 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 facility81 and the biofuel production facility would be located at the same site, and thus no transportation would be necessary between these two facilities.

1.3.1.2 Wood Residue Collection and Harvest

Another potential source of f eedstock that may be converted to cellulosic biofuels are wood residues. This category of feedstock refe rs to a large range of currently unused wood wastes from forestry and wood pr ocessing industries. Significa nt sources of wood residue are either currently available or expected to be ava ilable in the near future in the form of mill residues, forest residue, and forestry thinnings.

Mill Residue

One source of currently available wood residue is mill residue. Mill residue is a waste product of both primary mills, mills that convert roundwood into other wood products, and secondary mills, those that produce finished consumer products. Because this residue is currently being produced at the primary and secondary mills all that would be required for its use as a cellulosic biofuel feedstock is it’s colle ction 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. Th e amount of residues poten tially available is a function of harvest amount, lo gging method, and type a nd location of timberlands. 205 In addition, residue availability is limited by economic factors. According to one study, “the actual operations of harvesting, collectin g, processing and transporting l oose forest residues are costly and present an economic barrier to rec overy and utilization of wood for energy”. 206 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 r ecovering forest residue for biomass is inwoods chipping. 207 This method is suitable for operations where there is whole-tree skidding to roadside, good road access to chip vans and chi ppers, and sufficient biomass volume per acre. However, in-woods chipping systems are not as effective when ground-based skidding is restricted or when there are no merchantable products other than biomass. In addition, the chip vans designed to haul wood chips were built for highway use and often do not have sufficient suspension systems for remote forest roads. Th ere are also high costs for wood grinders with low production rates. 208 Fortunately, there have been deve lopments in altern ative methods to reduce the costs of biomass collection systems.

There has been much focus recently on devel oping methods of dens ifying 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 bundling82 machines, horizontal grinders, and roll on/off container transport) . One of the advantages of using slash bundling machines is the ability to store biomass longer than in chip form. Storing biomass at roadside in the form of biomass bundles could provide a more secure and stable biomass supply than with chips which are smaller and have greater surface area for potentialweathering. Utilizing roll on/off containers allows for recovery of residue from difficult-toaccess locations and in such situations could be competitive with regular highway chip vans.

While these are just some of the ways to improve recovery operations for forestry residues, these methods still have challenges. For example, there are some difficulties with bundling of brittle residues or short, large diameter pieces. In addition, some residues may include rocks or trash that can result in additional saw maintenance and reduced utilization. With millions of acres of forest, there is no single residue treatment option that will meet the needs of all situations. Forest land managers will need to weigh the different options for dealing with forest residues to determine the most co st-effective means for residue removal in their specific locations.

Forest Thinnings

A third source of wood residue is forestry thinnings. Forest thinnings refer to woody material removed from forests that have become overgrown, either to reduce the risk of forest fires or to increase pr oductivity 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 thinni ngs is paid for by the land owner. Therefore, in order to use this material as a cellulosic feed stock the forest thinnings would only have to be collected from the forest and move d to the roadside. Once at the roadside they would likely be either chipped or bundled using th e process previously discussed to increase the density of the thinnings, and thus reduce the transportation costs.

1.3.1.3 Agricultural Residue Harvest

Agricultural residue is a very large and potentially readily available cellulosic feedstock source for biofuels producers. Wh ile the residues of some crops have been harvested for many years, much crop residue is left on the fields in order in increase soil qua lity and protect against erosion from wind and rain as di scussed in Section 1.1. Despite the many benefits of leaving agricultural residue on the fields we believe that it is possible to remove some portion of the agricultural residues without signif icant negative impacts to the soil quality in many parts of the country. We also believe that agricultural residues will make up a large portion of the cellulosic feedstocks used for biofuel production by 2022. The following section discusses the likely process for agricultural residue harvest and the associated challenges we anticipate. We have chosen to focus our discussion on corn stover as it is expected that it will be used more extensively than any other agricultural resi due, 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.83 Corn stover harvest, at present, requires multiple machines: combines, shredders, rakes, balers, bale wagons, and stackers just to get the stov er 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 form a windrow, of sorts, following which the windrow is baled. 209 However, modern combines leave most of the stalk standing. In or der to harvest as much of the stove r as possible, it is necessary to shred the standing stalks and then rake all of it together prior to baling. 210 The baler pickup must be set high enough to avoid picking up dirt and di rt 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/g rower 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 become a single, mixed grain and stover stream. The harvester blows the entire stream into tractor-pulled grain-carts that run along-side the harvester. When a cart is filled, it is replaced by an empty cart, and the full cart is hauled to the field side, where it’s unloaded into bulk ‘walking-f loor’ 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 proce ssing before it’s sent to storage. Although a facility (equipment, buildings, etc.) at an elevator for separating the corn grain from the stover has not been constructed, we anticipate that it could operate very much like a modern grain harvester/combine, except it will obviously be stationary. The entire stream could be fed, by chain or belt, where it drops between a cylinder covered with rough steel bars and a piece of equipment called a concave. As the cobs are r ubbed between the steel bars and concave, the corn grain rubs off and drops onto a perforated be lt; most of the stover remains are larger than corn grain pieces, and is moved rearward toward the spreader. The corn grain and small stover particle fall through and are carried to a chaffer.

Small grain straws, such as those from wheat, oats, barley, and rice have been harvested for many years. A significant difference between the harvesting equipment used for corn stover and these grains, is that the small grain plant is cut off near the ground and passes through the combine at the time of harvest. It falls to the ground from the harvester into somewhat of a windrow; in some cases, the windrow many need to be raked together before baling to gain maximum removal efficiency. Since the whole grai n plant had dried prior to harvest, it’s not necessary to wait for the straw to dry before it’s ba led. Small grain straws can be baled, hauled, and stacked in standard small ba les or in larger 3’ x 4’ x 8’ square bales with current hay equipment.84 Sugarcane bagasse is not harvested, in the sense we’ve discussed ‘a harvest.’ It is a byproduct of sugar production from sugarcane, de livered 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 fromthe sugar fermentation facility to the cellulosic biofuel production facility if they are not colocated.

1.3.1.4 Energy Crop Harvest

Energy crops are another very large potential, yet currently unutilized, source of cellulosic feedstock. As with corn stover, no harvesting process for energy crops currently exists. Additionally, the harvesting process used for energy crops will vary greatly depending on whether the energy crop is herbaceous, such as switchgrass or miscanthus, or woody, such as hybrid poplar. Nevertheless, we believe that the harvesting practices for energy crops will resemble those currently used for small grains and tree plantations respectively.

Herbaceous Energy Crops

The harvesting process for herbaceous energy crops, such as switchgrass and miscanthus, is expected to closely resemble that described for corn stover in the preceding section. When the herbaceous energy crops are sufficiently dry they will be cut with a mower or swather, similar to those used to harvest hay, and left on the field in windrows. The energy crops will then be baled and moved to the roadside where they will await transportation to a storage location.

While it is possible to harvest herbaceous energy crops using currently available equipment designed for hay and ot her agricultural residues, the high yields of these crops present several challenges. The higher production rates per acre of energy crops, when compared to hay or corn stover, will require unique equipment designs. There is also likely to be a small harvest window where the crop is ready to be harvested, but before the onset of winter weather, especially in northern parts of the country. As more energy cr ops are grown and harvested as feedstocks for biofuels and energy sources in other sectors, it is likely that harvesting equipment will be developed that is optimized for energy crops.

There may also be significant regional variation in the harvesting process for energy crops. Energy crops grown in the south will 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 th e 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 Crops85 As with herbaceous energy crops, it is possible to harvest woody energy crops with equipment currently in use by logging operations and the pulp and paper industry. Trees can be cut and gathered using a feller buncher and then transported to the roadside. Once at the roadside they can either be chipped and blown in to chip vans for transportation to the biofuel production facility, or bundled using the process described above in the forest residue section. It is more likely, however, that woody energy crops will be harvested using equipment specifically designed for that purpose and able to take adva ntage of the regular spacing of the trees found on tree plantations. In Europe self propelled harvesters that cut and chip the woody energy crops are being used. The wood chips are then stored in large stacks until they are transported to the facility where they will be used 211 . 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 a nd allowed to dry before being chipped and used for biofuel production. We anticipate that woody energy crops will be harvested using a process optimized to fit the individual woody energy crop plantati on, likely resembling one of the processes just described.

1.3.2 Feedstock Transp ortation and Storage

Once cellulosic feedstocks have been made available at the roadside, either through collection or harvesting, they must then be transported to the biofuel production facility. For some feedstocks, such as sorted MSW, this may be as simple as delivering the feedstock to a biofuel production facility rather than a landfill. For other feedstocks, such as agricultural residue or energy crops, it will require a much more complicated process involving multiple relocations, loadings, and unloadings, as well as storage in a secondary storage facility. The complexity of the transportation of the feedstock from the location where it is produced to the biofuel production facility is most dependent on whether the feedstock is available year round and harvested on an as needed ba sis or collected or harvested on an annual or se mi-annual basis.

1.3.2.1 Secondary Storage

One potential challenge for cellulosic biofuel producers is where the cellulosic material will be stored before it is converted into fuel. Some feedstocks, such as MSW or wood residues, can be collected or harvested year round. It will therefore only be necessary for the biofuel production facility to store a small amount of feedstock on site, we estimate 3-4 days worth, and additional feedstock can be received regularly di rectly from the producers. Agricultural residues and herbaceous energy crops, however, are harves ted annually or semi-a nnually, and therefore the biofuel producer must be able to store a years worth of feedstock. Because of the low energy density of cellulosic feedstocks it would not be 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 storin g 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 storage at the farms where it is produced would be problematic. Storing significant quantities of feedstock at the farm sites could force land that would othe rwise be used for feedstock pr oduction to be instead used for86 feedstock storage. Heavy traffic by the bale loaders and trucks used for transportation could cause significant damage to the farmers’ fiel ds. 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 interr upted by extended periods of incl ement weather. We believe 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 cellulosi c feedstock would be moved fro m the site of production to a secondary storage facility at the time of harvest. It would then be transported from the secondary storage site to the biofuel production facility as needed. Feedstock from many farms would be collected at a single s econdary storage site. The number of secondary storage sites would depend on the size of the biofuel production plant and the density of the feedstock production. Storing cellulosic feedstock in secondary storage sites increase s the delivered cost of the feedstock, but could be necessary due to the limitations of on farm storage mentioned above.

In addition to where the cellulosic feedstock is stored, there is also the question of how the feedstock will be stored. Many different ways of storing the feedstock have been suggested, ranging from stacked bales exposed to the weather, to bales wrapped in plastic, to storage in covered buildings or pole barns. The issue of whether the feedst ock should be baled as round or square bales also effects how the feedstock shoul d be stored. Round bales store better in the open than square bales since rain, and particularly snow, collect on flat surfaces more readily than on round. When stacked, however, round ba les usually cannot be stacked more than three bales high without the risk of de formation, instability of the st ack, and dry matter loss. Square bales, however, can be stacked as many as five high without the risk of instability.

In making the decision whether to store the bales in an indoor facility the cost of the storage facility must be weighed against the dry matter loss that will result from storing the bales in the open. Dry stover bales stored indoors or outdoors had aver age dry matter losses of 5% and 15%, respectively. Wrapping dry bales in net or plastic wrap and storing on a well drained surface significantly reduced dry matter loss compar ed to storing twine wr apped dry bales on the ground. 212 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 fe asible to transport and stack wrapped bales at a secondary storage site. Indoor storage is, in most cases, a conc rete slab with a roof, supported by poles, with open sides (pole-barn). Depending on the number of bale s to be stored, the slab must be sized to include aprons around all four edges with aisles between stacks to accommodate stacking and hauling equipment and for fire safety. Considering these many factors, we believe that indoor storage is the storage method that will be most widely utilized. This is the storage method which was used in our cost analysis, which can been seen in more detail in Section 4.1.1.

1.3.2.2 Municipal Solid Waste (MSW) Transportation

Transportation and storage of MSW as a 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. This would be done in large over-the-road trucks. The biofuel87 producer would have to store several days worth of feedstock at the fuel production site to ensure that fuel production is not interrupted, but because MSW is produced and collected year round no secondary storage would be necessary.

If the biofuel producer is receiving unsorted MSW it is probable that the sorting facility would be co-located with the biofuel production facility. If the biofuel production facility is near the source of MSW it may be possible for the lo cal refuse collection trucks to deliver the MSW to the plant directly. If the biofuel production facility is located some distance from the MSW source it will be more cost effective to transfer the MSW from local refuse collection trucks to large over-the-road trucks for transportation to the biofuel production facility. Once again, no secondary storage would be required due to the consistent availability of MSW. In this case, however, the biofuel producer would have to arrange for the trans portation of recovered recyclable materials, as well as contaminated waste that cannot be used to produce biofuels.

1.3.2.3 Wood Residu e Transportation

Wood residues are expected to be collected from the places they are produced, the primary or secondary mill for mil l residues and the roadside of th e forestry operation for forest residue and forest thinnings, and transported directly to the biofuel production facility in large over-the-road trucks. For each of the three types of wood residues we expect that the wood will be chipped or processed in so me other way to increase the de nsity of the residue before transportation. This will reduce transportation costs by allowing a greater mass of wood residue to be transported by each truck. As with MSW, secondary storage is unlikely to be necessary for wood residues as they are available to be harvested throughout the year.

1.3.2.4 Agricultural Residue and Ener gy Crop Transportation and Storage

Unlike MSW and wood residues, which are av ailable to be harvested and collected throughout the course of the year, agricultu ral residues and herbace ous energy crops are harvested on an annual or semi-annua l basis. As a result, a large amount of feedstock, enough to supply the biofuel production facility for a whole year, must be stored and delivered throughout the year. We expect secondary storage sites, as described above, will be the best option. Following the baling operation, the bales of agricultural residue or energy crops will be picked up from the field in 10-bale loads, by vehicles designed for that purpose. Such vehicles are currently used to gather hay ba les today. The bales are subse quently unloaded or dropped at the field-edge. Later, the bales are loaded onto wa gons pulled by high-speed tractors that haul as many as 20-bales per load to satellite storage (t he pole-barns desc ribed 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 tr ucks and trailers that can haul net-loads of up to about 45- to 50-tons. However, because the bale density is low (on average, about half the weight of a similarly sized hay bale), the maximum number of bales a truck can haul usually weighs much less than the maximum allowable weight. Grindi ng the baled feedstock be fore transportation to the biofuel production facility would increase the density of the feedstock, and therefore increase the mass that each truck could transport and lower the overall transportation costs.88 As discussed in Section 1.3.1.2, we anticipate that the corn stover harvest could become a single-pass operation by 2022. In this case corn stover would be transported from the farm to a specialized cellulosic feedstock depot to be processed. Equipment at the cellulosic feedstock depot would chop and dry the corn stover. This distributed preprocessing facility can provide significant cost benefits by producing a higher value cellu losic feedstock with improved handling, transporting, and merchandising potential. In addition, data supporting the preferential deconstruction of feedstoc k materials due to their bio-composite structure identifies the potential for significant improvements in equipment efficiencies and compositional quality upgrades. 213 The stover, now with flowability characteristics similar to small cereal grains, is moved by standard grain loading and unloading systems into large corrugated steel bins for intermediate storage. In this harvest format, the stover is handled by only two machines before it reaches the roadside and never hits the ground, significan tly reducing dry matter losses. The biofuel producer would then pick up its feedstock from th e elevator/depot in trucks and trailers for transport to the facility. We believe stover feedstock in the ground format could have a significantly higher bulk-density than baled stover, which should translate into lower transportation costs.

1.3.3 Cellulosic Feedstock Tr ansportation and Storage Tool

In order to better estimate the impacts of tr ansport and secondary storage on the overall price of cellulosic ethanol , we have developed a tool 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 tool also provides us an estimate of the type of feedstock material used by each plant, allowing us to determine th e average cost of secondary storage for these materials.

1.3.3.1 Basis and Assu mptions for Transport Tool

Feedstock densities and locations have been compiled on a county basis for use within the tool . This information has been provided by a variety of sources, including the National Forestry Service for forestry residue, the Nati onal Agricultural Statistic al Service (NASS, 2007) for agricultural residues and Elliot Campbell from Stanford University for energy crops. Municipal solid waste is also considered for this tool . For more information regarding the sources of data used for the tool , see Section 1.1.2 of this RIA. Data for agricultural residues provided by NASS reported harvested grain values , and needed to be modified to reflect agricultural residue values, using grain to residue ratios 214 . Data provided from FASOM modeling was used in this tool for total feedstock usage as well as farmside cost.

In order to simplify the location of plants within the tool , 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 mate rial from farmside to the count y centroid, with consideration for feedstock density within the county as well as the total county area. Furthermore, transport of feedstock between counties (for plants importing feedstock outside the county they are located in) is based on the distance between county centroid locations, with an additional factor to Deleted: Model¶

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Deleted: model89 account for the added distance of using on-road tran sportation. 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 tool closely follow the determinations made in Section 1.3.2 above. Secondary storage costs in the tool 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 tool assumes that no secondary storage is necessary for either municipal solid waste, wh ich would be transported to the plant directly by waste removal services; or for forest residue, which can be harvested year-round and transported on as-needed to the plant. Capital costs used in the tool for plant selection are ba sed on current refinery modeling, broken down by PADD location. Thes e capital costs are base d 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 Tool Operation

The tool begins operation by compiling feedstock availability (by county) based on the data sources discussed in Section 1.3.3.1. Using county loca tions, it builds a list for each county that contains the locations of other counties wi thin 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 tool operation. The tool then adds feedstock information such as feedstock densities, total amount of feedstock available, and feedstock type specific to each county. Using this feedstock information, the tool generates a list of all feedstocks available for each county; both within the c ounty itself as well as feedstock available for import from othe r neighboring counties. At the end of this step in the tool operation, each county has a datapoint in the tool which contains a complete lis t 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 a ssumptions discussed in Section 1.3.3.1, the tool calculates and adds complete cost information for each feedstock available to a county. These costs include the farmside cost of the feedst ock, the transportation required to move the feedstock to the centroid of its own county and the secondary storage of that feedstock. If the feedstock is available by import from a neighbor ing county, the transpor tation 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 tool 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 tool operation, the list of feedstock availability cost is used to choose feedstocks that a plant located at each county centroid would processes. For each county, the cheapest feedstock from the list is selected fo r 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 to tal volume of feedstock processe d 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 tool continues adding feedst ock sources to a county by selecting the next cheapest feedstock on the list. Selection proceeds until either the county either reaches a set Deleted: model

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Deleted: model90 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 c ounty datapoint contains information regarding the cheapest total cost to produce cellulosic ethanol at that location.

The tool 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 tool . The feedstock used in by location is removed as a source from any feedstock availability list used by other counties. The tool then repeats using this modified feedstock data, starting from the step involving the selection of feedstocks used in a county. In this way, a list of estimated plant locations is chosen by always selecting the next cheapest location in which a plant can be built; this provides the final output of the tool . The tool stops operation when the total processed volume of all locations selected reaches the sixteen billion gallon maxi mum discussed in Section 1.3.3.1.

1.3.3.3 Final Tool Output and Interpretation

Not only does the tool provide estimated plant locations, it also provides supplementary information we have used to estimate average transportation and storage costs for feedstocks used by each plant, and subsequently all plants estimated by the tool . Since both the farmside feedstock cost as well as the contribution of capita l cost is known for each of the estimated plants (as these are inputs to the tool ), the transportation and storage costs can be calculated for each ton of feedstock processed by th at plant, including county to county transport. The cost of transportation for each plant can then be averag ed with the other plants selected by the tool to arrive at a total transportation and storage cost average across all plants selected by the tool . For more information about how these transportation a nd storage costs are used, see Section 4.1.2 in this RIA. Deleted: model

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Deleted: model91 Figure 1.3-1 Illustration of Estimated Plant Sites Selected by Plant Siting Tool

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 tool can be seen. It is important to note that the above av erage number of plants se lected for the southern region of the United States is most likely due to the lower capital costs associated within the this region. The tool takes into account regional variations of plant constr uction and operation costs. The lower capital cost in the southern region (most likely due to existing construction infrastructure for conventional oil refineries) reduces the overall price of plants selected in these locations, and we feel explains why the tool has a preference for this region of the country. More specific information on th ese capital cost regions can be found in Section 4.1.1.2 of this RIA.

The tool 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 tool output that most closely matches the output for feedst ock 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 tool can be easily adjusted and updated to take into account this new information.



### 1.4 Biofuel Production Technologies

Biofuel production tec hnologies continue to evolve with research and development efforts focused on reducing costs and increasing efficiencies. Improvements include increasing conversion yields for various f eedstocks, reducing energy and ma terials usage, eliminating or reducing wastes, finding alternative uses for by- products, etc. For those technologies not yet Deleted: Model

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Deleted: Section Break ( Continuous ) ¶ Section Break (Continuous)92 commercial, researchers are combining their innova tive ideas to develop cost-effective processes to produce biofuel at low enough costs to comp ete with their petroleum counterparts. The following sections describe bot h 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 conv erting 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) andgenerally produce only one primary co-product: distillers grains with solubles (DGS). The coproduct is sold wet (WDGS) or dried (DDGS) to the agricultura l market as animal feed. Wet mill ethanol plants separate the grain kernel prior to processing into its component parts and produce other co-products (usually gluten feed, gluten meal, and food-grade corn oil) in addition to DGS. Each process is described in great er detail in the subsections that follow.

Figure 1.4-1. Components of the Corn Kernel

ENDOSPERM Contains nearly all the starch used to make ethanol and also contains protein used in animal feed.

TIP CAP Attachment point of the kernel to the cob. PERICARP/BRAN The protective covering of the kernel. Contains fiber used in human and animal food products.

GERM

Contains corn oil used in food applications as well as biodiesel production.

1.4.1.1 Dry Milling Technology 215

In traditional dry mill plants, first the corn is screened to remove any unwanted debris. Then, it goes through a hammer mill where it is ground into course flour also know as “meal.” Next the meal is cooked to physically and 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 adde d. The slurry is heated to 180– 190°F for about 30–45 minutes to reduce viscosity.

The second step in the cooking process is lique faction, which occurs in two steps. First the hot slurry is pumped through a pressurized jet cooker at approximate ly 220°F and held for93 about 5 minutes. The mixture is then cooled by an atmospheric or vacu um 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 glucoamylase enzyme breaks down the dextrins to form simple sugars. Yeast is added to conver t 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 th e ethanol. By the time the product stream leaves the distillation columns, it contains about 95% ethanol by volume (190-proof). The residue from this process, called stillage, contains non-fermentable solids and water and is pumped out from the bottom of the columns into the centrifuges.

The final step in the ethanol production pro cess is dehydration to remove the remaining 5% water. The ethanol is passe d through a molecular sieve to phys ically 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 cons umption) and the ethanol is placed into storage.

During the ethanol production process, tw o primary co-products are created: carbon dioxide and distillers grains. As yeast ferment the sugar, th ey 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 pr ocessing 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 with 5–10% solids) and wet distillers grain.

Some of the thin stillage is routed back to the cooking tanks as makeup or “backset” water, reducing the amount of fre sh water required by the cookin g process. The rest is sent through a multiple-effect evaporation system where it is concentrated into a condensed distillers solubles or “syrup” containing 25–50% solids. This syrup, which is high in protein and fat content, is then mixed back in with the distillers grain to make wet distillers grains with solubles.

Wet distillers grains with solubles (WDGS) contain most of the nutritive value of the original feedstock (plus added yeast) and can be easily conveyed as a wet cake for transport. As such, WDGS makes an excellent cattle ration for local feedlots and dairies. However, WDGS must be used soon after it’s produced because 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 dryi ng system to remove moisture and extend the94 shelf life. The resulting dried di stillers grains with solubles (DDGS) are commonly used as a high-protein ingredient in cattle, swine, poultry, and fish diets. Distillers grains are also being researched for human consumption. A schematic of a typical dry-mill ethanol plant is shown below in Figure 1.4-2.

Figure 1.4-2. Dry Milling Process

1.4.1.2 Wet Milling Technology 216

In wet mill plants, first the corn is soaked or "steeped" in a dilute sulfurous acid solution for 24-48 hours. The steeping process facilitates the separation of the corn kernel into germ, fiber, gluten, and starch.

After steeping, the corn slurry is processed 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 i ndustry. However, most wet mill plants refine the product into food-grade corn oil for use in cooking applications. The remaining fiber, gluten and star ch components are further segreg ated using centrifugal, screen, and hydroclonic separators.95 The steeping liquor is concen trated in an evaporator. This concentrated product, heavy steep water, is co-dried with th e 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-friendl y alternative to salt for removing ice from roads.

The gluten component (protein) is filtered an d 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 proce ssed 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 fermentation process is very similar to the dry mill ethanol production process described above. A schematic of the wet milling process is shown below in Figure 1.4-3.

Figure 1.4-3. Wet Milling Process

1.4.1.3 Advanced Technologies

A number of corn ethanol plants are expl oring new technologies with the potential to increase their profits by producing higher value co-products and reducing the ethanol plants energy requirements. Dry fractionation and corn oil extraction seek to recover the oil in the corn kernel for sale in the food, feed, or biodiesel markets. Cold starch fermentation and membranes that reduce ethanol distillation energy requirements are two of several new technologies focusing on reducing the energy usage of ethanol production facilities. Finally a growing number of companies are utilizing alternative boiler fuels and/or incorporating combined heat and power (CHP) technology into their facilities to reduce to plant energy requirements, and in some cases,96 produce excess power for the grid. The advan ced technologies currently being pursed by the corn ethanol industry are descri bed in more de tail below.

Dry Fractionation

Dry fractionation is a mechanical separation of the corn kernel into its three component pieces, the germ, bran, and endosperm before fe rmentation. This separation decreases the amount of non-fermentable material sent through the process and allows each of the components to be processed sepa rately to produce new, higher-value co-p roducts. As shown in Figure 1.4-1, the germ is the small, non-fermentable part of th e 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 incr ease its protein content. The bran, or pericarp, is the protective outer covering of the kernel. The bran can be sold as cattle feed, human fiber additive, or corn fiber. It can also be burned to reduce the amount of coal or natural gas required for ethanol production. The endosperm, which contains a pproximately 98% of the starch, and is the only fermentable portion of the kernel, is sent to the fermentation vessels. Decreasing the amount of non-ferm entable materials (germ and br an) in the process has many beneficial effects, in cluding increasing the production capac ity of the plant, decreasing the energy required to dry the DGS, and potentially d ecreasing the enzyme re quirement of the plant by up to 30%.

While the production capacity of the plant increases with the addition of dry fractionation, the amount of corn used to produce a gallon of ethanol increases by approximately 2-3% due to starch loss in the fractionation process. Dry fractionation is also a capital intensive process, costing an estimated $35 million to add to an existing 100 million gallon per year ethanol plant. Dry fractionation is currently ab le 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 us e dry fractionation. Several co mpanies, including ICM, Delta-T, and POET currently offer dry fractionati on options for new or existing plants.

Corn Oil Extraction 217

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 combination of both. While the corn oil is of a lower quality and value than that produced from corn fractionation, the equipment can be easily added to existing ethanol production facilities and is relatively inexpensive. We estimate that adding corn oil extraction equipment to an existing 100 million gallon per year corn ethanol plant would cost between $5 million and $12 million, depending on the type of equipment used and the percentage of oil recovered. The starch 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 usag e of the dry fractionati on process are similarly not realized.

The oil recovered using the corn oil extraction process is distressed oi l and cannot be sold as a food grade product. Markets for this product do exist, however, as an additive to cattle feed97 or as a biodiesel feedstock. In addition to generating an additional revenue stream, extracting the corn oil has several other benefits for the etha nol producer. Because the oil is an insulator, removing it improves the heating efficiency of the DGS dryers and reduces the energy demand of the ethanol plant. Reducing the oil content of the DGS also improves its flowability and concentrates its protein content. The de-fatted DGS is potentially more marketable than DGS containing corn oil, as higher quantities may be able to be included in the diets of poultry and swine. Several ethanol producers are currently using corn oil extraction technology and have reported oil recovery rates of greater than 33%. Technology providers have indicated that in the near future they expect to be able to extract up to 75% of the oil contained in the kernel. For our economic analyses we have assumed that by 2022 ethanol production plants using oil extraction technology will be able to extract 66% of the oil in the corn.

Cold Starch Fermentation 218219

POET Biorefining, the United Stat es’ 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 wit hout 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 ener gy costs, but also releases additional starch for conversion to ethanol, increases protein content and quality of co-products, increases co-product flowability, potentially increases plant throughput, and significan tly decreases plant emi ssions. The benefits of the process include reduced energy costs, increased ethanol yields, increased nutrient quality in the distillers grains and decreased plant emissions. At least 20 POET plants currently utilize the BPXTM cold starch fermenta tion technology. According to POET, the BPXTM process, which yields 20% ethanol in fermenta tion, increases theo retical ethanol yiel ds 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 add itional benefit of the cooking process is that it sterilizes the starch slurry before fermentation, killing microorganisms and neutralizing toxins that are often contained in the corn. Without this step, the microorganisms may compete with the yeast, lowering ethanol yields. Toxins may pass through the proce ss 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

W At the time of our November 299 plant assessment. For more information, refer to Section 1.5.1.1.98 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 successfully installed in GreenField’s Ti verton, Ontario demonstration plant and are scheduled to be installed in their Chatham, On tario 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 membranes would replace the rectifier unit as well as the molecular sieves used in a conventional ethanol plant, potentially reducing the energy consumption of the ethanol dehydration pr ocess by up to 50%. Another way for these membranes to be used is to treat the ethanol/w ater vapor collected when the molecular sieve units are regenerated. This stream is us ually 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 rectifier, reducing energy consumption and increasing production rate by 20% or more. While membra ne replacement technology has the potential to significantly reduce the energy demands of an etha nol plant, they are likel y at least a couple of years from being commercially available. It is not expected that membrane replacement units would be retrofitted into existing plants due to the significant capital costs. These two factors will effectively limit the use of membrane separation units to new ethanol plants built in 2010 or later.

An alternative method of membrane replacement is to use ethanol-permeating membranes to eliminate the need for the beer column, followed by a water-selective membrane for final dehydration. Eliminating the need for the beer column as well as the rectifier and molecular sieve units would significantly reduce th e capital costs of an ethanol plant, as well as lowering the energy requirements of ethanol sepa ration. While this tec hnology 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 220

Ethanol production is a relativ ely resource-intensive proce ss that requires the use of water, electricity, and steam. In most cases , water and electricity are purchased from the municipality and steam is produced on-site using boi lers 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 ge nerator unit that produces electricity, and using waste heat to make process steam. In some cases, the generator produces excess electricity that can be sold to the grid. While the thermal energy demand for an ethanol plant using CHP technology is slightly higher than that of a conventional plant, the additional energy used is far

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.99 less than what would be require d to produce the same amount of electricity in a central power plant. The increased efficiency is due to the ab ility of the ethanol plant to effectively utilize the waste heat from the electricity generation process.

The CHP system can be owned and operated so lely by the ethanol plant, or jointly operated with the local utility company. In thes e cases it is common for the utility company to purchase the generator and to split the cost of th e generator fuel with the ethanol plant. The utility company receives th e electricity produced, while the etha nol plant uses the waste heat. These arrangements redu ce the energy costs for both parties, as well as reducing the green house gas emissions that would be produced by opera ting the generator and bo iler 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 fo r industries looking to use CHP at both the state and national level. These grant programs will likely encourage a greater adoption of CHP among ethanol producers than would have otherwise been expected. We expect 26% of ethanol plants to use CHP, either solely owned or in partnership with a local utility company.

Figure 1.4-4. Steam Boiler with Steam Turbine

Alternative Boiler Fuels

In addition to CHP (or sometimes in combination), a growing number of ethanol producers are turning to alternativ e fuel sources to re place 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 in clude biomass (wood and other organic feedstocks), co-pr oducts from the ethanol production pr ocess (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 the ethanol production process. Sending the stillage to an anaerobic digester rather than drying it and selling it as DGS would produce sufficient100 biogas to exceed the energy requirements of the ethanol production facility. Excess methane could be sold to provide an additional revenue stream, however all revenue from DGS sales would be lost. Whether or not these systems are a dopted in the future is likely to be dependent 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 tec hnology 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 Suga rcane Juice and Molasses

The production of ethanol from sugarcane juice or molasses is the least complicated method to use biomass to produce ethanol since s ugarcane contains six-car bon 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 subsequently separated by centrifugation. In ethanol production in Brazil, the sugars in the juice are fermented into ethanol by the addition of yeast. Fermentation varies from 4-12 hours, with ethanol yields ranging from 80-90%. The fermented mixture is then distilled to produce hydrous (96 % ethanol) or anhydrous ethanol (99.7 % ethanol). The production of anhydrous ethanol is done by addition of cyclohexane or by the use molecular sieves. See Figure 1.4.5 for a diagram of the sugarcane ethanol and sugar production process. 221 The production of sugar (for food and export) or ethano l depends on the supply and demand changes for both products.

Y Based on current company plants.101 Figure 1.4-5. Simplified Overview of Sugarca ne Ethanol and Sugar Production Process

In addition to ethanol, sugarcane also yields trash, bagasse, filter cake mud, and vinasse. These by-products are described below:

Trash (Leaves and Tops)

The tops, brown and green leaves of sugarcane are commonly referred to as trash. Sugarcane trash in Brazil is not currently 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 there is an increased mechanization of harvesting sugarcane. In the U.S., sugarcane trash is curre ntly mechanically harvested and delivered to the factory with stalks. The collection and use of trash at the sugarcane ethanol facility is beneficial as greater electricity can be produced and potentially sold to the grid.

Bagasse

Bagasse is the fibrous material left over after juice is extracted from the crushed stalk of the sugarcane plant. It mainly consists of hemicellulose, cellulose and lignin valued mainly for its use to produce steam for electricity. U.S. factories and other indus trial units have used bagasse mainly for steam production, but a few are producing electricity (co- generation) as well. In Brazil, most facilities are able to produce more energy than needed and have exported excess electricity to the grid. This is further discussed in Chapter 2 in the lifecycle section, as surplus electricity production displaces primarily fossil-based electricity production.

Filter Cake Mud

Filter cake is the dried, leftover solid material from precipitated mud after sugarcane juice clarification (via lime addition) at the facility. It is sometimes reapplied to sugarcane fields as a fertilizer.

Vinasse102 Vinasse is the liquid waste product from the ethanol 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 contai n descriptions of cellulosic ethanol and cellulosic diesel production technologies. Section 1.4.3.1 introduces the two primary pathways for the production of cellulosic ethanol, through biochemical and thermochemical processes while Section 1.4.3.2 discusses cellulosic diesel wh ich is produced through thermoch emical processes. We end the section with specific company desc riptions of cellulosic biofuel t echnologies and br iefly describe how they differ from generic process discussions.

1.4.3.1 Cellulosic Ethanol

Cellulosic biomass has long been recognized as a potential source of mixed sugars for fermentation to fuel ethanol. The Germans may have been one of the earliest to try commercializing a process to produce ethanol from a cellulosic feedstock, probably from wood in the late 1890s. They used dilute acid to hydrolyze the cellulose to glucose and xylose, but were able to only produce a little less than 20 gallons per ton of feedstock; they soon improved the process enough to gene rate 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. 222, 223 Although corn-grain ethanol was used in the early 20 thCentury, especially by highperformance race cars and as an additive to ra ise gasoline octane, petr oleum-derived gasoline eventually replaced it as the prim ary fuel for automobiles and light-duty trucks. From the early 1970’s and up through the present, ethanol from co rn, has been increasingl y used as a fuel; however, recently, ethanol from cellulose is being viewed with increasing interest.

Several processing options are currently available to convert cellulosic biomass into ethanol. These conversion technologies generally fall into two main categ ories: biochemical and thermochemical. Biochemical conversion refers to the fermentation of sugars liberated from the breakdown of biomass feedstock. Thermochem ical 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 th e biochemical route is that thermochemical processes can more easily convert low-carbohydrate or “non-fermentable” biomass materials such as forest and wood residues to alcohol fu els and can more readily accept a wider variety of feedstocks. 224 However, the thermochemic al process does have some drawbacks, such as tar production and clean-up gas procedures that require additional capital investment.

Since commercial production of cellulosic ethanol has not yet begun, it is unclear which process options will prove most viable or whether additional variations will emerge. At least in the near future, there have been plans to build both stand-alone biochemical and thermochemical103 ethanol processing plants. In addition, some investors are currently supporting research and development in both cellulosic processing procedures, neither choosing one conversion over the other. 225 The following subsections describe the pro cess 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 car bohydrate is starch, lignocellulosic biomass is composed mainly of cellulose (40-60 %) and hemicellulose (20- 40 %). The remainder consists of lignin, a complex polymer which serves as a stiffening and hydrophobic (waterrepelling) agent in cell walls. 226 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.

Both starch (corn grain) and cellulosic feedstocks must be hydrolyzed prior to fermentation. Structural differences at the molecular level make it far more difficult, and therefore more costly, to hydrolyze cellulosic biomass than it is to hydrolyze starch. Glucose, C 6 H 12 O 6 , the repeating monomer in both starch and ce llulose, 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 atom . For uniformity (and ease) of discussion, it is generally assumed that the first carbon atom next to the oxygen, is carbon #1; the numbering, 2- 5, continues around the ring with oxygen in the 6 th position; one of the four bonds of the fifth carbon atom is attached to the oxygen atom to complete the ring, one is attached to hydrogen atom and the fourth to a -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. Th ere are also 1,6-linked glucose branches that occur irregularly on approxi mately one in twenty-five glucose units. 227 The -OH groups on the same side of the polymer, along with the randomly attached 1,6-glucose branches, leaves starch polymers relatively weak, flexible, and able to easily wrap and twist together to form tiny granules ( e.g., common, everyday corn starch),

Cellulosic polysaccharides are in the β -conformation with the hydroxyl group on carbon #1 is positioned away from the ring, in the equatorial or β -position, which causes the -OH’s on each successive glucose monomer, added to the chain, to end up on opposite sides of the polymer. The hydroxyl groups lined up evenly and uniformly along opposite sides of each polymer strand allow intra-molecular hydrogen bonds to develop within each monomer. They also allow inter-molecular hydrogen bonds to develop between adjacent polymers to form tight, rigid, strong, mostly straight polymer bundles calle d microfibrils that act as the core constituent104 in the formation of plant cell walls that are also insoluble in water and resistant to chemical attack. The β -conformation and the resulting hydrogen bonds stabilize the glucose chair structure to help minimize the polymer’s flexibility (which hinders hydrolysis) and to add to its strength.

The second cellulosic component is called hemicellulose. It consists mainly of a random mixture of highly branched and heavily substituted five- and six-carbon rings. The five-carbon residues are usually D-xylose and L-arabinose; the six-carbon resi dues are usually D-galactose, D-glucose, and D-mannose, and uronic and acetic acid. Hemicellulose is not as rigid or strong as cellulose, but does contribute add itional strength and helps prot ect 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 deri ved principally from coniferyl al cohol by extensive condensation polymerization. Covalent ly bonded to the hemicellulo se, it is essentially a glue-like polymer that covers the cellulose and hemicellulose polymer cell walls and helps hold them together, provides additional strength, help s resist microbial decay, and perhaps most importantly, for this discussion, inhibits hydrolysis. Its molecular weight is around 10,000. 228 While both cellulose and hemicellulose contribute to the amount of fe rmentable sugars for ethanol production, lignin does not, but can be combusted to provide proce ss energy in a biochemical plant or used as feedstock to a thermochemical process. 229

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 plan t cell walls through condensation reactions. In general, condensation is a chemic al process by which two molecules are joined together to make a larger, more complex molecule, and a molecule of water is a byproduct of the reaction. In the formation of polysaccharides, and enzyme cat alyzes the reaction wherein the -OH group on carbon #1 of one monomer, or glucose residue, r eacts 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 chai n. Again, depending on the direction of the – OH group at carbon 1, it may be called an alpha (as in starch) or a be ta (as in cellulose) linkage. 230

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 sepa rate glucose monomers. During starch hydrolysis, water and water borne hydrolyzing enzymes can easily penetrate the randomly formed polymers (the tiny granular particles or bundles) in order to break the bonds to release glucose monomers. However, the cellulosic or glucan polymers formed in tightly pa cked, dense, rigid microfibrils are especially resistant to water and hydrolyzing enzymes. Xyla n, 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.105 Biochemical conversion processe s typically use dilute acid with enzymes or concentrated acid to convert cellulosic biomass to sugar fo r fermentation to ethanol . Concentrated acid hydrolysis is fairly well devel oped and is being pursued to comm ercialization in certain niche situations. For example, concentrated acid hydrolysis is suitable for feedstocks such as municipal solid wastes which have largely heterogeneous mixtures. 231 Concentrated acid hydrolysis is typically much faster than enzymatic approaches, albeit at the cost of reduced sugar yields due to undesirable side reactions. 232 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 ce llulose is expected to decline significantly as these technologies c ontinue to improve. 233

In general, steps of the biochemical proce ss include: feedstock pret reatment, hydrolysis, saccharification and fermentation, ethanol dehydra tion, and lignin recovery. Refer to Figure 1.4- 6 for an illustration of the enzymatic biochemical production process. We used NREL’s study as a guide to describe, somewhat generically, how such a process might work. Refer to the NREL technical documents for greater detail. 234,235

Figure 1.4-6. Cellulosic Ethanol Biochemical Production Process (Enzymatic )

Stage 1 – Feedsto ck Pretreatment

Lignocellulosic biomass must undergo at least some pretreatment prior to hydrolysis. During the early years of cellulosic ethanol pr oduction (e.g., 2010 to 2015) , we anticipate that106 this stage will likely occur within the facility. In the out years covered by this rule (2022) we believe that this stage may be m oved 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 pretr eated 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. 236

Physical pretreatment nearly always include s 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. 237

Chemicals are also used for pretreatment . The most common chemical pretreatment methods for cellulosic feedstocks are dilute acid, hot water, alkaline, organic solvent, ammonia, sulfur dioxide, carbon dioxide, or other chemicals to make the biomass more digestible by the

enzymes. 238,239 These chemicals cause the biomass to react quite differently. 240 For example, instead of hydrolyzing the hemicellulose (as in ac idic 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 fro m the decomposition of hemicellulose and lignin. This is important since these degradati on products can inhibit microorgani sms in the fermentation step. A well known pretreatment method that doe s not degrade biomass sugars or produce fermentation inhibitors is amm onia fiber expansion (AFEX). During AFEX, liquid ammonia is added to the cellulosic material followed by a rapid pressure release.

Each type of feedstock, whet her softwoods, corn stover or ba gasse, requires a particular combination of pretrea tment methods to optimize the yields of that feedstock, minimize the degradation of the substrate, and maximize the sugar yield. Pretreatment of cellulosic biomass in a cost-effective manner is a major challenge of cellulose-ethanol t echnology research and development. 241 For more information on feedstock considerations and their impacts on biorefining refer to the NREL report completed for the final rule. 242

Stage 2 – Pretreatment and Hydrolyzate Conditioning

NREL refers to this stage as a combination of pretreatment and hydrolysis. In their process flow diagram, the washed and sized-redu ced feed is directly heated with steam and mixed with dilute sulfuric acid. The pr ocess converts, primar ily, the hemicellulose polysaccharides xylan, mannan, arabinan and ga lactan, to produce the mixed sugars and further helps prepare the cellulose for hydrolysis. A sma ll amount of glucan in the hemicellulose and in the cellulose is converted into glucose. The rundown from the acid hydrolysis reactor is fed to a blowdown tank that subsequently feeds a filter press. The filter press produces two main streams, a filter cake and a liquid filtrate, also called hydrolyzate. The filter cake carries the107 unhydrolyzed portions of the feed (e.g., glucans) among other insolubles, while the liquid carries that part of the feed that was hydrolyzed, mainly the xyloses.

The liquid portion is neutralized to remove gypsum and other contamin ants 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 ‘S imultaneous Saccharifica tion and Fermentation’ (SSF). Saccharification, in the process we’re discussing, takes place primarily in several reactors along with other intermediate treatments such as filtering and detoxifying. Using a cellulase enzyme cocktail, saccharification of the cellulo se to glucose occurs first at an elevated temperature to take advantage of increased enzyme activity, which reduces the quantity of required enzyme as well as the reaction time.

The cellulase enzymes used to convert cellulose to sugars can be obtained in two ways. The first option is for a plant to produce it on- site. The second option requires the plant to purchase the enzymes from off-site enzyme manufact urers. Due to a joint research effort by DOE, Genencor Interna tional, and Novozymes Biotech, the cost for producti on of cellulase enzymes has been drastically re duced. Such research and development in areas of enzyme production have reduced the cost of cellulolytic enzymes by a factor of 10 to 30, down to 20 to 30 cents per gallon of ethanol produced. 243,244,245 It is estimated, however, that enzyme costs will have to be further reduced to a level comparable to those used to produce ethanol from corn grain at a cost of 3 to 4 cents per gallon of et hanol. The current challe nge 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 polysaccharide, is more easily hydrolyzed than glucan (cellulose polysaccharides), the xylose su gar is more difficult to ferment than is the glucose sugar. Different microb es 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 towa rd fermenting a higher percenta ge of xylose during the past few years. 246

Stage 3A – Consolidated Bioprocessing e.g., Simultaneous Saccharification and Fermentation (SSF)108 During the past few years, researchers have been looking for ways to combine saccharification and fermentation into a single step through the use of enzyme/microbe cocktails. If successful, we expect there could be significant capital cost savings in that fewer reactors and other support equipment and piping would be ne cessary. Also, it may be possible to reduce processing times if hydrolysis reac tions can take place simultaneous ly, rather than sequentially. Such strategies are known as consolidated bi oprocessing (CBP). CBP, however, is currently hampered by the relative inability of yeast to process recombinant cellulases (enzymes that help convert cellulose to sugars), a nd the relative lag in the develo pment of molecular biological methods to manipulate organisms th at secrete cellu lases naturally. 247

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 of about 83% water and only 5.5% ethanol; the balance of the mixture is very complex, but consists mostly of lignin. The beer column removes the dissolved 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 rectificati on column overhead that consists of about 92.5% ethanol and 7.5% water, is fed to a molecular sieve that produces a 99.5 wt.% ethanol product stream with about 0.5 wt.% water. Gasoline, a denaturant, is added to produce ethanol fuel.

Stage 5 – Lignin Recovery

Following the saccharification and fermentation of the xylan and glucan to ethanol, the lignin is gradually concentrated with other solids into a moist cake-like product that is about 48% insoluble solids. About 80% of the 48% insolubl e solids is essentially li gnin microbial cells, and other unconverted biomass remnants, (e.g., cellul ose, 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-located starch etha nol plant, or as we discuss in the following section, could be used as feedstock for a thermochemical unit.

1.4.3.1.2 Thermochemical Conversion

Thermochemical conversion involves biomass being broken down into intermediates using heat and upgraded to fuels using a combina tion of heat and pressure in the presence of catalysts. 248 Thermochemical processes include py rolysis (absence of oxygen), gasification (partial oxidation in the presence of a gasifying agent, usually air, oxygen, and/or steam), and combustion (complete oxidation) . The former two conversi on 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 renewable feedstock is used (i.e. biomass) to produce cellulosic biofuel. A thermochemical unit can al so complement a biochemical 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. 249 We discuss the gasification and pyrolysis processes below.109 Gasification

Compared to corn ethanol or biochemical cellulosic ethanol plants, the use of biomass gasification may allow for greater flexibility to utilize different biomass feedstocks at a specific plant. Mixed biomass feedstocks may be used, based on availability of long-term suppliers, seasonal availability, harvest cycle, and costs. Agricultural residue, energy crops, wood residues, and municipal solid waste are all being considered as potential feedstocks. Geographic location, availability of biomass, the existence of biomass suppliers, and costs would all likely influence the mix of biomass feedstocks utilized. The general steps of the gasification thermochemical process include: feedstock handling, gasification, gas cleanup and conditioning, fuel synthesis, and separation. Refer to Figure 1.4-7 for a schematic of the thermochemical cellulosic ethanol production process through gasification. For greater detail on the thermochemical mixedalcohols route refer to NR EL technical documentation. 250

Figure 1.4-7. Cellulosic Ethanol Thermochemical Gasification Process

Stage 1 – Feedstock Handling

The particle size requirement for a ther mochemical process is around 10-mm to 100-mm in diameter. 251 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 level required by the gasifier.110 Stage 2 – Gasification

There are two general classes of gasifiers. First, partial oxidation (POx) gasifiers (directly-heated gasifiers) use the exothermic reaction between oxygen and organics to provide the heat necessary to devolatilize biomass and to convert residual carbon-rich chars. In POx gasifiers, the heat to drive the process is generated internally within the gasifier. A disadvantage of POx gasifiers is that oxygen production is expensive and typically requires large plant sizes to improve economics.

The second general class, called indirect ga sification, uses steam gasifiers to accomplish gasification through heat transfer from a hot solid or through a heat transfer surface. Either the byproduct char and/or a portion of the product gas can be combus ted with air (external to the gasifier itself) to provide the energy required fo r gasification. Although steam gasifiers have the advantage of not requiring oxygen, most operate at low pressure and th erefore require product gas compression for downstream purifi cation and synthesi s unit operations. 252,253

There are different subcategories of gasifiers which are either directly or indirectly heated. One subcategory is te rmed a bubbling fluidized bed gasi fier and it employes a bubbling fluidized bed of inert material and the reactant (biomass) is also bubbled through the fluidized bed. A second variant is the circulating fluidized be d 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 usin g biomass as a feedstock, a second reactor is sometimes added which solely targets converting the tar to syn-gas. If the biomas feedstock is ground to a sufficiently small pa rticle 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 us ing an entrained flow gasifier is described for this example. The gasification process begins as the biomass is fed to the reactor containing a heat transfer media, such as sand, and is partially reacted with air (or oxygen) which is introduced to the bottom of the reactor. The air serves as the carrier-gas and as the oxidant for partially oxidizing the biomass to syn-gas, carbon monoxide and hydrogen. In addition to the syngas produced, char and coke are also formed. The heat for the endothermic gasification reactions is supplied by circulating heat transfer media (e.g. sythetic sand ) between the gasifier and the char combustor. The heat generated by the combustion of the char and coke heats the heat transfer media to over 1800°F. The syngas is separated from the sand and ash and sent to gas cleanup.

Stage 3 – Gas Cleanup & Conditioning

Once the biomass is gasified and converted to syngas, the syngas must be cleaned and conditioned. This raw syngas has a low to medium energy content depending on the gasifying agent and consists mainly of CO, H 2 , CO 2 , H 2 O, N 2 , and hydrocarbons. The minor components, tars, sulfur, nitrogen oxides, alkali metals, and particulates have the potential to negatively affect the syngas conversion steps. Therefore, unwanted impurities are removed in a gas cleanup step111 and the gas composition is further modified during 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” syng as is comprised of essentially CO and
H 2 . The syngas is then converted into a liquid fu el by either a catalytic process or through the use of a microorganism. The fuel producer has the choice of producing di esel 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 et hanol production, it may be economically advantageous for fuel producers to convert syngas to ethanol instead of to diesel fuel. Production of cellulosic diesel is discusse d 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 synthe sis using catalytic processes. The proposed mixed alcohol process produces a mixture of ethanol along w ith higher normal alcohol s (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 mi xed alcohol products are high in methanol, but contain a wide distribution of seve ral different alcohols. One concep t proposed in literature is to completely recycle this methanol in order to increase the production of ethanol and higher alcohols which are generally mo re valuable. This concept was modeled by NREL for the thermochemical production of ethanol for the ye ar 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 complete recycle of methanol within the process. 254 For the final rule, we worked with NREL to develop the thermochemical mixed-alcohols model for the 2015 and 2022 timeframe, as discussed in greater detail in the technical document. 255 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. 256 This combined syngas and fermentation process has the benefit of having a significantly faster processing time, on the order of minutes, as compared to the typical biochemi cal process on the order of days. 257

Stage 5 – Alcohol Separation

The liquid rundown from the low-pressure separator is dehydrat ed in vapor-phase molecular sieves, producing the dehydrated mixed al cohol feed into a meth anol/ethanol overhead stream and a mixed, higher molecular weight alc ohol bottom stream. The overhead stream is further separated into a methanol stream and an ethanol stream.

Heat & Power112 A carefully integrated conventional steam cycle produces process heat and electricity (excess electricity is e xported). Pre-heaters, steam generato rs, and super-heaters generate steam that drives turbines on compressors and el ectrical generators. Th e heat balance around a thermochemical unit or thermochemical/biochemi cal combined unit must be carefully designed and tuned in order to a void unnecessary heat losses. 258

1.4.3.2 Cellulosic Diesel

Cellulosic diesel fuel tecnologies convert ce llulosic feedstocks to diesel fuel. There could be a whole set of technol ogies which fall in this categor y including thermochemical and other chemical processes and biochemical processes.

BTL Technology

One important cellulosic diesel fuel technology is a thermoch emical process which is also termed biomass-to-liquids (B TL). Like the thermochemical ethanol pro cess described previously, the BTL process produces a syngas from biomass. However, instead of reacting the

syngas to alcohol, the syngas is fed to a Fischer-Tropsch (FT) reactor to primarily produce diesel fuel and some naphtha. 259

The BTL method removes contaminants from the gasification stream prior to the reactions that form the liquid compounds. The re sulting liquid fuel is e ssentially contaminantfree and is very similar to petrol eum-based diesel fuel – in fact, its cetane number is higher than petroleum-based diesel fuel making it somewhat better in quality. Thus it can be easily blended with or used interchangeably with petroleum-based diesel fuel.

Figure 1.4-8 is a block diagram of a BTL process. Deleted: syncas

Deleted:113 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 th ermochemical cellulosic ethanol plants described above. However, once the syngas is produced, it is then cooled producing high pressure steam, and is scrubbed to rem ove particulate matter. Impurities such as mercury, arsenic and trace metals are removed by a sulfur impregnated carbon reactor. The syngas is further treated in either a Selexol or R ectisol unit to remove hydrogen su lfide 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.

The cleaned and water-shifted syngas is sent to the FT reactor where the carbon monoxide and hydrogen are reacted over a FT catal yst. The FT catalyst is either ir on-based or cobalt-based. The c obalt catalyst is more e xpensive, although it does not require a recycle, while the less expensive iron catalyst does require a recycle. The FT reactor creates a syncrude, which is a variety of hydrocarbons that boil over a wide distillation range (a mix of heavy and light hydrocarbons). The syncrude from the FT reactor is sent to a distillation column where it is separated into various component s based on their vapor pressure , mainly liquid petroleum gas (LPG), naphtha, distillate and wax fractions. The heavier compounds are hydrocracked to maximize the production of diesel fuel. The distillate boiling compounds have high cetane and thus are of high quality for blending into diesel fuel. Conversely, the naphtha material is very low in octane thus, it would either have to be upgraded, or blended down with high octane blendstocks (i.e., ethanol), or be upgraded to a hi gher 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.114 The unreacted carbon monoxide and hydrogen an d 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. 260 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 upgrade d to hydrocarbon fuels via hydrotreating and hydrocracking processing, which re duces its total oxygen content. Some believe that pyrolysis could have a significant economic advantage over other cellulosi c 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. 261 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 produ ce one or more fuels that could qualify under RFS2, we found that it is helpful to organize them into fuel technology categories. Organizing them into categories eases the task of understanding the costs and life cycle impacts of these technologies because like technologies likely have similar cost and life cycle impacts. The simplest organization is by the fuel produced. However, we frequently found that additional subdivisions were also helpful. Table 1.4-1 provides a list of technologies, the cellulosic fuels produced and a list of many of the companies which we learned are pursuing the technology (or something very similar to the technology listed in the category).115 Table 1.4-1 List of Biofuel Categories, the Fuels Produced and the Companies Pursuing the Technologies Technology Category Fuels Produced Companies Biochemical from Corn Grain Ethanol ICM, Delta T, Broin Biochemical Cellulosic Ethanol Ethanol Abengoa, AE Fuels, Cornell Univ., Citrus Energy, DuPont/Danisco, Florida Crystals, Novenzymes, Poet, Western Biomass, ICM, Alltech/Ecofin, IOGEN, Qteros, and Raven Biofuels, BPI, New Age Energy, Universal, Fiberight, KL Energy. Thermochemical/Catalytic conversion of Cellulose Ethanol Range Fuels, Pearson Technologies, Fulcrum Bioenergy, Enerkem, and Gulf Coast Energy. Thermochemical/Biochemical conversion of Cellulose Ethanol Coskata and INEOS Bio.

Strong Acid Hydrolysis of Cellulose/Biochemical Ethanol Blue Fire, Arkenol, Pencor, Pangen, Auburn Univ., Agresti. Dilute Acid, Steam Explosion of Cellulose/Biochemical Ethanol Verenium, BP, Central Minnesota Ethanol Coop.

Consolidated Bioprocessing (one step hydrolysis and fermentation) of Cellulose/Biochemical Ethanol Mascoma

Biochemical conversion of Cellulose via carboxylic acid Ethanol, Gasoline, Jet Fuel, Diesel Fuel Terrabon, Swift Fuels, Zeachem

Thermochemical/Fischer Tropsch Diesel Fuel and Naphtha Choren, Flambeau River Biofuels, Baard, Clearfuels, Gulf Coast Energy, Rentech, TRI. Thermochemical/Fischer Tropsch DME Chemrec, New Page. Catalytic Depolymerization of Cellulose Diesel, Jet Fuel or Naphtha Cello Energy

Biochemical conversion of Cellulose Diesel, Jet Fuel or Naphtha Bell Bioenergy

Catalytic Reforming of Sugars Gasoline Virent Biochemical conversion of Sugars Diesel, Jet Fuel or Gasoline Amyris, Gevo, LS9.

Biochemial of Sugars – converted corn ethanol plants Isobutanol Gevo/ICM.

Pyrolysis of Cellulose Diesel, Jet Fuel, or Gasoline, Envergent (UOP/Ensyn), Dynamotive, Petrobras, Univ. of Mass, KIOR. Hydrotreating of Plant Oils Renewable Diesel Fuel UOP, Neste, Eni,Conoco-Phillips, Dynamic Fuels (Syntroleum/Tyson). Fatty Acid Methyl Ester (FAME) Biodiesel Many Free Fatty Acid to Biodiesel Biodiesel Endicott Production of Algae Oils via Photobioreactor or open pond Algae Oil (Biodiesel or Renewable Diesel Fuel) Solazyme, Algenol, Aurora Biofuels, Petrosun, Sapphire Energy, Livefuels, Solix, HR Biopetroleum (Cellana), XL Renewables, Petroalgae, Synthetic Genomics, GreenFuel.

Of the technologies listed above, many of th em are considered to be “second generation” biofuels or new biof uel technologies capable of meeting either the advanced biofuel or cellulosic biofuel RFS standard. The follo wing sections describe specifi c companies and the new biofuel technologies which the companies have develope d or are developing. This summary is not meant to be an unabridged list of new biofuel technologies, but ra ther a description of some of the more prominent or interesting of the new biofuel technologies th at serve to provide a sense of Deleted: ... [18]116 the technology categories listed above. Th e process technology su mmaries are based on information provided by the respec tive companies. EPA has not been able to confirm all of the information, statements, process conditions, and the process flow st eps 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 custom designed yeast cells and is modular in design and can be collocated with existing ethanol plants to produce diesel fuel and gasoline.

Amyris’s yeast cells are the key drivers of 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 cons truction of a pilot plant as well as a commercial demonstration plant in Brazil to showcase their technology. Amyris intends to convert its own sugar cane mills over with this technology starting in 2011. In 2012, Amyris expects to begin converting sugar cane mills owned by others with its sugar to hydrocarbon technology.

The diesel fuel capable of being produced from the process is compatible with the existing petroleum distribution system and provide s better storage and cold flow properties than biodiesel.

Biochemical to Diesel Fuel - Bell Bio-Energy

Bell Bio-Energy has devel oped a biochemical technology which uses genetically engineered bacteria to convert cellulosic feedst ocks directly to synthe tic 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 Department of Defense which became inte rested in this technology for providing fuels to their land and air based vehicles. The military agreed to partially fund the establishment of pilot plants at different military bases, however, of the original 7 conceived pilot plants, only one pilot plant was built at Fort Stewart in Georgia. The Fort Stewart pilot plant began operating in late 2008. Bell Bioenergy intends on starting up two demonstration plants – one associated with the University of California in Fresno, the other with the City of Atlanta. The primary output of these plants will be compost, however, these two plants are also expected to produce 1 to 2 million gallons of diesel fuel on an annual basis.

The technology works by first grinding the ce llulosic feedstock into a smaller size and then immersing the ground cellulose with bacteria into water. Th e bacteria begin to digest the cellulose after only several hours, but require 30 to 60 days to fully digest the cellulose. The117 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 str ong acid hydrolysis technology process that converts cellulosic materials into ethanol. The technology can ma ke ethanol from urban trash, rice and wheat straws, wood waste and other agricultural residues. Acid hydrolysis is the main reaction mechanism to convert cellulosic and hemicellulosic material into simple sugars such as hexose and pentose or "C6 and C5" sugars. Ferm entation of these sugars with microbes converts these sugars into ethanol. This process for conv erting cellulosic and hemicellulosic material into ethanol via acid hydrolysis and fermentation has been around fo r many decades; though it has not been economically competitive as the cost was not competitive with transport fuel made from petroleum. BlueFire’s proce ss 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 etha nol production more ec onomically attractive than older acid hydrolysis methods. Some of BlueFire’s stated improvements include a more efficient acid recovery system; higher sugar purities and concentrations; use of more efficient microbes to ferment C6 and C5 sugars into ethanol; the processes ability to use biomass feedstock’s containing silica. The BlueFire process consists of the followi ng main components; feedstock preparation; decrystallization/hydrolysis reaction; filtration of solids and liquids; separation of the acid and sugars; fermentation of the sugars and product separa tion. For product separation, ethanol effluent is separated using distillation and then dehydrated with molecular sieve technology.

BlueFire has successfu lly operated a pilot plant for six years near their headquarters in Southern California. BlueFire is in the process of building its first commercial facility which will be located in Lancaster California. As of the third quarter of 2009, BlueFire had obtained the permits to build this facility and was seeking additional funding and bids for the construction of the plant. The plant is expected to start up in 2011 or 2012 and will produce up to 3.9 million gallons of cellulosic ethanol per year from 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-Energy

The Cello-Energy process is a catalytic depolymerization technol ogy. At moderate pressure and temperature, th e Cello-Energy process catalyti cally 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 are118 polymerized to form compounds that boil in the di esel boiling range, though the process can also be adjusted to produce gasoline or jet fuel. The resulting diesel fuel meets the ASTM standards, is in the range of 50 to 55 cetane and typically contains 3 ppm of sulfur. The resulting diesel fuel has been tested in Caterpiller engines to demonstrate the viability of the fuel.

The Cello-Energy process is reported to c onvert 94% of the hydrocarbon material to diesel fuel, although a very small amount of heav ier hydrocarbons is also produced. The Cello Energy Process could be totally self-sufficient by routing 12% of the produc t 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 c ontent 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 refi neries, 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 million gallon per year commercial demonstration plant. As of late 2009, the plant is operational, however, the production volumes are still very low. Cello is working to increase the production volume of its plant. According to the company, they are currently working to resolve materials handling and processing issues that surfaced when they attempted to scale up productio n to 20 MGY from a previously operated demonstration plant. As of November 2009, they had ordered new equipment and are waiting for it to arrive and be installed which they hope d 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 Alab ama. Cello explained that they will use prefabrication techniques so that these plants can readily be constructed, shipped and installed anywhe re in the U.S.

Thermochemial/Fischer Tropsch - Choren

Choren has a technology called Carbo-V, which is a Fischer-T ropsch 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, forest ry biomass, biogenic waste and recycling substances into a synthesis gas which can be further converted to a diesel119 fuel using a Fischer-Tropsch reactor. The Carbo- V process can also be configured without the Fischer-Tropsch hydrocracking technology, so as to produce electricity, heat and power, methanol, and other chemical feedstocks.

The principal aspect of the Carbo-V Process is a three-stage gasification process consisting of low temperature gasification, hi gh temperature gasifi cation and endothermic entrained bed gasification. In the first stage, bi omass is partially oxidize d with air or oxygen at temperatures between 400 and 500 °C. This break s down the feedstock into a gas containing tar and solid carbon. In the second stage, the tar is oxidized at temper atures higher than the ash’s melting point, converting the tar into a synthesis gas. In the third stage, solid carbon is mechanically pulverized and blown into the hot gasification stream . The fluidized carbon endothermicly reacts with the gasification stream a nd is converted into a synthesis gas. In the next Fischer-Tropsch stage of the process, the sy nthesis 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 proce ss to produce primarily diesel fuel.

Choren will be building a commercial Plant in Freiberg/ Saxony Germany that is expected to be operational in 2011 or 2012. Initially, the plant will use biomass from nearby forests, the wood-processing i ndustry 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 bi ofermentation, it is not easily classifiable as either a biochemical or thermo chemical production method. Th is process requires that the biomass or carbonaceous materi al be processed to a small particle size and then it is injected into a gasifier.

The gasifier combusts any dry carboneous f eed stocks into syngas, comprised primarilyof carbon monoxide and hydrogen. The syngas produced is fermented in a reactor by microorganisms, which convert the carbon monoxide and hydrogen direc tly 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 et hanol, providing significant cost savings over current cellulosic and corn based fermentation pr oduction methods. The Coskata process is conducted at low pressures, which offers savings on capital and energy costs. A dditional energy savings can be realized by employing membrane technology to separate ethanol from the reactor decant liquid. This technology uses gravity and filtration to recover ethanol, resulting in significant savings on distillation capital and energy costs used in other cellulosic and corn based production methods. Initial ethanol production cost estimates are lower than the biochemical and thermochemical cellulosic technologies describe d in previously in Subsections 1.4.3.1 and 1.4.3.2.

For woody biomass, Coskata estimates that each ton of this feedstock would generate about 100 gallons of ethanol and small amounts of ash which woul d be burned to supply energy120 needs for the process. Corn stover is expected to provide similar et hanol 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 Wa rrenville, IL, and its larger 40,000 gallon per year pilot plant became operational in 2009 in Madi son, 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 ha s 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 vehicles. Additionally, the process can make feedstock’s that can be used to produce chemicals. The process is flexible on the types of biomass feedstock’s that can be processed. The fuel produced from the Dynamotive process is called “BioOil” and contains up to 25% water, though the water is intimately mixed and does not easily separate in to 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 catal ytic 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 Dynamoti ve process, bio oil (60-75% by weight), char (15-20% wt.) and non-condensable gases (10-20% wt.). The char produced is similar to coke and can be used as fuel by other industries while the gase s 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 dry tons of biomass a year with an energy output equivalent to 130,000 barrels of oil. The ot her of its demonstration plants is located in West Lorne Ontario, Canada. This plant starte d 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 Bi oOil production capacity between th e two plants is estimated at around 9 MGY of bioOil, but both plants are curre ntly operating at a fraction of their rated capacity. However, according to a recent press release, Dynamotive has contracts in place to supply a U.S.-based client with at least nine shipments of BioOil in 2010. Although Dynamotive has been working on a technology fo r converting its biooil to trans portation fuels, they have not announced plans for building such a facility121 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 gallons of ethanol annually. POET has expanded their production capability to include cellulosic ethanol technology. POET’s cellulosic technology will make ethanol from plant materials like corn stalks, switch grass, wood chips and refuse. In February 2007, POET was selected by DOE for an award totaling $80 million for federal funding for a commercial cellulosic ethanol plant, which will be located in Emmetsburg, Iowa. As such, POET will be one of the first to build a cellulosic plant on a commercial scale. POET’s commercial demonstration plant is projected to produce 25 million gallons per year and start up in 2011. It will make cellulosic etha nol 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 produc ed approximately 24,000 gallons in 2004 and 34,000 gallons in 2005. Production dropped dram atically in 2006 and 2007 but came back strong with 55,000 gallons in 2008. Up to th e last quarter of 2009, Iogen has produced over 127,000 gallons of ethanol from their demonstration plant.

Iogen also recently became the first cellulosic ethanol producer to sell its advanced biofuel at a retail service sta tion in Canada. Their cellulosic ethanol 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 commer cial scale plant in Prince Albert, Saskatchewan in the 2011/2012 timeframe.

KL Energy Corporation (KL Energy), thr ough 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 constructio n 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 wi ll involve the production and sale of small but commercial-quality volumes of ethanol and lignin co-product. The company’s current 2010 production goal is for WBE to generate RINs under the RFS2 program.

DuPont Danisco Cellulosic Ethanol, LLC ( DDCE), a joint venture between Dupont and Danisco, is another company pursuing biochemi cal conversion of cellulosic material into ethanol. DDCE received funding from the State of Tennessee and the University of Tennessee to build a small 0.25 MGY demonstration plant in Vonore, TN to pursue switchgrass-to -ethanol production. According to DDCE, construction co mmenced in October 2008 and the plant is now122 mechanically complete and currently undergoing start-up operations. The facility is scheduled to come online in January and the company hopes to operate at or around 50% of production capacity in 2010. According to the DDCE, the obj ective in Vonore is to validate processes and data for commercial scale-up.

Fiberight, LLC (Fiberight) is yet anothe r company pursing cellulosic ethanol from a biochemical process, but using MSW as a feedstoc k. According to Fiberight, they have been operating a pilot-scale facility in Lawrenceville, VA for three years. They have developed a proprietary process that not only fractionates MSW but biolog ically 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 c onvert it to become MSW-to-ethanol capable. According to the company, construction is curr ently underway and the goal is to bring the 2 MGY demo plant online by February or March, 2 010. Fiberight’s long-term goal is to expand the Blairstown plant to a 5-8 MGY capacity a nd build other small commercial plants around the country that could convert MSW into fuel.

Thermochemical Ethanol - Range Fuels and Enerkem

Range Fuels produces cellulosic ethanol via a two step ther mochemical process. Their technology converts biomass to syngas followe d by catalytic conver sion 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 a nd 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 add itional reaction capacity 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 recipient of a $50 million grant from DOE to build a 10 MGY woody biomass-to-ethanol plant in Pontotoc, MS. The U.S. plant is not schedul ed to come online until 2012, but Enerkem is currently building a 1.3 MGY de monstration plant in Westbury, Quebec. According to the company, plant construction in Westbury started in October 2007 and the facility is currently scheduled to come online around the middle of 2010. While it’s unclear at this time whether the123 cellulosic ethanol produced will be exported to the United States, Enerkem has expressed interest in selling its fuel commercially.

Reforming of Sugars to Gaso line - Virent Bioreforming

Virent is pursuing a process called “Biofo rming” which functions similarly as the gasoline reforming process used in the refining in dustry. While refinery-based reforming raises natural gasoline’s octane value a nd produces organic chemicals, benzene, xylene and toluene as a byproduct, Bioforming reforms bi omass-derived sugars into hy drocarbons 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 tec hnology, as production costs estimates are low in comparison to many other renewable and biom ass production pro cesses while the products are compatible with traditional petroleum stocks.

Biomass feedstocks for the Bioforming pro cess are sugar feeds, such a corn syrup, sucrose, glycerol, sorbitol, xylose, glucose, cellulose and hemi cellulose. These are primarily converted into gasoline and diesel fuel, thoug h other hydrocarbons such as jet fuel, LPG, benzene, toluene, xylene, hydroge n, natural gas can also be produced. Water is also produced, as the reforming process removes oxygen from the sugar feeds. The resulting properties and energy content of gasoline and diesel produced though ar e physically comparable to those yielded from refining industry. Variable operating costs are low because no distillation equipment is needed to separate the produced gasolin e, diesel and other hydrocarbons, as these separate naturally from the aqueous solutions generated in the refo rming process. The net energy costs are also low due to low operating pr essures and temperatures.

1.4.4 Biodiesel & Renewa ble Diesel Production

1.4.4.1 Biodiesel

Plant oils and animal fats are triglyceride s, a molecule consisting of a group of three hydrocarbon chains (saturated or olefinic) linked to a three-carbon backbone via carboxylic acid esters (see Figure 1.4-9). Biodiesel is made by removing the chains from the triglyceride molecules and adding methanol to their ends to fo rm methyl esters. Glycerin is formed as a coproduct from the three-carbon backbones that remain . For relatively pure triglycerides, such as virgin plant oils, the primary reaction is catalyzed by an alkaline pH and takes place in a stirred vessel at mild temperature and pressure conditions.124 Figure 1.4-9. Overview of biodiesel conversion process

In the case of feedstocks containing more than a few percent free fatty acids (FFAs), such as rendered fats, waste greases, or corn oil extracted after ethanol production, addition of base will result in the formation of soap, an undesira ble process contaminate when present above trace levels. To avoid this, these feed stocks must first undergo an acid pre-treatment step to esterify the FFAs before proceeding to the base-catalyzed triglyceride transesterification reaction. Feedstocks with small amounts of FFAs may be converted in a basic environment if the soaps can be removed from the fuel product.

Once the chemical conve rsions are complete, the mixture is neutralized, washed, and coproduct and unreacted alcohol and catalyst are recovered. At that point the biodiesel is subjected to quality control testing and then released for sale. Figure 1.4-10 shows a process flow diagram for a typical biodiesel pr oduction process that uses virgin plan t oil as feedstock; processes using waste fats or greases would include an acid esterification step upstream of the transesterification reactor shown here. Plants that also produ ce other oleochemicals often have distillation equipment at the end of the process capable of pur ifying the methyl esters to a high degree or separating them by molecular weight. These pl ants 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. 262 

# +

transesterification

methyl esters (biodiesel) glycerin

triglyceride 

# +

transesterification

methyl esters (biodiesel) glycerin

triglyceride

Deleted: a125 Figure 1.4-10. Schematic of typical biod iesel production from virgin plant oil

Some differences exist between large and small plants that are worth mentioning given the very wide range of plant capacities existing in this industry. Larger plants (greater than 10 million gallons per year) are more likely to employ continuous flow processes, which afford certain efficiencies of scale and steady-state operation. On the other hand, small plants (less than one million gallons per year) are most likely to produce fuel batch-by-batch, which may give them more flexibility to change feedstock types or slow output on short notice. Smaller plants are less likely to be able to afford an on-site laboratory or quality control specialist, which may cause them hardship as fuel quality standards tighten and/or are more stringently enforced. Third-party labs exist for this purpose, but they pose challenges such as significant per-test costs and multi-day turnaround times that require holdi ng of product batches until results are received.

The biodiesel production proce ss is relatively simple and ec onomical, 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 ch anges 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 comply with changing fuel quality standards, or as new plants are occasionally built to take advantage of specific market niches.Transesterification

Reactor

Acid Vegetable Oils

Methanol Catalyst (Base)

Acidulation

Separator

Acidulation

Glycerin Stripper Column Methanol Rectification Column Glycerin Product Methanol / Water Biodiesel Wash Tank Crude Biodiesel

To Methanol Storage Glycerin Methanol Water Water

Separator Gray Water

Biodiesel / Methanol Stripper Biodiesel

Methanol / Water Filter Biodiesel 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 Filter126 One such change may be an increase in distillation of biodiesel. EPA requires biodiesel to meet the ASTM D-6751 specificati on for B100 in order to be lega lly 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, st erol glucosides, and partially-converted triglycerides in the finished biodiesel. There are a variety of process parameters a biodiesel producer can adjust to reduce the levels of these compounds in the finished fuel, but one very effective way to ensure a high purity product is through distillation. At this time it is unclear to what extent distillation will be relied upon for compliance with the amended biodiesel specification. An increase in distillation would increase per-gallon energy inputs to the process significantly.

Some industry forecasts suggest animal fats and waste greases will make up an increasing share of biodiesel feedstocks due to their lower costs and lower upstream GHG impacts. Because most fats and greases c ontain significant levels of FFA s, 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 producti on process converts ve getable oils and animal fats into diesel fuel using thermal depolymerization, which is similar to hydrotreating used in petroleum refining to remove sulfur. Th e process uses hydrogen and cata lyst to remove oxygen from the triglyceride molecules in the feedstocks oils via a decarboxylation and hydro-oxygenation reaction, yielding some light petroleum products and water as co-products. The reactions can also saturate the olefin bonds in the feedstock oils, converting them to paraffins; additional steps can also be taken to isomerize a portion of the pa raffins to create fuels with varying properties. All of these reactions consume significant amounts of hydrogen. The yield of these reactions to the primary product (diesel) depends on the process conditions, as some of the carbon backbone of the oils can be cracked to naphtha and lighter products with higher severity. For our analysis we assume approximately 90% yield to diesel, with the remainder split between light fuel gas and naphtha. Figure 1.4-11 shows a flow diagra m of the primary steps of renewable diesel production.127 Figure 1.4-11. Process flow diagram of primary steps in renewable diesel production

Renewable diesel can be produced either at a stand-alone facility or within the boundaries of an existing petroleum refinery. For the stand-alone facility, feedstock is brought in and finished fuel is transported out to market. This type of facility may be co-located with a rendering facility or a chemical operation with excess hydrogen to minimize feedstock transportation and storage costs. For production within the boundaries of a refinery, the feed material may either be processed in a segregated unit (new or revamped), or co-processed with petroleum in an existing unit. In any case, the feedstock will require pre-treatment in a unit that removes contaminates such as sulfur, nitrogen, and trace metals that may poison hydrotreating catalysts.

For a period during 2007 and 2008, ConocoPhilips produced some (300-500 bbl/day) renewable diesel at their Borger, Texas, refi nery from beef tallow generated by Tyson Foods, Inc. in Amarillo, Texas. 263 In fall of 2008, Dynamic Fuels, LLC (a joint venture of Syntroleum Corp. and Tyson Foods, Inc.) announced construction of a 75 million gallon per year plant (5,000 bbl/day) in Geismar, Louisiana, that will use Tyson meat processing fats as feedstock to Syntroleum’s Bio-Synfining process. Start- up is scheduled for mid-2010, with the primary product being high-quality diesel fuel that will be fungible within the existing petroleum supply system. 264 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. 265

Syntroleum Corp was founded in 1984 and ho lds 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 favorab le 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

reactor128 They have further adapted this process to use a variety of fats and oils as feedstocks, calling it Bio-Synfining. It is this technology that will be used in the Geismar facility.

Looking internationally, the Finnish compan y 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 conver t biomass to liquid fuels using gasification. 266

Since thermochemical production of hydr ocarbon fuels from fats and biomass is a relatively new endeavor to conduc t on a commercial scale, we expect continue d innovation and fine-tuning of the technol ogy as these processes evolve from their roots in Fischer-Tropsch and petroleum hydrotreating pr ocesses. (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 i ndustry and how production might grow in the future under the RFS2 program based on our volume assumptions. The bulk of the discussion focuses on corn ethanol, im ported sugarcane-based et hanol and conventional FAME-based biodiesel, today’s most establishe d U.S. biofuel sources. However, we also discuss renewable diesel, cellu losic diesel, algae-based biodi esel and other up-and-coming second generation biofuels that ar e likely to develop during the c ourse 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 there we will discuss the availability of imported ethanol from Brazil and Caribbean Basin Initiative (CBI) countries to help meet the advanced biofuel standard. Domestic s ugarcane- and sweet sorghum-base d ethanol plants could also contribute to meeting the advanced biofuel standard in EISA. Following this discussion, we will characterize the present state of the cellulosic biofuel industry and talk about the potential timeline for commercialization based on projected industry plans and technological breakthroughs aided by state and federal grants, tax incentives, and loan guarantee programs. As part of this discussion we will de scribe our assessment of the cellulosic industry in the context of setting the standard for 2010. Finally, we will conclude our industry characterization by discussing the present state of the biomass-base d diesel industry and how we expect biodiesel production to grow in the future along with renewable diesel and algae-based biodiesel.

1.5.1 Corn Ethanol

The majority of domestic biofuel production cu rrently comes from plants processing corn and other similarly-proce ssed grains in the Midwest. Howeve r, 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. Deleted: Section Break ( Continuous ) ¶ Section Break (Continuous) Section Break (Continuous)

Deleted: biofiuel

Deleted: projected129 1.5.1.1 Historic/Current Production

The United States is currently the largest ethanol producer in the world. In 2008, the U.S. produced nine billion gallons of fuel ethanol fo r domestic consumption, the majority of which came from domestically-grown corn

. Z,268 The nation is currently on track for producing over 10 billion gallons by the end of 2009

. BB,269 Although the U.S. ethanol i ndustry has been in existence since the 1970s, it has rapidly expa nded over the past few years due to the phase-out of methyl tertiary butyl ether (MTBE ), elevated crude oil prices, state mandates and tax incentives, the introduction of the Federal Volume Ethanol Excise Tax Credit (VEETC) DD , the implementation of the existing RFS1 program EE and the new volume requirements established under EISA 270

. As shown in Figure 1.5-1, U.S. ethanol producti on has grown exponentially over the past decade.

Z Based on historical transportation ethanol use less imports reported by EIA.

BB Based on projected transportation ethanol use less imports reported by EIA.

DD On October 22, 2004, President Bush signed into law H.R. 4520, the American Jobs Creation Act of 2004 (JOBS Bill), which created the Volumetric Ethanol Excise Tax Credit (VEETC). The $0.51/gal VEETC for ethanol blender replaced the former fuel excise tax exemption, blender’s credit, and pure ethanol fuel credit. However, the Farm Bill modified the alcohol credit so that corn ethanol gets a reduced credit of $0.45/gal and cellulosic biofuel gets a credit of $1.01/gal.

EE 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. Deleted:

. 267

Deleted:

. A A

Deleted: ) CC

,

Deleted:

,
Deleted: volumes

Deleted: recently-enacted

Deleted: has

Deleted: . The 2008 Farm Bill also gives

Deleted: Both credits appear to be valid through the end of 2012.130 Figure 1.5-1. Historical Growth in U.S. Corn/Starch Ethanol Production 271

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

1 9 9 9 20 0 0 2 0 0 1 2 0 02 20 0 3 2 0 04 20 0 5 20 0 6 2 0 07 20 0 8

YearCorn/Starch Ethanol Production (Bgal)

As of November 2009 there were 180 corn/sta rch ethanol plants operating in the U.S. with a combined production capacity of approximately 12 billion gallons per year

. GG,272 This does not include idled ethanol plants , discussed later in this subsection. The majority of today’s ethanol production (91.5% by volume) is produced exclusively from corn. Another 8.3% comes from plants processing a blend of corn and/or similarly-pr ocessed grains (milo, wheat, or barley ). The remainder comes from small plants processing waste beverages or other waste sugars and starches. A summary of U.S. ethanol production by feedstock is presented in Table 1.5-1.

GG Our November 2009 corn/starch ethanol industry characterization was based on a variety of data sources including plant lists published online by the Renewable Fuels Association and Ethanol Producer Magazine, information from ethanol producer websites including press releases, and follow-up correspondence with producers. The baseline does not include ethanol plants whose primary business is industrial or food-grade ethanol production nor does it include plants that might be located in the Virgin Islands or U.S. territories. Where applicable, current/historic production levels have been used in lieu of nameplate capacities to estimate production capacity. Deleted:

. FF

Deleted: ) and less than half a percent is produced131 Table 1.5-1. Current Corn/Starch Ethanol Produc tion 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 facilities, 162 utilize dry-milling technologies and the remaining 11 plants rely on wet-milling processes. Dry mill ethanol plants grind the entire kernel and generally produce only one primary co-product: distillers’ grains with solubles (DGS). The co-product is sold wet (WDGS) or dried (DDGS) to the agricultural market as animal feed. However, there are a growing num ber of plants using front-end fractionation to produce food-grade corn oil or back-end extrac tion to produce fuel-gra de corn oil for the biodiesel industry. A company called GreenShift has corn oil extraction facilities located at five ethanol plants in Michigan, I ndiana, New York and Wisconsin

. II,273 Collectively, these facilities are designed to extract in excess of 7.3 million gallons of corn oil per year. Primafuel Solutions is another company offering corn oil extracti on technologies to make existing ethanol plants more sustainable. For more in formation on corn oil extraction and other advan ced technologies being pursued by today’s corn ethanol indus try, refer to Section 1.4.1 of the RIA

In contrast to traditional dry mill plants, wet mill facilities separate the kernel prior to processing into its component parts (germ, fiber, protein, and starch) and produce other coproducts (usually gluten feed, gluten meal, and food-grade corn oil) in addition to DGS. Wet mill plants are generally more costly to build but are larger in size on average. As such, 11.4% of the current grain ethanol production comes from the 11 wet mill facilities listed in Table 1.5-2.

II Two plants in Michigan and one in each of the other three states. All company information based on GreenShift’s Q2 2009 SEC filing. Deleted: Greenshift

Deleted: a patented and patent-pending

Deleted: technology that is currently employed

Deleted:

. HH

Deleted: previously-mentioned132 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 counterparts. These small production facilities do not require milling and operate a simpler enzymatic fermentation process. Due to their limited feedstock supplies and niche mark ets, these plants have a fr action 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.

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 relativ ely resource-intensive proce ss that requires the use of water, electricity, and steam. Steam needed to h eat the process is genera lly produced on-site or by other dedicated boilers. JJ The ethanol industry re lies primarily on natural gas. Of today’s 180

JJ Although some plants may pull steam directly from a nearby utility.133 ethanol production facilities, an estimated 152 burn natural gas KK (exclusively), three burn a combination of natural ga s and biomass, one burns natural gas and coal (although natural gas is the primary fuel), one burns a combination of natural gas, landfill bi ogas and wood, and two burn natural gas and syrup from the process. We ar e aware of 17 plants that burn coal as their primary fuel and one that burns a combination of coal and biomass

. MM274 Our research suggests that two corn ethanol plants rely on a combina tion of waste heat and natural gas and one plant does not have a boiler and relie s solely on waste heat from a nearby power plant. Overall , our research suggests that 27 online plants curren tly 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 the waste heat from power production for process steam, reducing the energy in tensity of ethanol production. NN A summary of the energy sources and CHP technology utilized by today’s etha nol plants is found in Table 1.5-4.

Table 1.5-4. Current Corn/Starch Ethanol Produc tion 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.

KK

Facilities were assumed to burn natural gas if the plant boiler fuel was unspecified or unavailable on the public domain.

MM 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.

NN For more on CHP technology, refer to Section 1.4.1.3. Deleted:

. LL

Deleted: All together

Deleted:134 During the ethanol fermentation proce ss, 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 pr ocessing industry for use in carbonated beverages and flash-freezing applications. We are currently aware of 40 fuel ethanol plants that recover CO 2 or have fac ilities in place to do so. According to Ai rgas, a leading gas di stributor, 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

. 275

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.

Figure 1.5-2. Petroleum Administration for Defense Districts

As a region, PADD 2 accounts for over 94% (or 11.3 billion gallons) of today’s estimated ethanol production capacity, as shown in Table 1.5-5.

Table 1.5-5. Current Corn/Starch Ethanol Pr oduction 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% Deleted: . But

Deleted:

. OO

Deleted: almost 10135 Leading the Midwest in ethanol production ar e Iowa, Nebraska, Illinois, Minnesota, and South Dakota. Together, these five states’ 109 etha nol plants account for over two-thirds (or about 8.2 billion gallons) of the nation’s et hanol production capacity. However, although the majority of ethanol production comes from P ADD 2, there are a growing number of plants situated outside the traditiona l Corn Belt. Our November 2009 industry assessment indicates that Arizona, California, Colorado, Georgia, Id aho, 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.

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%136 The U.S. ethanol industry is currently comp rised of a mixture of company-owned plants and locally-owned farmer coopera tives (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, compan y-owned plants account for about 80% of today’s online ethanol production capacity. 276 Furthermore, nearly 30% of th e total domestic product comes from 40 plants owned by just three different companies – POET Biorefining, Archer Daniels Midland (ADM), and Valero Renewables. For a summar y of ethanol production by company, refer to Figure 1.5-3 below.

Figure 1.5-3. Current Corn/Starch Ethanol Pro duction 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 March of 2009 when it acquired seven ethanol plants from former ethanol giant, Verasun. Th e 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

. QQ,277 However, ethanol plants are much smaller than petroleum refineries. Va lero’s smallest petroleu m refinery in Ardmore, OK has about twice the throughput of all its ethanol plants combined

. 278 Still, as obligated parties under RFS1 and RFS2, the refining industry continues to show increas ed interest in biofuels . Suncor and Murphy

QQ Valero recently announced that it has purchase agreements in place to acquire the last two Verasun plants in Linden, IN and Bloomington, OH and the former Renew Energy plant in Jefferson Junction, WI.

SS EIA’s Annual Energy Outlook 2009 – ARRA Update (Table 12). Deleted: almost

Deleted:

. PP

Deleted:

. R R137 Oil recently joined Valero as the second and th ird oil companies to purchase idled U.S. ethanol plants. Many refiners are also supporting th e development of cellulo sic biofuels and algaebased biodiesel

.

1.5.1.2 Forecasted Production Under RFS2

As highlighted earlier, domestic ethanol production is projected to grow to over 10 billion gallons in 2009. And with over 12 billion gallons of capacity online as of November 2009, ethanol production should continue to grow in 20 10, provided plants continue to produce at or above today’s production levels. In addition, despite current market conditions (i.e., poor ethanol margins), the ethanol industr y is expected to grow in the future under the RFS2 program. Although there is not a set corn ethanol requirement, EISA allows for 15 billion gallons of the 36-billion gallon renewable fuel standard to be met by conventional biofuels. We expect that corn ethanol will fulfill this requirement, provided it is more cost competitive than imported ethanol or cellulosic 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 sma ller ethanol plants that have been idled for quite some time, whereas others are in a more temporar y “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 f iled for Chapter 11 bankruptcy protection. Some corn ethanol companies have exite d the industry all together (e.g., VeraSun) whereas others are using bankruptcy as a means to protect themse lves 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 ar e projected to increase from about $80/barrel (today’s pr ice) to $116/barrel by 2022. SS As oil and gas prices rebound, we expect that the biofuels industry will as well. Since our April 2009 industry assessment used for the NPRM, at least nine corn ethanol plants have come back online.

For analysis purposes, we assumed that all 27 idled corn/starch ethanol plants would resume operations by 2022 under the RFS2 program. We also assumed that a total of 11 new ethanol plants and two expansion projects curren tly under construction or in advanced stages of planning would come online

. UU,279 This includes two large dry mill expansion projects currently

UU

Our November 2009 corn/starch ethanol industry characterization (including idled and planned plants) was based on a variety of data sources including plant lists published online by the Renewable Fuels Association and Ethanol Producer Magazine, information from ethanol producer websites including press releases, and follow-up correspondence with producers. The ethanol industry characterization 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. Deleted: , discussed in Sections 1.5.3 and 1.5.4.3

Deleted: nine

Deleted: four

Deleted: TT

Deleted:

.
Deleted: DOE-funded138 underway at existing ADM wet mill plants and two planned combination corn/cellulosic ethanol plants that received funding from DOE . While several of these proj ects 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 billio n 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. or
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.

While theoretically it only takes 12-18 m onths to build a corn ethanol plant VV , the rate at which new plant capacity comes online will be dictated by market conditions, which will in part be influenced by the RFS2 requirements. As explained in Section 1.2.2 , today’s program will create a growing demand for corn ethanol reaching 15 billion gallons by 2016 . However, it is possible that market conditions could driv e demand even higher. Whether the nation produces additional corn ethanol is uncertain and will be determined by feedstock availability/pricing, crude oil pricing, and the relative ethanol/gasoline price relationship. To measure the impacts of the proposed RFS2 program, we assumed that corn ethanol production would not exceed 15 billion gallons. We also assumed that all growth would come from new plants or plant expansion projects (in addition to idled plants being brought back online). However, it is possible that some of the required growth coul d 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 estimate 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 chee se 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.

VV

For more information on our estimated plant build rates, refer to Section 1.5. 3.4.

XX One manure biogas plant is currently idled and the other that was under construction is now on hold. Deleted:

.

Deleted: mentioned above

Deleted: proposed

Deleted: 2015

Deleted: will overcomply with the

Deleted: standard

Deleted: W W

Deleted: project

Deleted: 2.139 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 XX , one biomassfired plant, and two coal-fired ethanol plants will be added to the mix. YY Of these new and returning idled plants, we’re aware of five facilities currently planning to use CHP technology, bringing the U.S. total to 32 as shown in Table 1.5-9.

YY The two coal fired plants are the aforementioned dry mill expansion projects currently underway at existing ADM sites. 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. Deleted: aforementioned

Deleted: expansions

Deleted: wet mill corn ethanol plants.140 Table 1.5-9. Projected Near-Term Corn/Starch Ethanol Pr oduction 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 grow th 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 pr ices will likely drive a number of et hanol 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 RFS2 program, the ma jority of new ethanol production (almost 70% of added capacity) is expected to originate from PADD 2, close to where the corn is grown. However, there are a number of “destination” ethanol plants being built outside the Midwest in response to state production subsidies, retail pump incentiv es, and state mandates. A summary of the forecasted ethanol production by P ADD under the RFS2 program can be found in Table 1.5-10. Deleted: proposed

Deleted: growing141 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. Ethanol production is expected to grow in other Midwest states and there are also a growing num ber of plants that are being built outside the Corn Belt. After the proposed RFS2 program is fully implemented, we estimate that more than half of the United States will have corn/starch ethanol production

. Table 1.5-11 shows our predictions of ethanol pr oduction capacity by state from greatest to smallest

. Deleted: as shown below in142 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 are expected to be company-owned. Of the 38 plants we are expecting to be built or brought back online under the 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, e ach with over 1.5 billion gallons of annual corn ethanol production capacity. Valero Renewables is expected to be the third largest ethanol Deleted: proposed143 producer with over 1.1 billion gallons of pr oduction capacity, provided the most recent ethanol 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 Pr oduction 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 ethanol industry will look like in the near term by looking at existing et hanol plants and those planned or under construction, further analysis is needed to forecast what the etha nol 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 , projected to be $7.75/MMBTU in 2022 in the EIA 2009 Annual Energy Outlook, has many ethanol plants considering alternative fuel sources. Greater biofuel availability and potential low life cycle green house gas emissions incentives may further encourage ethanol producers to transition from fossil fuels to biomass based fuels.

As ethanol plants become more efficient and require less energy, their ability to use biofuels increases. Two of th e biggest drawbacks to using biof uels currently are handling and storage costs. Due to the lower de nsity of biofuels, as compared to coal, a larger area is required to store biomass with an equivalent heating value. Handling costs are also increased as a larger volume of fuel must be moved. These negative impacts would be less significant in an ethanol plant using less energy. Lower overall energy use would also allow the energy needs of the ethanol plant to be met entirely, or to a great er extent, by waste produc ts and locally produced Deleted: currently144 biofuels. This would greatly reduce the purchas e and transportation cost s of the biofuels. If ethanol producers do decide to make a transition to biofuels, is likely that plants currently using natural gas would transition to biogas, and those using coal would transition to 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 incr ease biofuels usage, higher fossil fuel costs and lower lifecycle green house gas em issions, are expected to increase the number of ethanol producers using combined heat and power (CHP) technol ogy. Projections for the primary feedstock and use of CHP tec hnology from 2020 to 2030 are summarized in Table 1.5-12 below.

Table 1.5-12

. 280 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 is also expected to change significantly. New technologies are expected to bot h increase the efficiency of uni ts currently used in ethanol production, as well as provide energy

- saving alternatives to conv entional production practices. Increasing energy efficiency is a priority in many ethanol plants as is can dramatically increase profitability by reducing energy costs, the second highest cost of ethanol production behind raw materials. Several groups are currently 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. The National Electrical Ma nufacturers Association’s (NEMA) premium efficiency moto rs 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 th e 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. Deleted: using

Deleted: using

Deleted: cost

Deleted:

Deleted:

. ZZ

Deleted: are

Deleted:145 Table 1.5-13

. 281 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 change s, including raw starch hydrolysis, corn fractionation, corn oil extraction, and membrane separation, are likely to be adopted to varying degrees. The degree to which they are adopted will depend on many factors, including technology availability, capital cost of implementation, energy cost savings, and co-product revenue gene ration. A description of each of these technologies, in cluding the challenges and benef its of their implementation, can be found in Section 1.4.1.3. The adoption of these technologies are expected to decrease the average thermal energy use of dry mill ethanol plants by 11.8% and to increase the average electrical energy use by 13.1%. These numbers are based on a plant that is drying 100% of its distillers’ grains with 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. Deleted:

. AA A

Deleted: projected impact of the implementation

Deleted: on ethanol production energy usage is

Deleted: usage

Deleted: usage

Deleted: distillers

Deleted: and146 Table 1.5-14

. 282 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 si gnificant role in determining the energy usage of ethanol plants is the treatment of the main co-product of the dry mill ethanol production process, distillers’ grains with solubles (DGS). The DGS, which is most often sold as feed for cattle, poultry, or swine, can be sold either dry or wet. Wet distillers’ grain with solubles (WDGS) can often only be sold locally, as it is difficult to transport and is susceptible to spoilage. Drying the DGS avoids these problems and allows the DGS to be sold in a much wider market; however drying the DGS is an energy intensive process. USDA models suggest that 40.4% of the thermal energy used in an ethanol plant that produces dry DGS is used in the drying process. Plants that do not dry their DGS, or dry only a portion of it, c ould experience energy savings up to 40.4%. According to a recent industry survey, 37% of all DGS produced by the dry mill ethanol industry is sold wet. We have assumed that this per centage remains constant through 2022 for our energy use projections.

Combining the impacts of these four factors (primary fuel sources, energy savings from efficiency improvements, new tec hnology and process cha nges, 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 proj ected primary fuel types and ener gy efficiency improvements. The next two lines adjust the totals to include new technologies and pro cess 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) CCC

.

CCC An Excel spreadsheet has been added to the docket showing the energy impact calculations of the technology improvements (EPA-HQ-OAR-2005-0161-2729 ). Deleted:

. BBB

Deleted: distillers

Deleted: and

Deleted: DGS147 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 change s 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 cas e scenario” plant. This plant was defined as a plant that used the combination of all the technologies considered that resulted in the lowest overall energy usage, as well as all the energy efficiency improvements discussed above. The technologies used by the best case scenario plant were CHP, dry fr actionation, membrane separation, and raw starch hydrolysis. Corn oil extraction was not considered as plants would have either corn oil extraction or dry fractionation but not both, and dry fractiona tion resulted in greater energy savings. Best case scenario energy usage numbers were calculated for both natural gas and co al/biomass fired plants producing both dry and wet DGS. The results are shown below.

Table 1.5-16 2022 Best Case Natural Gas Dr y 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 construction after December 19, 2007 must achieve at least a 20% reduction in lifecycle greenhouse gas emissions compared to baseline lifecycle greenhouse gas emissions in order to generate RI Ns under the proposed RFS2 program. DDD However, facilities that commenced construction before December 19, 2007 are exempt or “grandfathered” from the 20% GHG reduction requirement. In addition, facilities that commenced construction in 2008 or 2009 are grandfathered if they burn natural gas, biomass, or any combination thereof.

DDD In accordance with Section 211(o)(2)(A)(i) of the Clean Air Act as amended by EISA.148 The volume of ethanol that is grandfathered under t oday’s RFS2 rule w ill be determined based on information received dur ing the expanded registration pro cess (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 base d on our knowledge of the industry.

To do so, we started with our assessment of corn ethanol plants th at were operational, idled or under construction at the time of our November 2009 assessment. As shown in Table 1.5-7, excluding the planned facilities, this amounts to about 14.8 billion gallons of ethanol production capacity. Provided all the plants meet the definition of “commence construction” under §80.1403, the potentially grandfathered volume of ethanol falls just shy of meeting the 15 billion gallon conventional biofuel standard. However, actual baseline volumes established during registration could easily exceed 15 billion gallons. Furthermore, by allowing a 5% tolerance on the baseline volume to account for minor changes during ongoing maintenance of the facilities under §80.1403(a)(1), these plants could readily exceed 15 billion gallons of production.

Further examination suggests that all of today’s corn ethanol plants will likely be grandfathered under the RFS2 program because they are either fired with na tural gas, biomass or a combination thereof and commenced construction prior to December 31, 2009 or they burn coal but commenced construction prior to Decem ber 19, 2007. A summary of grandfathering

assessment logic we applied is found in Figure 1.5-1 . The 20 coal-fired plants we considered in greater detail are presented in Table 1.5-17. Deleted: under the RFS2 rule

Deleted: they’re

Deleted: logis

Deleted: and the

Deleted: is149 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

No150 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 Cargill c Eddyville, IA 35 1992 Chief Ethanol Fuels Inc. Hastings, NE 62 1985
Corn LP d 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 e 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 2,393

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 natural gas and coal.

d Burns a combination of coal and biomass.

e 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 c ould potentially pose a challenge w ith respect to the construction cutoff date set by EISA. These facilities, bolded in Table 1.5-17 above, include two dry-mill ADM plant expansion projects currently underway in Cedar Rapids, IA and Columbus, NE as well as Riverland Biofuels in Canton, IL and Southwest Iowa Renewable Energy in Council Bluffs, IA. However, research and 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. 283151 1.5.2 Imported Ethanol

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 European Union (EU), Japan, India, and China to determine whether each country will likely be an im porter or exporter of etha nol in the future. The following sections first describe the etha nol demands of each of these countries due to enacted or proposed mandates and goals as well as their ability to supply those demands with domestically produced ethanol. With the exception of Brazil, we show that the majority of countries analyzed could likely be importers of ethanol in the fu ture and therefore could compete with the U.S. for supplies of ethanol. We conclude our analysis by examining the most likely pathways for imported ethanol to the U.S. , 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 to tal exports escalating from under 700 million gallons in 2005 to over 1200 million gallons in 2008. As seen in Figure 1.5-6, Brazil exports ethanol to many different countries around the globe. Prior to 2006, the majority of Brazilian ethanol exports flowed to the EU and Caribbean due to favorable economics. In 2006, the majority of Brazilian etha nol exports (52%) went to the U.S as a result of the withdrawal of MTBE from the U.S. gasoline fuel pool and high oil prices . The EU, Caribbean, and U.S. have continued to be major impor ters of Brazilian ethanol in recent years. Deleted: the

Deleted: an increased price of ethanol152 Figure 1.5-6. Brazil Ethanol Exports (Includes all types of ethanol). 284,285,286



### 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 an d anhydrous ethanol. Hydrous ethanol contains 96% ethanol and 4% water by volume , whereas anhydrous ethanol is made up of 99.5% ethanol and 0.5% water. 287 While hydrous ethanol is used in Brazil directly in Otto-cycle motors ( as 100 % ethanol by volume ), anhydrous ethanol is mixed with gasoline at 20-25% by volume. Production of anhydrous ethanol to be mixed with ga soline has fallen since the 2005/2006 harvest, on account of the smaller share of ca rs running exclusively on gasoline. This was especially due to the success of flex vehicles with Brazilian customers. 288 In fact, sales of flexfuel vehicles (FFVs) in Brazil, those that can use any mixture of gasoline and ethanol from 0 to 100%, have grown dramatically, with domestic FFV sales repres enting 85% of vehicles sold between January 2009 to October 2009. 289 Hydrous ethanol account ed for 65% of ethanol produced in Brazil in 2008, and 73% of ethanol pr oduced as of December 1, 2009. Figure 1.5-7 shows the historical production of hydrous and anhydrous etha nol in Brazil. Deleted: has

Deleted: in its composition

Deleted: %

Deleted: during153 Figure 1.5-7. Historical Etha nol Production of Hydrous an d Anhydrous Ethanol in Brazil. 290

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 the U.S. must first be converted to anhydrous ethanol before it can be used in conventional or FFV vehicles. This differs from Brazil because Brazilian FFVs have been designed to use hydrous ethanol, or E100 (100% ethanol by volume ) for the conditions in Brazil, whereas U.S. FFVs can only use up to E85 (85% ethanol and 15% gasoline by volume). As a result, if hydrous ethanol is exported fro m Brazil, it must be dehydrated somewhere else before it can be used in the U.S. This is the case for the majority of ethanol exported from Brazil to the Caribbean, wh ere it is dehydrated a nd 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 increa se production. Sugarcane analyst Data gro 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. 291 Estimates of future ethanol production in Brazil vary greatly , see Figure 1.5-8. Brazil’ s government has adopted plans to meet global demand by tripling production by 2020. 292 This would mean a tota l capacity of approximately 12.7 billion gallons, to be achieved through a combination of efficiency gains, greenfield projects, and infrastructure expansions. Estimates for the required investment 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. 293 If global demand were to increase much more than Brazil is planning, th en capacity would need to expand even further and greater investment would be required. Deleted: its use

Deleted: is

Deleted: range

Deleted: . See

Deleted: required

Deleted: thus

Deleted: dollars154 Figure 1.5-8. Estimated Brazilian Ethanol Production Volumes 294



### 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. Brazil currently has nearly 400 sugar and ethanol mills, with more anti cipated over next few years. 297,298,299 Brazil’s state-owned development bank BNDES said the country is set to invest $13.1 billion between 2007 and 2011 in 89 new sugar and ethanol mills. 300 Some estimate even more, where investments in sugarcane processing factories are expected to top $23 billion over the next four years. 301 Investments 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 produce ~ 400 million gallons per year of ethanol. 302 Even U.S. ethanol producer ADM is preparing to enter the sugarcane business in Brazil. A recent quote by ADM’s senior vice president of strategy, Steve Mills, said that sugarcane ethanol is now “a key component” of ADM’s short-term strategy and, “We’re devoting a lot of time and energy to this area. We’re not talking about something 10 years down the road. It’s on the front burner.” 303

In addition to expanding su garcane production and ethanol plant capacity, Brazil will need to improve its current etha nol distribution infrastructure. Brazil’s transport system is predominantly road-based. 304 Railroad infrastructure and use of a waterway system is lacking, as well as very low availability of multi-mode terminals. Logistics represent approximately 22% of the export expenses and is one of the areas where costs need to be reduced in order for Brazilian ethanol to become more competitive abroad. 305

One way to deal with the lack of infrastructure is to expand the pipeline network. Petrobras, Brazil’s largest petroleum refiner is pla nning to build a pipeline to transport ethanol Deleted: This includes over 90 new plants (354 existing plants in 2007/2008) that will be set up in the next five

years. 295,296

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Deleted: invest in enlarging155 destined for export from the stat es of Sao Paulo, Minas Gerais, Mato Grosso, Mato Grosso do Sul, Goias, and Parana. The pipeline is an ticipated 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 ethanol . By 2011, Petrobras has the goal of exporting 920 million gallons per year. 306 One of the pipelines will run from Goias state in Brazil’s center-west to Petrobras’s Paulinia refinery in Sao Paulo State. The project is called PMCC Projetos de Transporte de Alcool. The line is expected to have the capacity to ship 3.2 million gallons of ethanol annually. 307

Other competitors include the joint venture from Cosan, Copersucar, and Crystalsev which will make initial investments of $11.5 million apiece to install an ethanol-only pipeline between the oil refinery in Paulinia, to an ethanol offloading terminal on the state’s coast. In addition, at least three major private equity groups (Infinity, Clean Energy Brazil, and Brenco) plan to invest $1 billion in a 683

- mile pipeline expected to be completed by 2011 with a capacity to deliver 1.1 million gallons of ethanol a year. In total, it is estimated that Brazil will need to invest $1 billion each year for the next 15 years in infrastructure to keep pace with capacity expansion and export demand. 308

Another area that requires investment is in R&D and education. Currently, Brazil produces only 0.08 engineers for every 1000 people, compared to 0.2 in the U

. S

. , 0.33 in the EU, and 0.8 in Korea. 309 Since certain types of educa tion require a long lead time (e.g

., scientific training) Brazil will need to continue to invest in training and professional development for the sector’s labor pool to meet the growing demand in the biofuels industry.

Before ethanol can be exported to othe r countries, Brazil’s own domestic fuel consumption must be met. Brazil currently ha s an ethanol mandate of 25%. 310 The ethanol to gasoline mix is set by the Brazilian government, which has the flexibility to adjust the ethanol mandate from 20-25% by volume

.
At some point in the future, Brazil’s light vehicle fleet may become saturated with FFVs in preference to mainly gasoline fueled vehicles . As such, the rate in domestic demand for ethanol is expected to begin to slow. 312 Thus, as domestic demand begins to level off, some experts believe that there is a significant possibility that exports will become more relevant in market share terms. Figure 1.5-9 shows various estimates for future Brazilian ethanol domestic consumption. Deleted: production

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.

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Deleted: ethanol to gas ratio. Ethanol currently represents nearly 30% of the light vehicle fuel market in Brazil. 311 ¶156 Figure 1.5-9. Estimated Brazilian Ethanol Consumption Volumes 313



### 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 met, the rest of the ethanol can be available for exports to other countries. Potential worl dwide exports basically equal the total produc tion 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 from Brazil as seen in Figure 1.5-10. Estimates from EPE and Unica indicate that as much as 3.8-4.2 billion gallons could be exported by Brazil in the 2020/2022 timeframe. Longer timeframe estimates from sugarcane analyst Datagro project international ethanol sa les to grow to 6.6 billion gallons by 2025. 314 Deleted: for157 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 largel y focused on biodiesel, ethanol has become increasingly important. Fuel ethanol demand is increasing due to the in troduction of mandatory blending targets. In 2001

, an EU Directive established 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 ha s been much less (0.5%, 0.6% and 1% in 2003, 2004, and 2005, respectively). 315

The EU is currently considering a binding ta rget requiring 10% biof uel use for transport by 2020, although the target has recently come under criticism due to concerns over deforestation and f ood security problems. 316 The International Energy Outlook (IEO) 2007 forecasts OECD European countries will consum e 159 billion gasoline gallons equivalent (gge) of transport fuel in 2010, growing to 167 gge by 2030. 317 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. EEE,318 However, this may be a slight overestimate of gasoline use sinc e 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 gaso line consumption volumes are possible by the 2020/2022 timeframe which when translated equals 5.2-5.4 billi on gallons of ethanol assuming a 10% energy requirement. 319,320

EEE Assuming energy contents 115,000 Btu/gal for gasoline and 77,930 Btu/gal for denatured ethanol and 164 gasoline gallons equivalent ( gge ) in 2022 Deleted: become

Deleted: demands are

Deleted: i.e.158 However, many believe that even 10% is unrealistic and are calling for a lower percentage for biofuels. Most recently, the EU Energy Committee (EC) has passed draft legislation that

, if approved

, is expected to forbid the EU- 27 countries from importing ethanol produced with excessive use of natural resources such as water or stimulates forest devastation. 321 As a result, Brazilian stakeholders are monitoring such potential modifications in EU biofuels policy as it will affect the potential EU demand for ethanol.

Fuel ethanol production in the EU has been much lower than mandatory targets , with less than 1 billion gallons produced historically (754 million gallons in 2008). 322 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 m eet the 10% volume requirement if only traditional crops are used. It should be note d, however, that the EU production estimates in the FAPRI Agricultural Outlook does not reflect the EC directive volume requirement since the targets were announced after the report was issued. This could s pur greater production in the EU and reduce the amount needed from et hanol exporters such as Brazil.

As of September 9, 2009, the in stalled capacity of the EU et hanol industry is 1.7 billion gallons, while 0.6 billion gallons are under construction and another 3 billion gallons has been announced. 323,324 Totaling these capacity estimates, the EU would have 5 billion gallons ethanol capacity. While not all the announced projects in the EU will be comple ted, this gives an estimate of how fast and large ethanol production in the EU could grow. If we assumed that EU could produce this volume by 2022, as much as 2 billion gallons would need to be imported from other countries assuming a 7.3 billion gallon demand due to the 10% mandate. It appears likely from the above analysis that the EU will conti nue 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. 325,326 Now the government is showing signs of encouraging biofuels production by promoting (not mandatin g) 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. 327 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. 328

With a 3% ethanol blend, ethanol trade may increase substantially with Japan (this may even reach over 1.5 billion gallons annually if a 10% ethanol blend is implemented nationwide in Japan, approximately 500 million gallons with 3% ethanol blends). 329 While the use of greater than 3% blends in Japan may be unlikely, the Ja panese government ha s mandated that all gasoline powered vehicles are able to run on 10 % blends by 2030 and may also enact legislation to require all new vehicles to be E10 compatible by 2012. 330,331 Deleted: EU

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-159 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 reveals that the Government of Japan’s (GOJ’s) current thinking, given limited agricultural resources, is to focus on cellulosic biofuel as the future for Japan’ s biofuel production. 332 The Agriculture Ministry states that Japan has enough feedstock to produce 26.4 million gallons per y ear, 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. 333 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 a nd the differences in the estimate s of domestic ethanol production.

Table 1.5-18 details select ethanol model plants and facilities in Japan. In total, there are close to a dozen ethanol facilities nationwide, how ever, details on each facility were not fully available and most are considered small-scale. The total capacity is much lower than the 132.1 million gallons of ethanol goal and further supports the argument that Japan could likely be heavily dependent on imports.

Table 1.5-18. Select Ethanol Model Plants and Facilities in Japan 334 Plant Capacity Feedstock Nippon Steel Plant 38,000 gallons/year Food waste from: supermarkets, restaurants, schools, hospitals Mitsui Engineering & Shipbuilding Co. Not available Agricultural wastes: felled oil palm trunks, empty fruit bunches, fibrous fruit wastes, kernel shells Shimizucho, public-private partnership between Mitsubishi Corp. and Hokuren 4 million gallons/year Off-spec wheat and sugarbeets

Tomakomai 4 million gallons/year Rice

Obihiro City, Hokkaido run by Tokachi Foundation Small volumes Wheat

Niigata, jointoperation with Zennoh Small volumes Rice

Historically, Japan has relied on na tions such as Brazil to supply ethanol , although it is almost all for industrial use. Imports of ethanol for transportation use are currently negligible; however, future imports may be possible from Brazil given the joint ventures established between Japanese and Brazilian firms . In early 2005, Japan and Brazil signed an agreement for a Deleted: recent

Deleted: Upcoming/Recent

Deleted: Three from Agriculture Ministry

Deleted: ~4 million

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Deleted: Hokkaido Prefectural Union of Agricultural Cooperatives

Deleted: 3.96 million gallons/year

Deleted: Sugarbeets that aren’t targeted for domestic sugar and substandard wheat unusable for food

Deleted: Nippon Steel Plant

Deleted: 104.89 gallons daily (38,285

Deleted: Food waste from: supermarkets, restaurants, schools, hospitals. (10 tons annually)

Deleted: )

Deleted: Mitsui Engineering & Shipbuilding Co.

Deleted: Agricultural wastes: felled oil palm trunks, empty fruit bunches, fibrous fruit wastes, kernel shells

Deleted: ¶160 bilateral biofuels progra m to export Brazilian ethanol and biodies el to Japan. Japan’s investment will be used to install new ethanol facilities, increase acreage of sugarcane production, and modernize the infrastructure necessary for the transportation of ethanol.

One such partnership is between Brazilian oil company

, Petrobras

, and trading house Mitsui & Co., with financial support from Japan Bank for Inte rnational Cooperation . The companies are in the process of analyzing 40 projects evaluated at $8 billion 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.” Petrobras plans to produce a total of 1 billion liters (264 million gallons) of alcohol annually at five processing plants in the states of Mato Grosso, Goias, and Minas Gerais. Each of th e 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. 335 With this amount (264 million gallons) slated for Japan only, other countries may have to either develop their own contr acts 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. 336

Another challenge is th e distribution of ethanol in Japan. As E5 and higher ethanol blends have been 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. 337 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. 338 Imports of ETBE were roughly 1.7 million gallons in 2008. 339

India

India has continued to focus on the use of non-food sources (e.g., sugar molasses) for the production of ethanol for blending with gasoline. The amount of ethanol blended into gasoline in India has fluctuated in the past few years. The government’s current target of 5% blending of ethanol with gasoline has been partially successful in years of surplus sugar production, but falters when sugar production declines. 341 Commercial production a nd marketing of ethanolblended gasoline started in Ja nuary 2003 when the Ministry of Petroleum and Natural Gas launched the first phase of the ethanol blended pe trol (EBP) program that mandated blending of 5% ethanol in gasoline in 9 states (out of a total of 28) and 4 union territori es (UT) (out of a total of 7). In 2004, ethanol blending in gasoline had to be halted because of a lower sugar output due to a drought, which increased prices. However, production started back up in late 2005 when a fuller sugarcane molasses crop became available. Then in September 2006 the government announced the second phase of the EBP that manda tes 5% blending ethanol with gasoline in 20 states and 8 union territories

. FFF The mandate was effective starting in November 2006 and

FFF The number of union territories appears to have changed since 2006. Deleted: (

Deleted: )

Deleted: for building 40 new processing plants

Deleted: ethanol in blends of

Deleted: or

Deleted: potential to increase its ethanol production due to its long agricultural tradition. However, it is still in the very young stages

Deleted: raising its biofuel industry, which leaves some analysts doubting this program’s stability. 340 Currently, India imports more than 70% of its energy needs. In addition to not being able to sustain its own current energy demands, the UN is predicting that India will become the most populated country by 2030 (surpassing China), and it will be consuming about a third of the world’s energy by 2050. ¶ ¶

Deleted: recent

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.161 would have required about 159 million gallons to be used. However, the program only started with 10 states and was not implemented in other st ates due to high state taxes, excise duties and levies.

Industry sources report that ethanol supplies for the EBP program have come to a virtual halt in most states since October 2008. 342 In fact, industry sources estimate that only 143 million gallons of ethanol have been supplied to the EBP program by the end of April 2009 during the past two and a half years . The government has had plans to extend the ethanol blend ratio to 10% in a third stage once the progr am is extended to all target states. The original plan was a minimum 10% ethanol blend by October 2008; however, this was put on hold because of the sharp fall in crude oil prices and because of tec hnical concerns raised by the Society of Indian Automobile Manufacturers (SIAM) . The main concern is that vehicles with older engines may not be able to use 10% blends without engine modifications (e.g

., two-wheelers). In December 2009, India’s government has i ndicated the urgency to kickstart the 5% blending program because the requirement of ethanol has increased to 225 million gall ons in the course of the delay in implementation (since 2006). 344 Regardless, the government announced a draft National Biofuel Policy in September 2008 to raise the blending level to 20% of total fuel usage by 2017 (includes biodiesel). 345 Industry sources expect the Nationa l Biofuel Policy ma y be reviewed again soon, however, approval by the Pa rliament may take some time.

India has about 320 distillers with a pr oduction capacity of about 925 million gallons. Due to the government’s ethanol policy, over 115 distilleries have modified their plants to include an ethanol production line, with a total production capacity of 396 million gallons per year, enough to meet the estimated demand for E5. Under an E10 mandate, however, the current ethanol production capacity would need to be enhanced.

Some oil companies are instead pushing for im ports of ethanol. However, there is an import duty of 28.64 % on the cif value for denatured ethanol. The c.i.f. (cost, insurance, and freight) value represents the landed value of the me rchandise 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 blending 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 from other countries. India’s own domestic production may grow from its current estimated production of 26 million gallons of ethanol (marketing year 2008/09) , with production capacity expanding to 396 million gallons per year.
To meet current E5 and E10 mandate s, approximately 225 million gallons to 450 million gallons per year of ethanol, respectively, is required (note that this will continue to increase as fuel demands increase) . Therefore, depending on the amount of ethanol that India chooses to mandate, India could either be an importer of ethanol or be able to meet its goals with domestically produced ethanol.

China Deleted: 145

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Deleted: will be blended with gasoline in 2006/07, compared with the original target of 145 million gallons

Deleted: Some local sources report plans to introduce E-10 mandates in several cane-producing states such as Tamil Nadu, Andhra Pradesh, and Maharashtra. 343

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.
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-

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-

Deleted: In the past, India’s largest sugar and ethanol manufacturing company (Bajaj Hindusthan) has tried to acquire ethanol production plants in other countries with large sugarcane outputs (i.e. Brazil). This way, the company can increase its ethanol production. Yet after

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Deleted: 230 million gallons of ... [19]162 China began mandating fuel ethanol blending in gasoline in June 2002. 348 In 2004, the Chinese government introduced an ethanol ma ndate of 10% (E10) in several provinces Helongjiang, Jilin, Liaoning, Henan, and Anhui. This mandate was further expanded to 27 cities in the provinces of Shandong, Jiangsu, Hebei, an d Hubei in 2006. To keep up with fuel demand, a National Plan calls for fuel ethanol production to rise from approximately 330 million gallons of ethanol per year to 660 million gallons by 2010 and 3.3 billion gallons by 2020. GGG,349

In 2008, China was the world’s fourth la rgest fuel ethanol producer, producing 502 million gallons. 350 The majority of fuel ethanol in China (about 80 %) is made from corn

. 352,353 However, concerns in China about the security of their food supply and the inflationary impact of biofuels which use grains as feedstock could influence the feedst ocks used in the future. With a population of 1.3 billion people, corn growers have to meet the demand for food while also providing feedstock for fuel. In addition, they supply livestock feed for which demand is estimated to rise. 354

In response to these food and feed demands for corn

, according to the National Development and Reform Commission (NDRC), China had stopped approvals for industrial corn processing for three years and su spended approved projects which had not yet started construction. 355 Over the next three years, corn consumption by the deep-processing sector (i.e

., transformation of corn into industrial products like ethanol) will be restricted to 26 percent of China's total corn consumption.

The National Development and Reform Co mmission (NDRC) stated in their 11 th Five Year Plan (2006-2010) that the production of approximately 2 billion gallons of grain-based ethanol will not threaten the country’s grain security. In 2005 , there were four fuel ethanol plants operating in the country which have a production capacity of approximately 300 million gallons: Jilin Fuel Alcohol Company Ltd, Anhui Fengyuan Petrochemical Ltd, Henan Tianguan Group and the Heilongjiang Huarun Jinyu Ltd (China Resources). 356,357 These plants were established after 2000 to address a surplus of grains in China at the time. Other plant expansions increased total fuel ethanol production to approximately 550 million gallons in 2007, see Table 1.5-19. Total production in 2008 was estimated at 480 million gallons. 358

Table 1.5-19. Fuel Etha nol Production in China 359

Province Company Name Feedstock 2005 Production (Gal) 2007 Production (Gal) Heilongjiang China Resources Alcohol Co. Corn 33,423,025 33,423,025 Jilin Jilin Fuel Ethanol Co. Corn 100,269,074 200,538,149 Henan Henan Tian Guan Fuel-Ethanol Co. Wheat 66,846,050 66,846,050 Anhui Anhui BBCA Biochemical Co. Corn 106,953,679 106,953,679 Guangxi China Resources Alcohol Co. Cassava 0 36,765,327 Hebei China Resources Alcohol Co. Sweet potato, corn, etc. 0 76,872,957 Hubei Tian Guan Fuel-Ethanol Co. Grains 0 33,423,025 Total 307,491,828 554,822,211

As seen in the above table, several distilleries have been looking into alternative feedstocks. 360 Examples of alternative feedstocks include sorghum, wheat, cassava, and sweet potato. These crops, however, are grown in much smaller quantities than corn . As such, if China ethanol production expands, China may have to rely on imported feedstocks

. 361

GGG Assuming a conversion of 1 million tonnes of ethanol equals 330 million gallons. Deleted: blended into

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. 351

Deleted: (which might increase about 0.22 million tons)

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.

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Deleted: Current and Future

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Deleted: , and163 China may soon become a major importer of ethanol, especially if the E10 blend is extended across the country. With a nationwide E10 blend in 2020, biofuels demand would be approximately 7.6 billion gallons of ethanol. 362 Even if the National Plan which calls for China’s domestic fuel ethanol production to reach 3.3 bil lion gallons by 2020 is met, a nationwide E10 blend would result in a s upply shortfall of a bout 4.3 billion gallons of ethanol. 363 Another study, the “World Biofuels: FAPRI 2007 Agricultural Outl ook” also indicates that China would be a net importer of ethanol in the future (out to 2016), where domestic production only reaches approximately 1 billion gallons. In addition, if only food crops are assumed to be used to produce ethanol, China is estimated to only produce 0.6 billion gallons. 364 Assuming a possible E10 mandate nationwide and the projections for domestically produced ethanol, China would need to import approximately 4.3-7.0 billion gallons of ethanol per year.

Other Countries

Although Brazil is the largest exporter of ethanol, there may still be other countries that could provide additi onal 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. 365 The North American Free Trade Agreement (NAFTA) is similar to the Caribbean Basin Initiative (CBI) in that it welcomes tariff-free ethanol imports from Canada and Mexico.

In addition, there may also be other countri es that are beginning biofuels programs and could demand smalle r volumes of ethanol in the future. We provide a list of the potentialmandates and goals for other countries below in Table 1.5-20. This list is not meant to be allinclusive, but rather a look at biofuel initiatives in other countries. Deleted: to give idea of the

Deleted: outlook164 Table 1.5-20 Potential Mandates and Goals for Various Countries 366,367,368,369,370,371

Argentina Argentine President Nestor Kirchner signed a law in February 2007 implementing tax breaks and fuel-content mandates for biofuels. The Biofuels Act includes tax breaks for companies investing in the biofuels sector and mandates 5% ethanol in gasoline by 2010. The Secretary for Agriculture estimates that the country would need 200 million liters per year of ethanol (528,000 gallons) to satisfy the E5 requirements.
Australia The Australian government has set a biofuels target of 93 Mgal by 2010 according to the 'Biofuels for Cleaner Transport' 2001 election policy. This target was never mandated in legislative form. Queensland - In early August 2006 a mandate for a minimum of 5% ethanol from December 21,
2010. New South Wales (NSW )- Beginning in September 2007, fuel supplied to wholesalers in New South Wales will be required to contain 2% ethanol. Proponents of ethanol in the region want to increase the mandate to 4% in 2009 and 10% in 2010. Australian Capital Territory (ACT) - The ACT does not plan to mandate ethanol. Generally this territory follows the policies of NSW because most of their fuel supplies are sourced from NSW.
Victoria - Biofuels target of 5% of fuel market by 2010 (106 Mgal), this includes biodiesel. South Australia - No plans to mandate of set a target for biofuels use. Northern Territory - No plans to mandate or set a target for biofuels known.
Western Australia - No plans to mandate or set a target for biofuels known. Tasmania - The alternative fuels policy is currently based on CNG use. No plans to mandate or set a target for biofuels known. Canada On June 26, 2008, the Canadian Senate passed Bill C-33, which will require the use of 5% renewable content in gasoline by 2010. Canada's Government General Michaelle Jean signed the bill after it was passed in the senate, making it official. Saskatchewan - Enacted in October 2006 a 7.5% ethanol mandate in gasoline (approximately 131 Mgal) Ontario - Enacted in January 2007 a 5% ethanol mandate in gasoline British Columbia - Bill C-16 to pass soon, 5% ethanol by 2010 to support federal plan
Alberta - Has not set its own standard as it prefers a national approach Manitoba - As of Jan. 1, 2008, 8.5% in gasoline (approximately 130 Mgal) Quebec - 5% ethanol in gasoline by 2012, expects source to be met with cellulosic ethanol production Nova Scotia - No goals for biofuels New Brunswick - No goals for biofuels Newfoundland Labrador,PIE - Interest on the East Coast, but nothing as of May 2008 North West Territories, Yukon, Nunavut - No goals for biofuels Columbia In September 2001, the Colombian Government issued Law 693, which made it mandatory to use 10% ethanol blends in gasoline in cities with populations larger than 500,000 inhabitants by the year 2008. The law went into effect in September 2005. Ethanol production, however, could not cover the entire country's demand, and thus the government established a phase-in period throughout the country for mandatory ethanol use.
Mexico There is currently no specific bio-fuels promotion program operation in Mexico. On April 26, 2007, the Mexican congress approved the Law for Promotion and Development of Biofuels (LPBD). The law, though lacking in any actual mandates, sets the state for further legislative actions on biofuels development and use.

Summary of Potential Import/Export Demands

For the main countries we have analyzed from above, there appears to be a large potential demand from the EU, Japan, I ndia, and China for imported et hanol. See Table 1.5-21 for a summary of potential import demand by 2020/2022. Total import potential demand from all these countries could range from approximately 5-15 billion ga llons. If these countries decide to meet their mandated ethanol ble nds or enact new mandates, this could greatly increase the amount that each country would demand from othe r countries. As discussed above, Brazil is only expected to export a total of 3.8-4.2 billion gallons by 2022. This is significantly below the volume we estimated that could be potentially demanded by other countries in the future. Deleted: would165 Therefore, it is likely that unless Brazil incr eases 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 c onsiders non-cellulosic biofuel pot ential. If cellulosic biofuel production develops in these countri es, it is entirely possible that the biofuel demands could be lower due to greater supplies. We briefly discus s the potential for importe d cellulosic feedstocks or biofuels in Section 1.1.2.6.

Table 1.5-21. Potential Import Demand: EU, Japan, India, and China by 2020/2022 (billion gallons). HHH Country EU Japan India China Total

Potential Domestic Production 1.5-5.0 0-0.1 0-0.4 0.6-3.3 Potential 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 0.2 n/a E10 (or 10% by energy for EU) 5.2-7.3 1.6 0.5 7.6 7% ETBE n/a 0.1 n/a n/a Potential Import Demand 0.2-5.8 0.1-1.6 0-0.5 4.3-7.0 4.6-14.9

1.5.2.2 Projected Growth Under RFS2

As long as imported ethanol is cost-competitive with gasoline, there will continue be a demand for it. As our analysis from above shows, Brazil is the only country that will likely be able to provide a significant volume of ethanol to the U.S. Accordingly, Brazil will ship ethanol to countries via the most cost-effective way.

The pathway Brazil chooses to ship ethanol will likely depend on the tariffs and taxes put in place by other nations. Specifically, the U.S. places a 54 cent tariff on all imported ethanol (as well as a 2.5 percent ad valorem tax for un-denatured ethanol and a 1.9 percent tax for denatured ethanol). A key reason for establishing a tariff was to offset a tax incentive for ethanol-blended gasoline, which is set at 45 cen ts per gallon of pure ethanol. III 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 countri es 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 Br azil. Legislation and agreements since the 1980s have waived or significantly reduced the tariff on imports fro m 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 a nd Barbuda, Aruba, Baha mas, 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. 373

HHH Ranges are calculated assumi ng the potential values fo r production and consumption

III Prior to the 2008 Farm Bill, the tax incentive was set at 54 cents per gallon Deleted: Potential for U.S. Ethanol Exports¶ ¶ Ethanol exports in the U.S. have averaged only approximately 100 million gallons per year since 2000, mostly to Canada, Mexico, and the E.U. See Figure 1.5-11. There is a trend over the past years of exporting larger quantities to fewer countries, with declining volumes to Asia and increasing volumes to the E.U. and India. Based on this historical data, it does not seem likely that volume of ethanol exports will change drastically in the future. ¶ ¶ Figure 1.5-11.¶ U.S. Ethanol Exports (includes hydrous, dehydrated, and denatured volumes). 372

0 20 40 60 80 100 120 140

2001 200 2Million Gallons

¶166 Under the Caribbean Basin Ec onomic Recovery Act (CBERA ), which created the CBI, countries in Central Am erica and the Caribbean have had dut y-free access to the United States since 1989 for ethanol produced from regional feedst ocks. Although most analysts believe there is sufficient land available fo r sugarcane production in some CBI nations, there has been insufficient economic potential to spur sugarcane planting fo r ethanol production. 374 Ethanol derived from non-regional feedstoc ks 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 Trad e Agreement with Central America and the Dominican Republic (CAFTA-DR). 375 Thus far, Costa Rica, El Salvador, Jamaica, Trinidad and Tobago, and the U.S. Virgin Islands (since 2007) are the only countries that have exported ethanol to the U.S. under the CBI quota.

Historically, the CBI nations have had little etha nol production capacity of their own but have supplemented it by importing hydrous Brazilian ethanol where it is further dehydrated before being re-expor ted to the U.S. duty-free. CBI countri es have also relied on surplus wine alcohol from France, Italy, Spain and ot her Mediterranean count ries in the past. 376 According to the United States International Trade Commission, the majority of fuel ethanol imports to the United States came through CBI countries be tween 1996 and 2003. Although CBI ethanol imports to the U.S. in 2006 totaled over 170 million gallons, imports to the U.S. from Brazil totaled 3 times that amount, or approximately 430 million gallons. This data indicates that in 2006 it was economical to import significant quantit ies 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. 377 The drawback is a loophole in the tax rules which allowed companies to import ethanol and then receive a rebate on taxes paid on the ethanol when jet fuel is sold for export within three years. The draw back considered ethanol and jet fuel as similar commodities (finished petroleum derivatives). 378,379 Most recently, however, Senate Representative Charles Grassley from Iowa included a provision into the 2008 Farm bill that ended such refunds. The provision states that “any duty paid under subheading 9901.00.50 of the Harmonized Tariff Schedule of the United States on im ports of ethyl alcohol or a mi xture of ethyl alcohol may not be refunded if the expor ted article upon which a drawback cl aim is based does not contain ethyl alcohol or a mixture of ethyl alcohol.” 380 The provision became effective on or after October 1, 2008 and companies have until October 1, 2010 to apply for a duty drawback on prior transactions. With the loophole closed, it is anticip ated that there may be less ethanol directly exported from Brazil in the future. 381

CBI countries have not yet exceeded the ta riff 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 percen t of the TRQ used, has ranged from 22-77% between 1990 and 2009 . See Figure 1.5-12. Thus, there is still considerable room for growth in CBI imported ethanol. Deleted: 2008167 Figure 1.5-12. U.S. Fuel Ethanol CBERA TRQ, 1990- 2009*



### 0 100 200 300 400 500 600 7001990199219941996199820002002200420062008Million Gallons 

### TRQ Used TRQ Available

*TRQ Used data for 2009 is preliminary , TRQ Available in 2010 is 739.8

.
In October 2003, the California Energy Commission (CEC) reporte d four active CBI ethanol dehydration plants, two in Jamaica, one in Costa Rica, and one in El Salvador. At the time, CEC concluded that reprocessing capacity was the limiting factor on CBI imports, with a total of 90 million gallons per year. 382 Since then, several companies have expanded plants or announced new plants as described below:

• Jamaica - In 2005, Petrojam Ethanol Limited (PEL), upg raded 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 plan t is based on a marketing agreement with the Brazilian company, Coimex Trading, where the feedstock - hydrous ethanol is supplied from Brazil

. 383

, 384 Jamaica Broilers Gr oup (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. 385 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. 386 Deleted: 2008 ¶

Deleted: not yet available

Deleted: 621.5 million gallons168 • El Salvador and Panama - In 2004, it was reported that Cargill and Chevron Texaco had announced plans to construct ne w dehydration plants in El Sa lvador and Panama. These plants could produce 60 million gallons per year and between 50 and 100 million gallons per year, respectively. 387 Plants currently in operation 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. 388

• Trinidad - EthylChem Inc. has reported plans to bu ild an ethanol dehy dration operation at the Petrotrin Refinery in Point-a-Pierre, a southern port city in Trinidad. The plant will dehydrate ethanol at a capacity of 100 million gallons per year and is expected to be complete between Marc h and April of 2007. 389 The cost to build the plant is estimated at $20 million. 390 It is probable, however, that not al l the ethanol would be exclusively for U.S. consumption. According to Ron White, the executive director of Ethylchem, "While EthylChem intends to export the fuel to the United States the company is examining the possibility of shipping the product to other markets in the world". 391 Another company, Angostura Ltd., started pr ocessing ethanol in 2005. 392 The plant has an overall capacity of 100 million gallons per year, with 50 million gallons per year in the first phase. 393

• Others - An idled ethanol plant in Haiti has attracted some investors and there are also projects in the works in Guyana, the Domi nican Republic and Aruba. The U.S. Virgin Islands has one plant dehydrating ethanol at 100 million gallons per year capacity (Geonet). 394 A new ethanol dehydration plant is propos ed to be built at the Bulk Terminal Facility near Spring Garden Highway in Barbados, with construction expected to commence by the end of 2008. 395 There is a proposal to build a US$36 million ethanol plant near Bridgetown, Barbados. The plant is expected to produce about 132 million gallons by refining et hanol imported from Brazil. 396

In total, current fuel ethanol plant capac ity for dehydration in the Caribbean is 500 million gallons per year. Plans to expand total approximately 200 million gallons. 397 This means that there could be 700 million gallons per year of fuel ethanol capacity in the next few

years.

Some stakeholders, however, ha ve expressed concer n that the CBI countries are not as stable for investment. Both Brazilian ethanol and European wine alcohol are susceptible to factors including availability, price fluctuations, trade regulations, currency movements and freight rates. Availability of European surplus wine alcohol has diminished since the World Trade Organization (WTO) placed limitations on export subsidies and ha s found new markets in Spain and Sweden. 398 CBI countries also need to compete for Brazilian ethanol. For example, Angostura’s ethanol subsidiary, Trinidad Bulk Tr aders Ltd., was not profitable in 2006 because it could not get enough fuel from Brazil. 399

There are other prohibitive factors to CBI ethanol production that exist. For instance, many of the CBI countries have no oil, natural gas or coal. Permitting is often a huge challenge and fresh water is typically scarce. 400

In addition, increasing significantly be yond the 7% limit may be challenging. Few Caribbean countries are in a position to produ ce ethanol from domestic feedstocks such as sugarcane. Currently, all three plants exist in Central America (CATSA in Costa Rica, Pantleon169 Group in Guatemala, and Pellas Group in Nicaragua). Capacity for each plant is approximately 10 million gallons per year. The majority of this domestic fuel ethanol is shipped to the EU for fuel use rather than US due to higher opportunity prices and similar tariff free treatment. 401 In addition, the governments of Trinidad, St. Kitts and Barbados have already decided the sugar sectors of their islands are not worth further investment. Rum distillers such as Trinidad’s Angostura and Jamaica’s Appleton Ltd. have also had to import molasses from Fiji for their spirits. 402 Thus, it may take years before Caribbean countries are able to domestically produce large volumes of ethanol. As noted above, however , as dehydration capacity gets close to the US CBI quota, processors will need to consider blending indigenous ethanol.

As a result of the economic benefit of shipping etha nol 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 cont rol case), then approximately 1.21 Bgal of ethanol could enter the U.S. through CBI countries. JJJ 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 st andard after accounting for the volume s from cellulosic biofuel, biodiesel, and renewable diesel.

Table 1.5-22. Projected Contribution of Ethanol from CBI Countries and Direct Brazilian exports in 2022 (billion gallons)

Ethanol From CBI Countries Ethanol Directly From Brazil Total Imported Ethanol

1.21 1.03 2.24

The amount of Brazilian ethanol available for direct shipment to the U.S. will be dependent on the biofuels mandates and goals set by other foreig n countries (i.e., the EU, Japan, India, and China). Our estimates show that there could be a poten tial 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 producti on capacity. Therefore, unless Brazil or other countries increase biofuels produc tion 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 produ ced in the United Stat es comes from plants processing first-generati on feedstocks like corn, plant oils, suga rcane, etc. Non-edible cellulosic

JJJ 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).170 feedstocks have the potential to greatly expand bi ofuel production, both volumetrically and geographically. Research and development on cell ulosic biofuel technologi es has exploded over the last few years, and plants to commercia lize a number of these t echnologies are already beginning to materialize. The $1.01/gallon tax cred it for cellulosic biofuel that was introduced in the 2008 Farm Bill and recently became effective, is also offering much incentive to this developing industry. In addition to today’s RFS2 program which sets aggressive goals for cellulosic biofuel production, the Department of Energy (DOE), Department of Agriculture (USDA), Department of Defense (DOD) and state ag encies are helping to spur industry growth.

1.5.3.1 Current State of the Industry171 There are a growing number of biofuel producers, biotechnology companies, universities and research institutes, start-up companies as well as refiners investigating cellulosic biofuel production. The industry is currently pursu ing 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 hydrocarbons like gasoline, diesel and jet fuel as “drop in” petroleum replacements. Some companies intend to star t 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 with fuel production capabilities, pilot plants, demonstration plants, as well as commercial demonstration plants

. KKK 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

. LLL However, we will continue to track these companies during future cellulosic biofuel assessments.

Regardless of their size, the main focus at these facilities is research and development, not commercial production. As shown below, most of the plants are rated at less than 250,000 gallons of cellulosic biofuel per ye ar and that’s if they were opera ted 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.

KKK Based on research of information available on the public domain and follow-up correspondence with cellulosic biofuel companies.

LLL

Both Amyris and ICM have received funding from DOE to further their cellulosic biofuel efforts. On January 29, 2008, DOE announced that it had awarded ICM a $40 million grant to help build a small cellulosic ethanol plant at an existing corn ethanol plant in St. Joseph, MO. The company is currently piloting butanol production from corn with Gevo. On December 4, 2009, DOE awarded ICM with another $25 million to further cellulosic ethanol production at the St. Joseph plant. In the same announcement, DOE awarded Amyris with $25 million to help further cellulosic research efforts at its pilot plant in Emmeryville, CA. Deleted:

.

Deleted:

.
Deleted: for172Table 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 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.cCellulosic feedstocks. 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 at this time.Cell.Tech.bOnlineDateMax Cap(MGY)PlantTypeaPlant LocationCell.BiofuelCell. FeedstockscFormatted:Left: 1.42", Right:1.42", Bottom: 0.5"Deleted:¶Abengoa Bioenergy CorporationdAE BiofuelsArkenol Technology CenterAuburn University / MasadaChemrec & WeyerhaeuserClearFuels / Hawaii Natural EnergCobalt BiofuelsCornell University Biofuels ReseaCoskataeCoskataeDOE National Renewable EnergyEnerkemFiberightfFulcrum Bioenergy - Turning PoinGulf Coast EnergyINEOS Bio (formerly BRI)eIogen CorporationIogen CorporationKL Energy Corp / WBELignol EnergyMascoma CorporationPan Gen Global (formerly ColusaPearson Technologies Inc.POET Project BelldPureVision Technology, Inc.fRange Fuels K2A Optimization PlSunOpta BioProcess Inc.VereniumVereniumCompany/Plant NameaPDU = Process development unit, Pilot =bConversion technology. Bio = BiochemiccFeedstocks. AR = Ag residues, EC = EnedCellulosic ethanol plant is co-located withePlant also processes non-cellulosic/renewfPlant is not currently operational and/orp173Table 1.5-24. Current Cellulosic Hydrocarbon Fuel & Pyrolysis Oil PlantsAR EC W UWBell Bio-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 XCell. FeedstockscCompany/Plant NameaPDU = Process development unit, Pilot = pilot-scale plant, Demo (C) = Commercial demonstration plant.bConversion technology. Bio = Biochemical, Cat = Catalytic depolymerization, Thermo = Thermochemical.cCellulosic feedstocks. 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 at this time.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.BiofuelFormatted:Keep lines togetherDeleted:¶Cello EnergydCello EnergydClearfuels / RentecheDynamotiveDynamotive / Evolution BiofuelsTerrabon Advanced Biofuels ReseThermoChem Recovery InternatioCompany/Plant NameaPDU = Process development unit, Pilot =bConversion technology. Bio = BiochemiccFeedstocks. AR = Ag residues, EC = EnedPlant is not currently operational and/orpeCurrently in the process of expanding natuSection Break (Next Page)174 As shown in Tables 1.5-23 and 1.5-24, today’ s cellulosic biofuel plants are run by a combination of academic, government, and private organizations. Some of the privately-owned companies are existing biofuel pr oducers, but many are start-up co mpanies 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 ). 403

As indicated above, a variety of feedstocks are being investigated for cellulosic biofuel production. There is a great deal of interest in urban waste (MSW and C& D debris) because it is virtually free and abundant in many parts of the country, including large metropolitan areas where the bulk of fuel is consumed. There is also a lot of interest in agricultural residues (corn stover, rice and other cereal stra ws) and wood (forest thinnings, wood chips, pulp and paper mill waste, and yard waste). However, researchers are still working to find viable harvesting and storage solutions. Others are investigating the possibility of growing dedicated energy crops for cellulosic biofuel production, e. g., switchgrass, energy cane, sorghum, poplar, miscanthus and other fast-growing trees. While these crops have tremendous potential, many are starting with the feedstocks that are available today with the mentality that once the industry has proven itself, it will be easier to secure growing contracts and start producing energy crops. For more information on cellulosic feedstock availability, refer to Section 1.1.2.

The industry is also pursuing a number of different cellulosic c onversion technologies and biofuels. Most of the te chnologies fall into one of tw o categories: biochemical or thermochemical. Bioche mical conversion 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 synthesi s 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 ar e 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 technologies, refer 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 requi red 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 sta ndard as part of this final rule.

Setting the cellulosic biofuel standard for 2010 represents a unique challenge. As discussed above, the industry is currently characterized by a wide range of companies mostly focused on research, development, demonstration, and fi nancing their developi ng technologies. In addition, while we are finaliz ing a requirement that producers a nd importers of renewable fuel Deleted: ).

Deleted: wood chips,

Deleted: conversion

Deleted: ¶ ¶175 provide us with production outlook reports detaili ng future supply estimates (refer to §80.1449), we do not have the benefit of this valuable cellulosic supply information for setting the 2010 standard. Finally, since today’s cellulosic biofuel produc tion potential is relativ ely 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 possible to uphold the 100 million gallon standard in 2010 based on anticipated production. At the time of our April 2009 NPRM assessment, we were aware of a handful of small pilot and 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 dieselplant in Bay Minette, AL. EPA staff visited the facility twice in 2009 to confirm that the first-ofits-kind commercial plant was mechanically comp lete and poised to produ ce cellulosic biofuel. It was assumed that start-up operations would go as planned and that the facility would be operating at full capacity by the end of 2009 and that three more 50 MGY 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 completing construction of its first 10 MG Y phase by the end of 2009 and beginning production in 2010.

Since our April 2009 industry assessment there have been a number of changes and delays in production plans due to technological, co ntractual, financial a nd other reasons. Cello Energy and Range Fuels have de layed 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 Ri ver Biofuels, and ZeaChem. Alltech/Ecofin and RSE Pulp & Chemical, two companies thatwere 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 Bio -Energy , a company that received DOD funding has since abandoned plans to build additional cellulosic diesel plants at U.S. military bases. MMM

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

MMM Bell Bio -Energy is currently investigating other location for turning MSW into diesel fuel.according to October 14, 2009 conversation with JC Bell. Deleted: complete

Deleted: begin

Deleted: energy

Deleted: energy

Deleted: generated by the State of California.

Deleted: ¶ ¶176 EPA with their first cellulo sic biofuel supply estimate required under CAA section 211(o)(7)(D)(i). In a letter to the Administrato r 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

. 404 A summary of the plants they considered is shown below in Table 1.5-25.

Table 1.5-25. EIA’s Projected Cellulosic Biofuel Plant Production Capacities for 2010

Online Company Location Product Capacity (million gallons) Expected Utilization (%) Production (million gallons) 3 2007 KL Process Design Upton, WY Ethanol 1.5 10 0.15 2008 Verenium Jennings, LA Ethanol 1.4 10 0.14 2008 Terrabon Bryan, TX Bio-Crude 0.93 10 0.09 2010 Zeachem Boardman, OR Ethanol 1.5 10 0.15 2010 Cello Energy Bay Minette, AL Diesel 20.0 10 1 2.00 2010 Range Fuels Soperton, GA Ethanol 5.0 2 50 2.5 Total 30.35 5.04 Notes: 1. Cello Energy is assigned a 10-percent utilization factor as they have not been able to run on a continuous basis long enough to apply for a Synthetic Minor Operating Permit or produce significant amounts of fuel during 2009. 2. It is estimated that only half the 2010 projected capacity (10 million gallons per year) will be a qualified fuel. 3. The production from these facilities in 2009 is not surveyed by EIA or EPA.

In addition to receiving EIA’s information and coordinating with them and other offices in DOE, we have initiated meetings and conversations with over 30 up-and-coming advanced biofuel companies to verify publicly available information, obtain confidential business information, and better assess the near-term cellulosic biof uel production potential for use in setting the 2010 standard. What we have found is that the cellulosic biofuel landscape has continued to evolve. Based on information obtained, not onl y do we project significantly different production volumes on a company-by-compa ny basis, but the list of potential producers of cellulosic biofuel for 2010 is also significantly di fferent than that identified by EIA.

Overall, our industry assessment suggests that it is difficult to rely on commercial production from small pilot or demonstration level plants. The primary purpose of these facilities is to prove that a technology works and demonstrate to investors that the process is capable of being scaled up to support a larger co mmercial plant. Small plants are cheaper to build to demonstrate a technology than larger plants, but the operating costs ($/gal) are high due to their small scale. As a result, it’s not ec onomical for most of thes e facilities to operate continuously. Most of these plants are regularly s hut 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 biofue l available for commercial sale. Deleted:

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Deleted: ¶ ¶177 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 cellulosic ethanol plant in Upton, WY. This plant was considered by EIA and is included in their final plant summary presented in Table 1.5-25. The second is Iogen’s cellulosic ethanol plant in Ottawa, Canada with a 0.5 MGY capacity. Iogen’s commercial 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, th ere 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 plant in Canada. Cello Energy’s plant in Bay Minette, AL continues to offer additiona l potential for cellulosic biofuel in 2010. And finally, Dynamotive, a company that currently has two bi omass-based pyrolysis oi l production plants in Canada is another potential s ource of cellulosic biofuel in 2010. All seven aforementioned companies are discussed in greater detail below along with Range Fuels.

KL Energy Corporation (KL Energy), thr ough its majority-owned Western Biomass Energy, LLC (WBE) located in Upton, WY, is designed to convert wood products and wood waste products into ethanol. Since the end of construction in September 2007, equipment commissioning and process revisi ons continued until the Octobe r 2009 startup. The plant was built as a 1.5 MGY demonstration plant and was designed to both facilitate research and operate commercially. It is KL Energy’s intent that WBE’s future use will involve the production and sale of small but commercial-quality volumes of ethanol and lignin co-product. The company’s current 2010 goal is for WBE to gene rate RINs under the RFS2 program

. OOO

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 st rong with 55,000 gallons in 2008. Iogen recently produced over 150 ,000 gallons of ethanol from the demons tration plant in 2009. Iogen also recently became the first cellulosic ethanol producer to sell its advanced biofuel at a retail service station in Canada. Th eir cellulosic ethanol was blended to make E10 available for sale to consumers at an Ottawa Shell station. Iogen also recently announced plans to build its first commercial scale plant in Prin ce Albert, Saskatchewan in th e 2011/2012 timeframe. Based on the company’s location and operating status, Iogen certainly has the potential to participate in the RFS2 program. However, at this time, we ar e not expecting them to import any cellulosic ethanol into the U.S. in 2010. PPP

OOO Based on information provided from Lori Litzen, Environmental Permit Engineer at KL Energy on December 10, 2009.

PPP Based on website information, comments submitted in response to our proposal

, and follow-up phone call with Iogen Executive VP, Jeff Passmore on December 17, 2009. Deleted: Bay Minette, AL

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Deleted: ¶ ¶178 DuPont Danisco Cellulosic Ethanol, LLC (DDCE), a joint venture between Dupont and Danisco, is another potential source for cellulo sic 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 mechanically complete and currently undergoing start-up operations. The facility is scheduled to come online in January and the company hopes to operate at or around 50% of production capacity in 2010. According to the DDCE, the objective in Vonore is to va lidate processes and datafor commercial scaleup, not to make profits. However, the compan y does plan to sell the cellulosic ethanol it produces. QQQ

Enerkem is another company pursuing cellu losic ethanol production. The Canadianbased company was recently announced as a recipient of a $50 million grant from DOE to build a 10 MGY woody biomass-to-ethanol plant in Pontotoc, MS

. 405 The U.S. plant is not scheduled to come online until 2012, but Enerkem is currently building a 1.3 MGY demonstration plant in Westbury, Quebec. According to the company, plant construction in Westbury started in October 2007 and the facility is currently scheduled to come online around the middle of 2010. While it’s unclear at this time whether the cellu losic ethanol produced w ill be exported to the United States, Enerkem has expressed interest in selling its fuel commercially

. RRR

Additional cellulosic biofuel could come fro m 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 bi ofuel production plans. According to Fiberight, they have been operating a pilot-scale facility in Lawrenceville, VA for three years. They have developed a proprietary process that not only fractionates MSW but biolog ically 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 c onvert it to become MSW-to-ethanol capable. According to the company, construction is curr ently underway and the goal is to bring the 2 MGY demonstration plant online by February or March, 2010. If the plant starts up according to plan, the company intends on making cellulosic ethanol commercially available in 2010 and generating RINS under the RFS2 program. Fi beright’s long-term goal is to expand the Blairstown plant to a 5-8 MGY capacity and bui ld other small commercial plants around the country that could convert MSW into fuel

. SSS

Cello Energy, a company considered in the proposal, continues to be another viable source for cellulosic biofuel in 2010. Despite r ecent legal issues whic h 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

QQQ Based on a December 16, 2009 telephone conversation with DDCE Director of Corporate Communications, Jennifer Hutchins and follow-up e-mail correspondence.

RRR Based on an October 14, 2009 meeting with Enerkem and follow-up telephone conversation with VP of Government Affairs, Marie-Helene Labrie on December 14, 2009.

SSS Based on a December 15, 2009 telephone conversation with Fiberight CEO, Craig Stuart-Paul and follow-up email correspondence. Deleted:

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Deleted: ¶ ¶179 and installed which they hoped would allow for opera tions to be restarted as early as February or March, 2010. Cello’s other planned commercial facilities are currently on hold until the Bay Minette plant is operational

. TTT

Another potential supplier of cellulosi c biofuel is Dynamotive Energy Systems (Dynamotive) headquartered in Vancouver, Cana da. 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 industrial applications . The BioOil production capacity between the two plants is estimated at around 9 MGY, but both plants are currently operating at a fraction of their rated capacity. UUU However, according to a recent press release, Dynamotive has contracts in place to supply a U.S.-based client with at least nine shipments of BioOil in 2010. If Dynamotive’s BioOil is used as heating oil or upgraded to transportation fuel, it could potentially count towards meeting the ce llulosic biofuel 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 meth anol catalyst they are not expected to produce qualifying renewable fuel in 2010 . During phase two of their project, currently slated for mid2012, Range plans to expand production at the Soperton plant and transition from a methanol to a mixed alcohol catalyst. This will allow for a greater alcohol production potential as well as a greater cellulosic biof uel production potential

. VVV

Overall, our most recent industry assessment suggests that there are six companies that could potentially produce cellulosic biofuel next year. Together these seven plants, summarized in Table 1.5-26, could have over 30 MGY of 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 explai ned in more detail below.

TTT Based on a November 9, 2009 telephone conversation with Cello Energy CEO, Jack Boykin.

UUU According to Dynamotive’s website, the Guelph plant has a capacity to convert 200 tonnes of biomass into BioOil per day. If all modules are fully operational, the plant has the ability to process 66,000 dry tons of biomass per year with an energy output equivalent to 130,000 barrels of oil. The West Lorne plant has a capacity to convert130 tonnes of biomass into BioOil per day (which, if proportional to the Guelph plant, translates to an energyequivalent 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. Dynamotive was unable to be reached for comment.

VVV Based on a November 5, 2009 telephone conversation with Range Fuels VP of Government Affairs, Bill Schafer. Formatted: Font color: Auto Deleted: facility

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Deleted: ¶ ¶180Table 1.5-26EPA’s Cellulosic Biofuel Plant Assessment – ProjectedPlants/Capacity Online by End of 2010Cello Energy Bay Minette, AL Demo (C) 20.00 Currently Off-Line Mar-10 Diesel Wood chips, hayDuPont Danisco (DDCE) Vonore, TN Demo 0.25 Undergoing Start-Up Jan-10 Ethanol Corn cobs then switchgrassDynamotive West Lorne (CAN) Demo (C) 3.55 On-Line Py Oil Waste woodDynamotive Guelph (CAN) Demo (C) 5.46 On-Line Py Oil Waste wood, wood chipsEnerkem Westbury (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 FeedstocksCell.BiofuelPlant LocationOperationalStatusProj. Op.DateDeleted:¶¶Formatted:Centered181 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 contingent upon when and if these plants come online and whether the projects get delayed due to funding or other reasons. In addition, based on our discussions with the developing i ndustry, it is clear that we ca nnot count on demonstration plants to produce at or near capacity in 2010, or in thei r 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 achiev able. We currently estimate that production from first-of-it’s kind plants could be somewhere in the 25-50% range in 2010. Together, the implementation timelines and anticipated production levels of the plants described above brings the cellulosic biofuel supply estimate to somewhere in the 6-13 million gallon range for 2010.

In addition, it is unclear how much was can rely on Canadian plants for cellulosic biofuel in 2010. Although we currently receive some conventional biof uels imports from Canada and many of the aforementioned Canadian companies have U.S. markets in mind, the country also has its own renewable fuel initiatives that coul d keep much of the cellulosic biofuel produced from coming to the United States, e.g., Iogen. Finally, 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 detailed registration in formation. Factoring in these considerations, the cellulosic biofuel potential from the seven plants summarized in Table 1.5-26 could result in several different produc tion scenarios in the neighborhood of the recent EIA estimate. We believe this estimate of 5 million gallons or 6.5 ethanol-equivalent million gallons represents a reasonable yet achievable level for the cellulosic biofuel standard in 2010 considering the degree of uncertainty involved with setting the standard for the first year. As mentioned earlier, we believe standard setting will be easier in future years once the industry matures, we start receiving production outlook reports and there is less uncertainty regarding feasibility of cellulosic biofuel production.

1.5.3.3 Current Outlook for 2011 and Beyond

Since the proposal, we have also learned about a number of othe r cellulosic biofuel projects in addition to those described above. This includes commercial U.S. production plans by Coskata, Enerkem and Vercipia. However, pr oduction isn’t slated to be gin until 2011 or later and the same is true for most of the other larg er plants we’re aware of that are currently under development. Nonetheless, wh ile cellulosic biofuel production in 2010 may be limited, it is remarkable how much progress th e 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. Re gardless of where they are at, many have fallen behind their original commercialization sche dules. As with any new technol ogy, there have been delays associated with scaling up capacity, i.e., bugs to work out going from pilot to demonstration to commercialization. However, most are sayi ng it’s not the technologies that are delaying Deleted: six more likely companies described above

Deleted: ¶ ¶182 commercialization, it is lack of available funding. Obtaining capital has been very challenging given the current recession and the banking sector's fi nancial 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 lookin g 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 $ 720 million in federal funding to help build pilot and demonstration-scale biorefin eries employing advanced t echnologies across the United States

. XXX,406 The largest installment from Recovery Act funding was recently announced on December 4, 2009 and includes funding for a series of larger commercial demonstration plants including cellulosic ethanol projects by Ener kem and INEOS New Planet BioEnergy, LLC. DOE has also issued grants and loan guarantees to help fund some of the first commercial cellulosic biofuel plants. Current recipients include Abengoa Bioenergy, BlueFire Ethanol YYY and POET Biorefining in addition to previously-mentioned Range Fuels

. 407 The Food, Conservation, and Energy Act of 2008 (also known as the “2008 Farm Bill”) is also helping to support the up-and-coming ce llulosic biofuels industry

. 408

The 2008 Farm Bill assists the cellulosic bi ofuel industry in many ways. First, it modified the $0.51/gal alcohol blender credit to give preference to ethanol and other biofuels produced from cellulosic feedstocks. Effective Ja nuary 1, 2009, corn ethanol receives a reduced tax credit of $0.45/gal while cellulosic biofuel earns a credit of $1.01/gal. ZZZ In addition, theFarm Bill 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 Bioref inery 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 f ood sources. The program provides loan guarantees to develop, construct and retr ofit viable commercial-scale bi orefineries producing advanced

XXX On January 29, 2008 DOE announced that it would provide $114 million to fund 4 small scale cellulosic biorefineries. On April 18, 2008, DOE announced that it would provide another $86 million to help fund three additional small-scale plants. On July 14, 2008, DOE announced another $40 million to help fund two more small cellulosic plants. On December 4, 2009, DOE announced that up to $483 million would be made available to fund 14 pilot-scale and 4 demonstration-scale biorefineries across the country, the majority of which are pursuing cellulosic biofuel production.

YYY Although BlueFire is still working on obtaining financing to build its first demonstration plant, it has received two installments of DOE funding towards its first planned commercial-scale plant. The 19 MGY plant in Fulton, MS (originally planned for Southern California) was awarded $40 million on February 28, 2008 and another $81.1 million on December 4, 2009.
ZZZ Refer to Part II, Subparts A and B (Sections 15321 and 15331 ). Deleted: 680

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Deleted: ¶ ¶183 biofuels. The maximum loan guarantee is $250 million 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 USDA to help build its Soperton, GA plant. AAAA Section 9004 of the 2008 Farm Bill provid es payments to biorefineries to replace fossil fuels with renewable biomass. Sectio n 9005 provides payments to producers to support and ensure production of advanced biofuels. And finally, Section 9008 provides competitive grants, contracts and financial assistance to enable eligible entities to carry out research, development, and demonstra tion of biofuels and biom ass-based base d 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. 409 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. 410 Later that same month, DOE announced its plan to spend $375 million to build three bioenergy research centers dedicated to accelerating research and development of cellulo sic ethanol and other bi ofuels. The centers, which will each focus on different feedstocks and biological research cha llenges, will be located in Oak Ridge, TN, Madison, WI, and Berkeley, CA. 411 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 gra sses, stover, and other cellulosic materials into biofuel. 412 In February 2008, DOE awarded another $33.8 million to three companies and one research center to support the development of co mmercially-viable enzymes to support cellulose hydrolysis, a critical step in the bioc hemical breakdown of cellulosic feedstocks. 413 On March 2008, DOE and USDA awarded $18 million to 18 universities and research institutes to conduct research and development of biomass-based products, biofuels, bioe nergy, and related

processes. 414

Numerous states are also offering grants and tax incentives to help encourage biofuel production. Most of the effo rts are currently centered on e xpanding existing production and developing sustainable, second- generation feedstocks, technologie s 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 biofuels, 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 in centives described above, a group of states in the Midwest have joined together to pursue ethanol and othe r biofuel production and usage goals as part of the Midwest Governors Association (M GA). States that have signed on to the MGA goals include Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Missouri, Oh io, South Dakota and Wisconsin. In 2007, the MGA adopted the Midwes t Energy Security a nd Climate Stewardship

AAAA 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. Deleted: And, as mentioned above, on December 4, 2009, DOE announced that it would provide $564 million in stimulus funding to 19 projects aimed at turning biomass into fuels chemicals and power.

Deleted: ¶ ¶184 Platform. 415 The Platform goals are to produce cellulosic ethanol on a commercial level by 2012 and to have E85 offered at one-thi rd of refueling stations by 2025. They also want to reduce the energy intensity of ethanol production and suppl y 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

. 416

The refining industry is also helping to fu rther 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 th e past 12-18 months. A few refine rs (e.g., BP and Shell) have even entered into joint ventures to become cellulosic biofuel producers. General Motors and other vehicle/engine manu facturers are also providi ng financial support to he lp with research and development.

A summary of some of the cellulosic biofuel companies with near-term commercialization plans in North America is provided in 1.5-27. The capacities presented represent maximum annual average throughput based on each company’s current production plans. However, as noted, capacity does not ne cessarily 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 estim ates is provided in Tables 1.5-28 and 1.5-29. Deleted: governors

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Deleted: ¶ ¶185Table 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 -----22.90Cello 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 40.13 102.78 298.78 336.78 691.68Capacity 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 productionDeleted:AbengoaAE BiofuelsBlueFire EthanolCello EnergyCMEC / SunOptaCoskataDynamotiveaEnerkemFiberightFlambeau River BiofuelsFulcrum BioenergyInbicon / Great River EnerINEOS Bio / New PlanetEIogenKL EnergyMascoma CorporationNew PageOhio River Clean Fuels /BPOET BiorefiningRange FuelsRentechcVercipia (Verenium/BP JVMaximum Plant CapacitCellulosic CompanyaCapacity has been estimatedbPlant will co-process biomascellulosic biofuel.cIncludes Clearfuels demo plaDeleted:¶¶186Table 1.5-28.Promising New Cellulosic Alcohol PlantsCap(MGY)OpDateCap(MGY)OpDate AR EC 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 19.00 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.bCellulosic feedstocks. 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 LocationDeleted:¶¶187Table 1.5-29Promising New Cellulosic Hydrocarbon PlantsCap(MGY)OpDateCap(MGY)OpDate ARW 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. Cat = Catalytic depolymerization, Thermo = Thermochemical.bCellulosic feedstocks. AR = Ag residues, W = Wood waste, chips, mill waste, etc., UW = Urban waste including sorted MSW and C&D debris.cCapacities exclude 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 LocationDeleted:¶¶Formatted:Font: Not Bold188Deleted:¶¶189 1.5.3.4 Construction Feasibilit y 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, follo wed by addition of industry capacity continuing at an increasing pace due to more plant starts per year as well as increasing plant size. This is typical as an industry progresses up the learning curve, and investors become more confident and are willing to fund larger, more efficient plants. During the period from 2010-12, we also expect a slowing of starch etha nol plant construction, such that engineering and c onstruction personnel and equipment fabricators would potentially be able to transition to work on cellulosic biofuel facilities.

Here we examine the build rate required to construct cellulosic plants in time to meet the standards in Table 1.2-1, and we compare this to the historic build rate of capacity in the starch ethanol industry. Figure 1.5-13 de picts these construction trends.

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

0 5 10 15 20 25 30

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4 2 0 06 2008 2 01

0 2 0 12 2014 2 01

6 2 0 18 2020 2 022Plant 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 ethanol were derived from capacity information in Figure 1.5-1. Average plant capacity figure s 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. Deleted: ¶ ¶190 For cellulosic biofuel plan t construction, we assumed new plant size would begin relatively small at 40 million gal/yr for any builds during 2010-13, increasing to 80 million gal/yr for 2014-17, and 100 million gal/yr afterwards. Gi ven the volume standards laid out in the EISA, as well as the number of volume of cellu losic biofuel projected, we arrive at a maximum required build rate of approximate ly 2 billion gal/yr from 2018-2022. This is similar to the rate of starch ethanol construction in recent years. Table 1.2-30 shows a summary of the figures used in the analysis.

Table 1.5-30. Summary of figures used in the cellulosic 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. Year-by-year industry capacity figures were taken from RIA Table 1.2-1.

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.

Deleted: ¶ ¶191 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 expe nsive to construct than starch ethanol plants. Therefore, we believe the market will need to react even more enthusiastically with cap ital funding, design and construction resources.

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 rende red fats. The industry capacity has expanded rapidly, going from a sparse network of small businesses selling locally to one with large companies selling internationally in less than a decade. As of November 2009, the aggregate production capacity of biodiesel plants in the U.S. was estimated at 2.8 billion gallons per year across approximately 191 facilities, with a mean size of 16 million gallons per year and a median size of just 6 million gallons per year. 417 Table 1.5-31 shows histori cal aggregate capacity, sales volumes, and other information relate d to biodiesel production and use.

Table 1.5-31. Recent biodiesel industry production and use trends

. 418

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

The average capacity utilization had been steady around 30% during 2006-2008 due to continued expansion of on-line cap acity despite apparently adequate existing capacity. Reasons for this include various state incentives to build plants, along with state and federal incentives to blend and sell biodiesel, which ha ve given rise to an optimistic industry outlook over the past several years. However, in 2009 utilization was about half this level, due to a steep decline in exports as a result of European trade barriers enac ted early in the year, as well as a drop in U.S. diesel prices which has made biodies el relatively more expensive.

We can speculate that sustained low capacity utilization has been feasible for this industry because of the relatively low capital cost (typically 5-10% of total per-gallon production cost) of these plants, which enables them to opera te only part of the year or at reduced capacity, depending on feedstock prices or other market conditions. Beside s fuel, some plants may also Deleted: 448

Deleted: 16%

Deleted: 233

Deleted: 55%

Deleted: we expect

Deleted: to be

Deleted: ¶ ¶192 produce oleochemicals for use in detergents, lubricants or other products, providing additional sources of revenue for part of the industry.

In order to conduct our emissions and 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 feasibility of sustained over-capacity and the variety of useable feedstocks. In the absence of other information, we made the assumption that the 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 status of the tax incentives which have been renewed on a year-by-year basis for some time . We estimated how many plants would continue to pr oduce biodiesel and where they might be located based on three factors: state incentives for production and sales, BQ -9000 certification of existing plants, and capabilities for handling multiple feedstock types. This information was gathered from a database of member plants maintained by the National Biodiesel Board, and a summary of tax incentives from th e Department of Energy website. 419 Existing plants with affirmative status for more of these factors were expected to be more likely to survive over those that had fewer. We also projected that a number of very small plants processing waste greases/fats would continue to operate based on local market niches regardless of these criteria.

We project that between now and 2022 the num ber of plants will decline by about 30%, pushing capacity utilization above 80%. It is expected that plants will continue to operate in 44 states. During this period most plants will have added the pre-treatment and feedstock segregation capacity to process any mix of feedstock types available in their area. Multi-product plants will retain the capacity to produce biodiesel , but it is not expected to be their primary product due to higher margins for more specializ ed 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

. 420

2008 2022 Total production capacity on-line (million gal/yr) 2,610 1,968 Number of operating plants 176 121 Median plant size (million gal/yr) 5 5 Total biodiesel production (million gal) 776 1,670 Average plant utilization 0.30 0.85

1.5.4.2 Renewable Diesel

For a period of time in 2007 and 2008, ConocoPhilips produced small quantities (300- 500 bbl/day) of renewable diesel at their Borger, Texas, refinery from beef tallow generated by Tyson Foods, Inc. in Amarillo, Texas. This operation was stopped primarily due to changes in tax law that reduced the subsidy for renewable di esel products being copr ocessed with petroleum at refineries. 422 Deleted: perennially uncertain

Deleted: current biodiesel industry

Deleted: forecast

Deleted: 421

Deleted: ¶ ¶193 In fall of 2008, Dynamic Fuels, LLC (a jo int venture of Syntroleum Corp. and Tyson Foods, Inc.) announced construction of a 75 million gallon per year plant (5,000 bbl/day) in Geismar, Louisiana, that will use Tyson meat processing byproducts as feedstock to Syntroleum’s Bio-Synfining pro cess. Start-up is scheduled fo r 2010, with the primary product being high-quality diesel fuel that will be fungible within the existing petroleum supply system.

423 The Geismar facility plans to utilize supplie s of hydrogen available in the industrial park where it will be located, as well as rail and shipping infrastructure already in place nearby. 424 However, it is not co-located with existi ng petroleum production, an d therefore would be considered a stand-alone facility in our analyses (thus meeting the definition of non-coprocessed fuel eligible to generate RINs counting to ward the biomass-base d diesel standard).

Our industry projection is ba sed 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. 425 It is conceivable that more facilities will be built by Dynamic Fuels or other companies (such as Neste), or that some renewable diesel will be imported into the U.S., but we felt there was too much uncertainty to project volumes, given the large capacity for biodieselproduction already on-line. Also, considering tax subsidy and RIN incentives putting coprocessed 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 the number of potential technology providers. To give a sense of the size of the industry, we’ve developed a list of over 70 co mpanies from various locations around the world and summarized a basic description of their technologies for algae production ( Table 1.5-33 )

. This list is current as of November 2009 and is based mainly on biofue l magazines and articles that are supplemented with company websites. As new information is available on a near daily basis, it is possible that we have not include d newly formed companies or those not highly publicized.

Companies that have announced plans for algae-based biof uel production include: Sapphire Energy for 135 MMgal by 2018 and 1 Bgal by 2025, Petrosun for a 30 MMgal/yr facility, Solazyme for 100 MMgal by 2012/13

, and U

. S

. Biofuels for 4 MMgal by 2010 and 50 MMgal by full scale. It is important to realize that future projections are highly uncertain, and we have taken into account the best informati on we could acquire at the time. For more information on algae as a feedstock for biofuel, refer to Section 1.1.3.4.

In recent months, there have also been grants given to technologies based on algae. On December 4, 2009, the Department of Energy announced that it awarde d several algae-based technology providers. This included the following companies: Algenol Biofuels ($25 million grant for a pilot scale project located in Freeport, Texas), Solazyme ($22 million grant for a pilot scale project located in Riverside, Pennsylvania) and Sapphire Energy ($50 million grant for a demonstration scale project loca ted in Columbus, New Mexico). Deleted: . ¶

Deleted: Dyanmic

Deleted: . See

Deleted: , 2

Deleted: timelines

Deleted: in Arizona

Deleted:

,

Deleted: ¶ ¶194 Table 1.5-33. Companies Developing Algae Production Technologies BBBB

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 algae technology. Marysville, Ohio

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

BBBB Although we provide this summary here, we caveat that we have not confirmed the statements made on the company websites or on the data collected from news magazine/articles. For latest information please refer to the company’s website or contact the company’s representatives. Blanks occur where information was not available or found. Deleted: ¶ ¶ Formatted: Font: 10 pt

Formatted: Font: 10 pt195 Aurora Biofuels Use genetically-modified algae to generate oil for production of biodiesel. Uses seawater-fed, open ponds. Has produced slightly under 1,000 gallons oil per year from 1/8th acre surface area. The company estimates that will translate into 6,000 gallons/yr/acre at commercial size. The company uses waste water technology and a wet extraction process instead of the traditional process of centrifugation and drying. On August 18, 2009 announced that it had optimized particular algae strains to more than double their uptake of carbon dioxide. Headquarters in Alameda, California ;Developed at the University of California at Berkeley; Pilot-Scale facility in Florida

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

Deleted: ¶ ¶196 Biolight Harvesting Develop renewable fuels and chemicals from blue-green algae. Biolight is focused on brackish water and agricultural runoff as a long-term medium for cultivation. California; 40-acre pilot facility in California's Imperial Valley

Bionavitas High-volume production of algae using biofactories and fiber-optic lights in algaculture system. Claims to have a cost-efficient way to deliver light to biomass. Light Immersion Technology (LIT). Redmond, Washington

BioProcess Algae LLC Photobioreactor systems coupled next to an ethanol facility which provides water, heat, and CO2. Pilot project anticipated to be in Shenandoah, Iowa

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 eight - 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. Deleted: 8

Deleted: ¶ ¶197 Circle Biodiesel and Ethanol Corporation Have manufactured an algae photobioreactor for the production of algae. Also has an algae harvesting system for the extraction of algae oil for algae biodiesel or algae biofuel. Algae harvesting system retails for $195,000 US dollars, can process one gallon of algae oil per minute. Headquarters in San Marcos, California

Desert Sweet Biofuels Using a combination of gasification and pyrolysis in such a way as to produce biochar, a byproduct is electricity. One low cost algae production system currently being developed is vectoring algae through Daphnia. Gila Bend, Arizona

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.
Deleted: ¶ ¶198 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 coupling PBRs with open pond systems. Hawaii

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 Headquarters in Menlo Park, California; Original plans to grow algae in ponds at the Salton Sea, an inland saline lake in Deleted: ¶ ¶199 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 acids and other oils used as feedstocks for renewable fuels. 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.

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

Deleted: ¶ ¶ Formatted: Font: 10 pt200 OriginOil The company's bioreactor attempts to speed the growth of algae in a tank by blending light emitted from a rotating shaft with nutrients. The process does not require chemicals, initial dewatering, or high capex for heavy machinery. The company’s technology combines electromagnetism and pH modification to break down cell walls, releasing algal oil within the cells. The oil rises to the top for skimming and refining, while the remaining biomass settles to the bottom for further processing as fuel and other valuable products. Los Angeles, California

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 Georgetown, South Carolina Deleted: ¶ ¶201 gases.

SAIC Focus on creation of algaebased jet fuel Headquarters in McLean, Virginia; locations in 150 cities worldwide

Sapphire Energy Plans to grow algae in open ponds of unusable water. Algae-based based fuels developed include gasoline, diesel, and aviation fuels. San Diego, California; Demo in Las Cruces, California

SCIPIO Biofuels Continuously circulating photobioreactors and continuous algae harvester. The company says it will target whatever fuel is demanded, be it jet fuel, ethanol, biodiesel, or biobutanol. Headquarters in Laguna Hills, California Plans for facility in Greensburg, Kansas

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 includingcellulosic 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 Deleted: ¶ ¶202 for the project in Southwest Colorado.

StellarWind Bioenergy The company is using its proprietary PhycoGenic Reactor and PhycoProcessor systems as well as a RecyCO2Tron system for CO2 recovery. The PhycoProcessor is an oil recovery system. Their resource recovery system coverts algae biomass into methane, charcoal, fertilizer,
or syngas. Indianapolis, Indiana

SunEco Energy Harvesting and growth of native algae species in open ponds, claims to can produce at least 33,000 gallons of biocrude per acre-foot per
year. Headquarters in Chino, California; Operations in Niland, California

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 Deleted: ¶ ¶203 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 generatingsystems; and the NonThermal Plasmatron. Carson City, NV; Plans for bioreactor running inGuelph, Ontario in midSept 2009

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.

Deleted: ¶ ¶ Section Break (Continuous)

Deleted: ¶ ¶204 

### 1.6 Biofuel Distribution

1.6.1 Biofuel Distribution Overview

The current motor fuel distribution infrastruc ture has been optimized to facilitate the movement of petroleum-based fuel s. Consequently, there are very efficient pipeline-terminal networks that move large volumes of petrol eum-based fuels from production/import centers on the Gulf Coast and the Northeast into the heartland of the country. In contrast, the most biofuel volumes are produced in the heartland of the count ry 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 dictated by the need to be close to the source of the feedstocks used rather than to fuel demand centers or to take advantage of the ex isting pipeline distribution system for petroleum products. CCCC

To varying degrees, the physical/c hemical 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 tr uck to petroleum termin als. All biofuels currently are blended with petroleu m-based fuels prior to use. Most biofuel blends can be used in conventional vehicles. However, E85 can only be used in flex-fuel vehicles, requires specially-constructed retail dispensing/storage equi pment, and may require special blendstocks at terminals. These factors limit the ability of bi ofuels to utilize the existing petroleum fuel distribution infrastructure. Hen ce, the distribution of renewable fuels raises unique concerns and in many instances requires the addition of new transportation, storage, blending, and retail equipment.

Significant challenges must be faced in reconfiguring the distribution system to accommodate the large volumes of biofuels that we project would be used to meet the proposed standards. Considerable effort s 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 syst em to support compliance with the volumes of biofuels required by the RFS2 standards. DDDD EPA will continue to participate in or monitor these efforts as appropriate.

Considerations related to the distribution of ethanol, cellulosic distillate fuel, renewable diesel fuel, and biodiesel are discussed in the following sections as well as the changes to each segment in the distribution system that would be needed to support the volumes that we project would be used to satisfy the RFS2 standards. The costs associated with making the necessary changes to the fuel distribution infrastructure are discussed in Section 4.2 of this RIA. The importation of ethanol into the U.S. is discussed in Section 1.5.2 of this RIA.

CCCC A discussion of the projected locations of ethanol production facilities can be found in Chapter 1.5 of this RIA.

DDDD For example, the “Biomass Research and Development Board”, an inter-governmental group co-chaired by USDA and DOE., includes a group that is focused on evaluating biofuels distribution infrastructure issues. http://www.usbiomassboard.gov/distribution_infrastructure.htm Deleted:205 1.6.2 Biofuel Shipment to Petroleum Terminals

Pipelines are the preferred method of shippi ng large volumes of pe troleum products over long distances because of the relative low cost and reliability. Ethanol currently is not commonly shipped by pipeline because it can cause stress corrosion cracking in pipeline walls and its affinity for water and solvency can result in product cont amination concerns. 426 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. EEEE We believe that it is currently not possible to re-process this mixture in the way that diesel-gasoline mixtures resulting from pipeline shipment are currently handled. FFFF The Pipeline Research Council International (PRCI) in coordination with th e Pipeline and 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. 427 A short gasoline pipeline in Florida is currently shipping batches of ethanol and other more extensive pipeline systems have feasibility studies underway. 428 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 feasib ility of constructing a new dedicated ethanol pipeline from the Midwest to the East coast. 429 Substantial issues woul d need to be addressed before construction on such a pi peline could proceed, including thos e associated with securing new rights-of-ways and establishing sufficient surety regarding the return on the several billion dollar investment.

We expect that cellulosic distillate fuels and renewable diesel fuel will not have materials compatibility issues with the existing petroleum fu el distribution infrastructure. Thus, there may be more opportunity for these biofuels to be shipped by pipeline. However, the location of ethanol and cellulosic distillate/renewable diesel production facilities relative to the origination points for existing petroleum pipelines will be a limiting factor regarding the extent to which pipelines can be used. The gathering of ethanol from production facilities located in the Midwest and shipment by barge down the Mississippi for introduction to pipelines in the Gulf Coast has been discussed by industry. This approach might also be considered for cellulosic distillate fuel when such plants are constructed. However, 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 pipe lines compared to direct shipment by rail.

Biodiesel is currently not widely shipped by pipeline due to concerns that it may contaminate jet fuel that is shipped on the same pipeline and potential incompatibility with pipeline gaskets and seals. Se gments of Kinder Morgan’s Plantation pipeline are currently shipping B5 blends, and its Oregon Pipeline that runs from Portland to Eugene is currently shipping B2 blends. 430 These systems do not handle jet fuel . The shipment of biodiesel by

EEEE Different grades of gasoline and diesel fuel are typically shipped in multi-product pipelines in batches that abut each other. To the extent possible, products are sequenced in a way to allow the interface mixture between batches to be cut into one of the adjoining products. In cases where diesel fuel abuts gasoline in the pipeline, the resulting mixture must typically be reprocessed into its component parts by distillation for resale as gasoline and diesel fuel.

FFFF We believe that it is not currently possible to separate ethanol from a gasoline/diesel mixture sufficiently by distillation. Hence, a significant amount of ethanol may remain in the gasoline and diesel fractions separated by distillation. Gasoline-ethanol mixtures can be blended into finished gasoline provided the applicable maximum allowed ethanol concentration is not exceeded. However, diesel-ethanol mixtures can not be used as motor fuel.206 pipeline may become more widespread and might be expanded to systems that handle jet fuel. However, the relatively sma ll production volumes from individual biodiesel plants and the widespread location of such production facilities may tend to limit the extent to which biodiesel may be shipped by pipeline. Rail cars, barges, and tank trucks th at transport biodiesel over long distances will need to be heated/insulated in cold climates to prevent gelling.

Due to the uncertainties regarding the extent to which pipelines might participate in the transportation of biofuels in the future, we assumed that biofuels will continue to be transported by rail, barge, and truck to petroleum terminals as the vast majority of biofuel volumes are today. To the extent that pipelines do play an increasing role in the distribution of ethanol, this may improve reliability in supply and reduce distribution costs.

Apart from increased shipment by pipeline, bi ofuel distribution, and in particular ethanol distribution, can be further optimized primarily through the expanded use of unit trains. Unit trains are composed entirely of 70-100 ethanol ta nk 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 a ssembled at a single produc tion 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 produ cers. 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 im portant 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 un it train receipt facilities would be located at petroleum terminals and existing rail term inals. Based on industry input regarding the logistical hurdles in citing unit train receipt f acilities at petrol eum/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. GGGG

Shipment of biofuels by manifest rail to existing rail terminals will continue to be an important means of supplying bi ofuels to distant markets where the volume of the production facility and/or the local demand is not sufficient to justify shipment by unit train. Manifest rail shipment refers to the shipment of biofuel in rail tanks cars that are incorporated into trains which are composed of a variety of other commodities. Shipments by barge will also play an important role in those instances where producti on and demand centers have water access and in some cases as the final link fro m 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.

GGGG 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.htm207 We project that most biofuel volumes shipped by rail will be delivered to petroleum terminals by tank truck. HHHH 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 bi ofuel storage tanks were constructed. IIII 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 biof uel 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 Oa kridge National Laboratory (O RNL) analysis of ethanol transportation activity under the EI SA that was conducted for EPA. 431 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 mark ets considering ethanol source and end use locations, the current configura tion and projected evolu tion of the distribution system, and cost considerations for the differ ent transportation modes. The NPRM analysis assumed that all biofuel volumes other than bi odiesel would be ethanol. For this FRM, we analyzed three scenarios under which varying volume s 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 analys is to evaluate the distribution impacts for the final rule assumes that cellulosic distillate produc tion plants would take the place of some of the ethanol production plants projected in the NPRM. It further assumes that cellulosic distillate fuel use would coincide with the ethanol e nd-use areas projected in the NPRM.

The extent to which new cellulosic disti llate fuel and cellulo sic 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 loca lly. Cellulosic distillate fuel distribution may also be further simplified to the extent that in the future it is blended with petroleum-based diesel fuel in higher blend-ratios than the 20% blends currently registered by EPA. An increased blend ratio for cellulosic distillate fuel would tend to enhance the ability for its use close to the place of manufacture rather than having to be spread mo re widely over a larger petroleum diesel pool.

We projected the volumes of biodiesel that would be used on a St ate-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

HHHH At least one current ethanol unit train receipt facility has a pipeline link to a nearby terminal. To the extent that additional unit train receipt facilities could accomplish the final link to petroleum terminals by pipeline, this would significantly reduce the need for shipment by tank truck.

IIII 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. Deleted:208 facilities and their volumes, we evaluated the most efficient means of meeting this projected demand while minimizing shipping distances (a nd cost). The remaining biodiesel production volume from these production facilities that was needed to meet the RFS2 mandated volume was assumed to be used in the same State where it was produced up to the point where the State’s entire diesel fuel pool c ontained 5% biodiesel. We belie ve that this should provide a somewhat conservatively high es timate of biodiesel distribution costs since biodiesel might be used in excess of 5% even absent a State mandate. If a State was already saturated with 5% biodiesel, the remaining volume was assumed to be shipped out of State within a 1,000 mile shipping distance. A 1,000 mile shipping distance was selected to ensure that all biodiesel not used to satisfy a State mandate or for bio-heat could find a market. It is likely that some fraction would not need to travel quite as far. Therefor e, this assumption is also likely to result in a conservatively high estimate of biodiesel freight costs. It wa s 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 mani fest 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, tank trucks, tank truck and rail/barge/truck receipt facilities is within the reach of the corresponding construction firms. Although shipment of biofuels by rail represents a majo r fraction of all biofue l ton-miles, it is projected to account for approximately 0.4% of all rail freight by 2022. JJJJ 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 substan tial resources that seem likely to be focused on this cause, we believe that overall freight ra il capacity would not be a limiting factor to the successful implementation of the biof uel requirement s 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 Labor atories (ORNL) to examine fuel ethanol transportation, activity, and potential distribution constraints for the North American freight rail system. 432 The analysis found that biofue ls transport is expected to constitute approximately 0.4% of the total freight tonnage for all commodities transported by the freight rail system through 2022. The results suggest that it should be feasible for the freight rail system to accommodate the additional biofue ls freight associated with the RFS2.

JJJJ See Section 1.6.3. of this RIA for a discussion of the increase in freight traffic due to the transport of the biofuels needed to comply with the RFS2 standards Deleted: volumes209 For the analysis, we provided the estimated location of ethanol production facilities, sources of ethanol imports, and state-level consumption for the annual volumes of ethanol that we estimated would be consumed in response to the EISA. KKKK We also provided the projected volumes of biodiesel and non-co-processed renewable diesel fuel that would be used. Due to the uncertainty associated with non-ethanol 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 Su rface Transportation Bo ard Carload waybill sample was incorporated into ORNL’s North American Transportation Infrastructure Network Model to provide a baseline a pproximation of the current day fre ight rail system unstressed by the transport of EISA-mandated 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 Am erican freight rail system. FAF2 integrates data from a variety of sources to estimate commodity flows by different modes of transportation and related freight transportation activity among states, regions, and major international gateways. FAF2 provides freight transportation forecasts through 2035.

To estimate potential future constraints of the freight rail system, EISA-mandated biofuels volumes were superim posed onto the unstressed Infrastructure Network model for 2012, 2012, and 2022. For each forecast year, total biofuels demand includes biodiesel and non-coprocessed renewable diesel fuel demand. As such, total biofuel demand for the forecast years were assumed to be 14.6, 17.5, and 35.1 billion gallons, respectively. See the ORNL report for additional assumptions and modeling details.

On average, 84% of the nation’s freight rail system will not be affected by biofuels shipments under the RFS2 scenarios considered, according to the ORNL analysis. The 16% which will be impacted will see a 2.5% increase in freight rail traffic associated with biofuels shipments, on average. LLLL 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, Mi nnesota, and Indiana, respectively. The balance is expected to originate from the surrounding Midwestern states.

As such, the 16% of the freight rail system that is expected to see an increase in biofuels shipments under RFS2 will see it concentrated along rail corridors radiating out of the Midwest. Most high-volume ethanol 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

KKKK These inputs are summarized in the ORNL final report.

LLLL The overall increase in freight tonnage is 0.4% (2.5% x 16%)210constitute 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 commodities. The results of this analysis suggest that it should be feasible for the distribution infrastr ucture upstream of the te rminal to accommodate the additional freight associated with this RFS2.

1.6.4 Rail Transportation System Accommodations

Many improvements to the freight rail system will be required in the next 15 years to keep pace with the large increase in the overall freight demand. Much of the projected increase in rail freight demand is associated with the expected rapid growth of inter-modal rail transport. Most of the needed upgrades to the freight rail system are not specific to the transport of renewable fuels and would be ne eded irrespective of the need for increased biofuel transport under the EISA. The modifications required to satisfy the increas e 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 MMMM and governmental agencies in discussions with EPA and in testimony provided for the Surface Transportati on Board (STB) expresse d 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 bottleneck areas with respect to the movement of ethanol from the Midwest to the East coast is Chicago. The City of Chicago commissioned its own analysis of rail capacity and congestion, which found that the lack of rail capacity is “no longer limited to a few choke points, hubs, and heavily utilized corridors.” Instead, the report finds, the lack of rail capacity is “nationwide, affecting almost all the nation’s critically important trade gateways , rail hubs, and intercity freight corridors.” This is due, in part, to the lack of critical linkages between the 27 major rail yards located in the Chicago-land

area.

To help improve east-west ra il connections through the city , federal, state, and local officials announced an agreement in 2006 to invest $330 million over three-years in city-wide

MMMM 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. Deleted:

,211 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 ra il freight cars pass through the city every day projected to increase to 67,000 by 2020. Chicago is the only city where a ll 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 are focused on making the modifications to the rail system to cope with the increase in demand. Rail carriers report that they typically invest 16 to 18 billion dollars a year in infrastructure improvements. 433 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 NNNN , administered by Federal Railroad Administration (FRA), as well as Section 45G Railroad Track Maintenance Credits, offered by the Internal Revenue Service (IRS).

The RRIF program offers loans to railroads for a variety of ca pital purposes including track and equipment rehabilitation at “cost of money” for 25 year terms. Typically, short line railroads cannot secure this kind of funding in the private markets. Under this program, FRA is authorized to provide direct loans and loan guarantees up to $35.0 billion. Up to $7.0 billion is reserved for projects benefiting freight railroads other than Class I carriers. However, the program has lent less than $650 million to non-passenger rail ca rriers since 2002, according to the FRA/RRIF website.

The American Association of State Highway Transportation Officials (AASHTO) estimates that between $175 billion and $195 billi on 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. 434 The report suggests that railroads should be able to provide up to $142 billion from revenue and borrowing, but that the remainder would have to come from other sources including, but not limited, to loans, tax cr edits, sale of assets, an d other forms or publicsector participation. Given the reported historical investment in rail infrastructure, it may be reasonable to assume that rail carriers would be able to manage the $7.1 billion in annual investment from rail carriers that AASHTO projects would be needed to keep pace with the projected increase in freight demand.

The Association of American Railroads (AAR) estimates 435 that meeting the increase in demand for rail freight transportation will require an investment in infrastructure of $148 billion (in 2007 dollars) over the next 28 years and that Class I railroads' share is projected to be $135 billion, with $13 billion projected for short line and regional freight railroads.

NNNN The RRIF program was established by the Transportation Equity Act for the 21st Century (TEA-21) and amended by the Safe Accountable, Flexible and Effi cient 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.212 In testimony before the STB, Class I railroads committed to working with all parties in the ethanol logistical chains to provide safe, cost-effective, and reliable ethanol transportation services as well as to resolve past freight rail capacity difficulties. Presumably, this commitment extends to the projected three- percent increase in overall frei ght tonnage envi sioned 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. OOOO In addition, questions persist regarding allocation of these investments, with the Alliance of Automobile Manufacturers, American Chemistry Council, National Industrial Transportation League, a nd others expressing concern that their infrastructural needs may be neglected by the Class I railroads in favor of more lucrative intermodal traffic. Moreover, the GAO has raised questions regarding the 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 a nd biodiesel might not be a first priority for rail carriers. In response to GAO concerns, the Surface Transportation Board (STB) agreed to undertake a rigorous analysis of competition in the freight railroad industry. PPPP

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 freight ra il capacity would not be a limiting factor to the successful implementation of the biofuel requirements under the RFS2 standards. Evidence from the recent ramp up of ethanol use has also shown that ra il carriers are enthusiastically pursuing the shipment of ethanol, although there is some indica tion 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 ga thering sufficient numbers of ethanol cars to allow Class 1 railroads to ship ethanol by unit train. Based on this recent experience, we believe that biofuels will be able to compete successfully with other commodities in securing its share of freight rail service.

While many changes to the overall freight rail system are expected to occur irrespective of today’s final rule, several biofuel-specific modifications will be needed. Additional unit train and manifest rail receipt facilities will be needed to handle the volumes of ethanol and cellulosic distillate fuel that we project will be used to co mply 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 the logistical hurdles in citing unit train receipt

OOOO The railroads interviewed by GAO were generally unwilling to discuss their future investment plans with the GAO. Therefore, GAO was unable to comment on how Class I freight rail companies are likely to choose among their competing investment priorities for the future, including those of the rail infrastructure, GAO testimony Before the Subcommittee on Surface Transportation and Merchant Marine, Senate Committee on Commerce, Science, and Transportation, U.S. Senate, Freight Railroads Preliminary Observations on Rates, Competition, and Capacity Issues, Statement of JayEtta Z. Hecker, Director, Physical Infrastructure Issues, GAO, GAO-06-898T Washington, D.C.: June, 21, 2006).

PPPP 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).213 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. QQQQ We assumed that under the primary mid-ethanol and the low-ethanol control scenarios that all unit train and manifest rail recei pt facilities would be capable of handling the receipt of both ethanol and cellulosic distillate fuel. There is no cellulosic distillate fuel under the high-ethanol scenario, thus all unit train receipt facilities would be dedicated to handling ethanol under the high-ethanol control scenario.

In the NPRM, we assumed that some new manifest rail receipt facilities for biofuels would be located at petroleum terminals. Since the NPRM we received industry input that it is unlikely that additional manifest rail receipt facilities could be located at petroleum terminals due to a lack of reasonable access to a rail line. Consequently, we are now assuming that additional manifest rail receipt facilities for biofuels woul d be placed at exiting rail terminals. We are assuming that biofuels will continue to be trans-loaded directly from rail cars to tank trucks at rail terminals for shipment to petroleum terminals as is the case today, thereby obviating the need for biofuel storage at rail terminals. RRRR Some manifest rail recei pt facilities would also handle biodiesel as well as ethanol, and cellulosic distillate fuel/renewable diesel fuel.

As part of Oakridge Nationa l Laboratory’s study for EPA on the projected patterns of ethanol distribution from producer to terminal under the EISA, ORNL estimated the number of unit train receipt facilities. 436 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 numbe r of unit train receipt facilities for the NPRM control case is still very useful in estimating the number of such facilities under the control cases examined in this final rule. The NPRM contro l scenario assumed the use of 34.14 BGal/yr of ethanol by 2022. Under the high-ethanol control scenario in this final rule (FRM), we estimate that 33.24 BGal/yr of ethanol would be used by 2022. Given their similarity, we assumed that the ORNL results for the NPRM would be appli cable to the FRM high-ethanol scenario for estimating the number of unit train receipt facilities required.

Based on our analysis of a spreadsheet used in the ORNL analysis, we determined that ORNL estimated that there would be approxima tely 210 unit train recei pt facilitie s under the NPRM control case. 437 The ORNL estimate was based on an assumption by ORNL regarding the minimum annual throughput needed to justify the construction of a unit train facility (~20 MGal/yr) which we now believe to understa te the throughput needed. Since the completion of the ORNL study, we received input from industry experts who are familiar with the construction of ethanol unit train receipt facilities that th e 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 th e land needed, and ease of

QQQQ Existing unit train receipt facilities have primarily followed this model.

RRRR 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.214 construction of the rail spur to the facility to a rail line. To provide a more realistic estimate under varied conditions, we assumed a minimum throughput volume of 280 MGal/yr.

We evaluated the location and annual thr oughput volumes of the unit train receipt facilities projected by ORNL. We consolidated the volumes from the smaller facilities projected by ORNL regionally to satisfy a minimum throughput vo lume of 280 MGal/yr while maintaining a reasonable trucking distance (<200 miles) from unit train facilities to petroleum terminals. Based on this analysis, we arrive d at an estimate of 40 unit tr ain receipt facilities to support the volumes of ethanol and cellulosic distillate fuel that we projec t 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. SSSS

We assumed that 40 unit trai n 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 sin ce the total volume of ethanol and cellulosic distillate fuel is somewhat lower under these scenarios relative to the high-ethanol scenario. However, we believe that this is an appropriate approach since it provides some margin to compensate for the potential that there may be so me instances where a unit train receipt facility may only handle ethanol or cellulosi c distillate fuel (potentially increasing the overall number of unit train facilities needed slightly). We estimate that there would be 9 uni t train recei pt facilities to support the transport of biofuels under th e 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 num ber unit train facilities under the RFS1 reference case, we evaluated how many of these type of facilities we re in place or under construction when historic ethanol consumption levels were consistent with the RFS1 case. Under the RFS1 reference case, we attri buted the need for 37 additional biofuel unit train receipt facilitie s (40-3) to the implementa tion of the EISA. Under the AEO reference case, we attributed 31 additional unit train receipt facilities (40-9) to the EISA.

The construction of each of these unit tr ain receipt facilities would require: the acquisition of land near a rail line and within trucking distance of the petroleum terminals that would be served, the construction of a rail spur and internal tracks to handle unit trains, facilities for the high-speed unloading of rail cars and loadin g of tank trucks, biofue l storage tanks and/or pipelines to ship biofuel to nearby petroleum te rminals, and other miscel laneous biofuel handling equipment. For our analysis, we assumed that al l 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 storage tanks at unit train receipt facilities.

SSSS See Section 1.6.6 for a discussion of the tanker trucks needed to support the distribution of biofuels under the EISA. For a discussion of our estimation of ethanol and cellulosic distillate freight costs, see Sections 4.2.1.2 and 4.2.2.2 respectively in this RIA. The attribution of the costs of unit train facilities to the volumes of ethanol and cellulosic distillate fuel is discussed in Sections 4.2.1.1.2 and 4.2.2.1.3 Deleted: Volumes

Deleted: were consolidated215 A spreadsheet used in the ORNL analysis indicates that ORNL estimated that there would be 56 manifest rail receipt facilities for biofuels under the NPRM control case. 438 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. TTTT We estimated that an additional 43 manifest rail receipt facilities would be ne eded to support the transport of biofuels for the three FRM control cases relative to the AEO reference case. We arrived at this estimate by subtracting the number of manifest rail receipt facilities that could be attributed to the incremental increase in biofuel shipment volumes in going from the RFS1 to the AEO reference case from the number of facilities attributed to the EISA under the RFS1 reference case (56-13). UUUU 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 a nd the preparation of bi lls of lading, and the installation of other miscellaneous 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 th e transport of ethanol would be used to handle cellulosic distillate and renewable diesel fuels. Our estimation of the rail cars needed to transport ethanol and cellulosic distillate fuel under the 3 control scenarios is based on an interpolation of the results from the ORNL analysis for the NPRM control case (34.14 BG/yr of ethanol by 2022) and AEO reference case (13.18 BG/yr of ethanol by 2022). The underlying assumption in this approach is that the overall number of rail cars needed varies by the total volume of biofuel projected to be used under a given control scenar io. Based on this approach, we estimate that 40,400 rail cars would be needed to transport th e volumes of ethanol a nd cellulosic distillate fuel/renewable diesel fu el under the high-ethanol scenario, 36,200 under the primary mid-ethanol scenario, and 34,400 under the low-ethanol scenario

. We subtracted the number of rail cars needed under the two reference cases to determin e the incremental number of rail cars attributed to compliance with the EISA (see Table 1.6-1).

TTTT 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.

UUUU The number of manifest rail receipt facilities attributed to the incremental increase in biofuel shipment volumes in going from the RFS1 to the AEO reference case was calculated by volume weighting. Deleted: .4216 Table 1.6-1. Additional Rail Cars Needed by 2022 for Shipment of the Incremental RFS2 Volumes of Ethanol, and Cellulosic Distillate Fuel/Renewable Diesel Fuel

Number of Rail Cars

Reference Case used for Comparison

RFS1 AEO 2007 Low-Ethanol Scenario 24,600 12,600 Mid-Ethanol Scenario 20,400 8,300 High Ethanol Scenario 18,500 6,500

We estimated the number of rail cars that w ould 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 cons ervatively 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 proj ected 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 1.6-2.

Table 1.6-2. Additional Rail Ca rs Needed by 2022 for Shipment of All Incremental RFS2 Biofuel Volumes

Number of Rail Cars

Reference Case used for Comparison

RFS1 AEO 2007 Low-Ethanol Scenario 25,800 13,700 Mid-Ethanol Scenario 21,500 9,400 High Ethanol Scenario 19,700 7,500

Our analysis of ethanol, biodiesel cellulosic distillate, and renewable diesel fuel rail car production capacity indicates that access to these cars should not represent a serious impediment to meeting the requirements under the RFS2 st andards. Ethanol ta nk car production has increased approximately 30% per year since 2003, with over 21,000 tank cars expected to be produced in 2007. To accommodate the increased demand for ethanol tank cars, rail car Deleted: .4

Deleted: .4

Deleted: .4217 producers converted existing boxcar production facilities to tank production facilities and brought on additional work shifts to adjust to rapidly changing to market conditions.

With the recent economic downturn, the backlog for railcars has decreased significantly. For example, the backlog for railcars of a major producer was approximately 7,000 railcars in 2009, but dropped to approximately 1,200 railcars scheduled for delivery in 2010. This has led to the closure of several railcar production facilities. We believe that the excess railcar production capacity will allow the industry to rapidly respond to potential increases in railcar demand due to ethanol, biodiesel, cellulosic distillate, and renewable diesel fuels, when the need arises.

1.6.5 Marine Transportation System Accommodations

The American Waterway’s Association e xpressed 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 c oncerns have been focused on the need to upgrade the river lock system on the Mississippi river to accommodate longer barge tows and on dredging inland waterways to allow for movement of fully loaded vessels. We do not anticipate that a substantial fraction of biofuels will be transported via these arteries. Thus, we do not believe that the ability to ship biofuels by inland marine will represent a serious barrier to the implementation of the requirements under RFS2 standards. Substantial quantities of th e corn ethanol co-product dried distiller grains (DDG) is expect ed to be exported from the Midw est 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 domes tic 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 barges with a carrying capacity of 30,000 barrels. Thus, our assumed use of 10,000 barrel barges may overstate the number of barges that would be needed. Our estimation of the barges needed to transport ethanol and cellulosic distillate fuel under the 3 control scenarios is based on an inte rpolation 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 assump tion in this approach is that the over all number of barges needed varies by the total vo lume 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 unde r the high-ethanol scenario, 150 under the primary mid-ethanol scenario, and 143 under the low-ethanol scenario. We subtracted the num ber 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 -3 ). Deleted: .5-1218 Table 1.6 -3

. Additional Barges N eeded by 2022 for Shipment of th e 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 biodies el that we expect would be shi pped 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. VVVV We estimate that 41 barges would be needed by 2022 to transport the volume of biodiesel that we project will be used to satisfy the RFS2 standards. We estimate that 7 barges would be needed by 2022 to transport the volume of biodiesel projected unde r the RFS1 reference case and 9 barges under the AEO reference case. Consequently, we attribute the construction of an additional 34 biodiesel barges to the implementation of the EISA unde r the RFS1 reference case and 32 under the AEO reference case. The total additional number of barges for the transport of ethanol, cellulosic distillate fuel/renewable diesel fuel, and biodiesel that we attribute to the implementation of the EISA is presented in Table 1.6

- 4.

Table 1.6 -4

. Additional Barges Needed by 2022 for Shipment of All Incremental RFS2 Biofuel Volumes

Number of Barges

Reference Case used for Comparison

RFS1 AEO 2007
Low-Ethanol Scenario 129 67 Mid-Ethanol Scenario 112 60 High Ethanol Scenario 105 53

The U.S. tank barge fleet currently numbers 3,600. 439 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

VVVV 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. Deleted: .5-1

Deleted:

.
Deleted: -2

Deleted: .5-2219 biofuels by barge over time, we believe that the addition to the fleet of the barges estimated to be needed to transport biofuels can be accommodated by the industry.

As discussed in Section 1.5.2. of this RIA, we are projecting significant imports of ethanol by 2022. To estimate which ports would receive ethanol imports we gave priority to ports that have a history of receiving ethanol imports from Brazil and Ca ribbean Basin Initiative Counties WWWW according to company-level historical fuel import data from the Energy Information Administration (EIA). 440 Additional ports were sele cted from those that have a history of receiving finished gasoline imports. Ports were selected in States that could not satisfy their internal ethanol demand from in-State production and from thos e ports that were closest to large demand centers. We estimate that a total of 30 ports would receive imported ethanol by 2022. The list of ethanol import ports was provided to ORNL as an input to the ethanol transportation analysis th at they conducted for EPA. 441 Under the high-ethanol option, we estimate that the 18 ports which did not receive et hanol 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 th e past would primarily ne ed to install additional ethanol storage tanks. We pr oject that under the primary mid-ethanol scenario that 15 new ethanol import locations would be added and that under the low ethanol scenario there would be 14 new ethanol import locations. We used these estimates relative to both the RFS1 and AEO reference cases since we expect that the increase in ethanol imports would most appropriately be attributed to the incremental increase in ethanol use levels above thos e reflected under both the AEO and RFS1 reference cases. We believe that all the ports where etha nol 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 Nationa l Laboratory’s study for EPA on the projected patterns of ethanol distribution from producer to terminal under the EISA, ORNL estimated the number of barge receipt facilities that would be needed to support biofuel shipments within the U.S. 442 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. 443
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 scenario provides a reasonable (although perhaps conservatively high) estimate of the number of such facilities that would be needed under the high-ethanol scenario.

We assumed that all biofuel barge receipt facilities would handle ethanol and cellulosic distillate fuel and that some of these facilities would handle biodiesel. To compensate for the potential that there may be some instances where a manifest rail receipt facility might handle ethanol but not cellulosic distillate fuel or vice-versa (perhaps increasing the number of unit train facilities slightly), we assumed that 57 manifest rail receipt facilities would also be needed under the mid-ethanol and low-ethanol scenarios. Our analysis of th e aforementioned ORNL

WWWW Caribbean Basin Initiative countries receive special exemptions from U.S. ethanol import tariffs (See Section 1.5 of this RIA regarding the source of ethanol imports and for additional discussion regarding how we estimated where ethanol imports would enter the U.S..220 spreadsheet indicates that ORNL estimated th ere would be approximately 4 barge receipt facilities under the RFS1 reference case. Therefore, we estimate that an additional 53 barge receipt facilities would need to be configured to receive biof uels in order to facilitate compliance with the RFS2 program relative to the RFS1 refe rence 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 fa cilities would need to be configured to receive biofuels in order to facilitate compliance with the RFS2 program relative to the AEO reference case

We believe that barge receipt facilities that receive shipments of biofuels would be those that already handle the receipt of petroleum-based fuels and which are incorporated into petroleum terminals or would be linked to unit train receipt facilities. Such facilities would need to install/modify piping, pumps, vapor handling systems. The need for biofuel storage tanks and other facilities to handle the storage and transfer of biofuels to other means of distribution at such is addressed within the context of the additional facilities needed at petroleum terminals and unit train facilities.

1.6.6 Road Transportation System Accommodations

A substantial number of tank trucks would be needed to distribute the additional volume of biofuels that we project would be used to m eet the RFS2 volumes. In all cases, a tank truck capacity of 8,000 gallons was assumed. Larger tank trucks are permitted in some areas, so this assumption will tend to overestimate of the number of tank trucks needed. We assumed that tank trucks similar to those used for the transport of ethanol would be used to handle cellulosic distillate and renewable diesel fuels.

Our estimation of the tank trucks needed to transport ethanol and cellulosic distillate fuel under the 3 control scenarios is based on an inte rpolation 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 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 tr ain facilities under the ORNL analysis which we consolidated into larger unit train receipt facilities represents 41% of the total volume shipped to unit train facilities (12.6 BG/yr out of 21.4 BG/yr in 2022 under the NPRM control case). We compared the location of the 170 unit train facilities that we consolidated into the remaining 40 such facilities from the ORNL analysis to the location of the petroleum terminals that these facilities were intended to service. Based on this comparison, we estimated that 41% of the volume of biofuels shipped by unit train would need to be shipped 3 times farther on average to reach the petroleum terminals serviced than under the ORNL analysis. We assumed that this would result in a 3 fold increase in the number of trucks needed to take this volume from the unit221 train facility to the petroleum terminal. XXXX The majority of the number tank trucks which ORNL estimated would be needed are attributed to the transpor t of biofuels from rail receipt facilities to petroleum terminals. Consequently, we believe that a reasonable (albeit conservatively high) estimate of the increase in th e number of tank trucks that would be needed due to our decrease in the number of unit train facilities can be arrived at by multiplying the fraction of biofuels shipped by unit train that is attributed to consolidated unit train terminals (41% of the total volume shippe d by unit train) by the average in crease 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 facilitie s would result in a 23% increase in the number of tank trucks needed compared to that indi cated by interpolation of the results from the ORNL study

Based on this approach, we estimate that 1,940 tank trucks would be needed to transport the volumes of ethanol and cellulosic distillate fuel/renewable diesel fu el under the high-ethanol scenario, 1,720 under the primary mid-ethanol scenario, and 1,620 under the low-ethanol scenario. We subtracted the number of tank trucks which ORNL estimated would be needed under the two reference cases to determine the incr emental number of tank trucks attributed to compliance with the EISA (see Table 1.6 -5 ).

Table 1.6 -5

. 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 estimate that 150 tank trucks would be needed by 2022 to transport the volume of biodiesel that we project will be used to satisfy the RFS2 standards. We estimate that 30 tank trucks would be needed by 2022 to transport the volume of biodiesel projected under the RFS1 reference case and 35 tank trucks under the AEO reference case. Consequently, we attribute the construction of an additional 130 biodiesel tank trucks to the implementation of the EISA under the RFS1 reference case and 120 under the AEO reference case. The total additional

XXXX 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. Deleted: .6-1

Deleted: .6-1222 number of tank trucks for the transport of ethanol, cellulosic distillate fuel/renewable diesel fuel, and biodiesel that we attribute to the implement ation of the EISA is presented in Table 1.6

- 6.

Table 1.6

- 6. Additional Tank Trucks Need ed 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 -7

.

Table 1.6 -7

. Estimated Number of Tank Trucks Needed for Shipment of Butane a

Number of Tank Trucks Need ed to Transport Butane

Low-Ethanol Scenario Primary Mid-Ethanol

Scenario High-Ethanol Scenario

Tank Truck (8,200 gallons) 2,165 3,280 5,530

a If a solution to the current difficulty in blending E85 to meet minimum volatility specifications can not be arrived upon by ASTM International to allow the use of commonly available gasoline blendstocks.

Concerns have been raised in the trade press regarding the ability of the trucking industry to attract a sufficient number of drivers to keep pace with demand. We used estimates of the number of truck drivers required to transport biofuels from the ORNL report as a basis for our estimate of the number of truck drivers that woul d be needed to transport the additional volume of biofuels attributed to the RFS2 program. Given the volume of butan e required for blending into E85, typical travel distances, etc., we estim ated 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 trans port non-ethanol biofuels; this number was approximately 300. When combined with the estimates from OR NL, the number of truc k drivers required to transport biofuel feedstocks and finished product is a pproximately 5,300 drivers. YYYY

YYYY 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. Deleted:

.
Deleted: -2

Deleted:

.
Deleted: -2

Deleted: .6-3

Deleted: .6-3223 According to a 2005 study commissioned by th e American Trucking Association (ATA), the motor carrier industry will face a shortage of qualified prof essional long-haul truck drivers by
2014. 444 In the study, ATA found that the long-hau l, heavy-duty truck tran sportation industry in the United States is currently experiencing a nationa l shortage of 20,000 tr uck drivers and, if the current trend continues, that shortage of long-haul truck drivers could increase to 111,000 by 2014. ATA projected the need for additional 54,000 drivers each year. The trucking industry is active in a number of efforts to attract and re train a sufficient numbe r 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 sta ndards would result in the need for a total of approximately 5,300 additional trucks drivers for the transport of biofuel feedstocks and finished products. Given the relatively small number of new truck drivers needed to transport the volumes of biofuels projected to be used to comply with the RFS2 standards through 2022 compared to the total expected increase in de mand 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 shor tage of truck drivers. Discussions with transport industry officials support this conclusion. However, specially-certified drivers are required to tran sport biofuels because these fuels are classified as hazardous liqui ds. Thus, there may be a heightened level of concern about the ability to secure a sufficient number of such specially-certified drivers to transport biofuels. The trucking industry is involved in efforts to streamline the certification of drivers for hazardous liquids transport. We do not anticipate that the need for special hazardous liquids certification for biofuels truck drivers of would substantially interfere with the ability to transport the projected volumes of biofuels by ta nk truck. We project th at tank truck deliveries of biofuels would typically be ac complished within an 8 hour shift allowing the driver to return home each evening. ZZZZ 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 truck (with typi cal 8 hour shift) may 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 f acilities. We do not expect that such potential concerns would represent a barrier to the impleme ntation 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 cl ose 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 maintenance costs. The potential impact on local road infrastructure and the ability of the road net to be upgraded to handle the increased traffic load is an inherent part in the placement of new biofuel production facilities. Consequently, we expect

ZZZZ 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.224 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 additional storage capacity to accommodate the volume of ethanol, cellulosic distillate fuel/renewable diesel fuel, and biodiesel that we anticipate will be used in response to the RFS2 standards. We estimate that it would be necessary to maintain an inventory level of 15% of the annual consumption of a given biofuel at the terminal level in order to provide a sufficient downstream bu ffer to ensure consistent supply. We chose a working inventory level of 15% ra ther 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 reliance on rail, barge, and truck for the transport of biofuels in our analysis as opposed to use of pipelines for the shipment of petroleum-based fuels. The need for 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 biofuels. We furt her estimate that an additional 30% of storage capacity would be needed as working space to accommodate biofuel deliveries. AAAAA 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 -8

.

Table 1.6 -8

. Total Biofuel Storage Capacity needed at Petroleum Terminals by 2022 to Handle the RFS2 Volumes

Biofuel Tankage (Mbbl)

Low-Ethanol Scenario Mid-Ethanol Scenario High-Ethanol Scenario
Ethanol 81.2 103.9 149.7 Cellulosic Distillate Fuel/ Renewable Diesel Fuel 43.0 30.3 NA

Biodiesel 7.2 7.2 7.2

To estimate of the additional bi ofuel storage tank capacity that should be attributed to the incremental RFS2 biofuel volumes relative to the 2 reference cases, we subtracted the volume which would have been in place regardless of the RFS2 program under the 2 reference cases. The same working inventory and working space estimates were used to estimate the volume of biofuel storage under the reference cases.

AAAAA Petroleum terminals typically allow an additional 30 percent of storage capacity (in relation to the amount provided for working inventory) to accommodate the receipt of petroleum products. Deleted: .7-1

Deleted: .7-1

Deleted:225 Overall demand for the gasoline motor vehicle fuel is expected to remain relatively constant through 2022 whereas demand for compressi on ignition vehicle fuel is anticipated to increase by over 10% over the same time period. 445 We expect that much of the demand for new ethanol storage capacity could be accommodated by modifying storage tanks that had previously been used for the gasoline that would be displaced by ethanol. Due to the lower energy density of ethanol relative to gasoline (67%), we project that only 67% of the demand for new ethanol storage might potentially be accommodated by modifying existing gasoline tanks for ethanol service. Likewise, we anticipate that much of the demand for cellulosic distillate fuel/renewable diesel fuel storage capacity might be satisfied by dedicating storage tanks that would have been constructed to store pe troleum-based diesel fuel to instead store these biofuels. Due to the anticipated lower energy density of cellulosic di stillate fuel relative to petroleum-based diesel fuel (~90% of petroleum-based diesel fuel), we project that only 90% of the demand for new cellulosic distillate/renewable diesel fuel storage might potentially be accommodated by modifying existing gasoline tanks for cellulosic distillate/renewable diesel fuel service. To provide some margin to compensate for the need for a greater degree of new tank construction than that indicated by the above analysis, we assumed that 5% of the tanks which might have been rededicated tanks previ ously 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 miscellaneous modifications to ensure the tank is compatible with ethanol. We assume that no changes would be needed to petroleum-based diesel fuel storage tanks to allow them to be used to store cellulosic distillate fuel/renewable diesel fuel. Since biodiesel storage tanks need to be insulated and heat ed under cold conditions, we assumed that all of the need for additiona l biodiesel storage capac ity would be satisfied through new construction.

The volume of new biofuel storage capacity that we project would be needed as a result of the implementation of the EISA under the 2 reference cases is pres ented in Tables 1.6 -9 and 1.6 -10

. Deleted: .7-2

Deleted: .7-3226 Table 1.6 -9

. 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, New Construction 6.2 4.4 NA

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

Biodiesel, New Construction 5.9 5.9 5.9 All Biofuels, New Construction 29.7 35.8 48.4 All Biofuels, Retrofit ted Tanks 30.9 44.7 74.4 All Biofuels, Redica ted 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 -10

. 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, New Construction 6.2 4.4 NA

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

Biodiesel, New Construction 5.5 5.5 5.5 All Biofuels, New Construction 24.4 36.4 61.8 All Biofuels, Retrofit ted Tanks 7.3 15.2 32.2 All Biofuels, Rededicated Tanks 36.8 25.9 0

a“ Retrofitted” refers to tanks that need significant changes to be made suitable for biofuel storage. “Rededicated” refers to tanks that need essentially no changes to be made suitable for biofuel storage. Deleted: .7-2

Deleted: .7-3227 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. 446 We acknowledge that it may not be possible for some terminals that have become surrounded by urban growth over time to install additional storage tanks within the boundaries of their existing facilities. However, we believe that there are ways to manage this situation. The areas served by existing terminals often overlap. In such cases, one terminal might be space constrained while another serving the same area may be able to install the additional capacity to meet the increase in demand. Terminals with limited biofuel storage could receive truck shipments of ethanol from terminals with more substantial biofuel storage capacity. In cases where it is impossible for existing term inals to sufficiently expand their storage capacity due to a lack of adjacent available land or diff iculties 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 projec t that all terminals that distribute gasoline would install ethanol blending capability in response to the RFS2 standards. We estimate that approximately 91% of terminals that distribute diesel would install biodiesel blending/storage capability under the RFS2 standards. Therefore, in the case of biodiesel, those terminal s that would experience that most difficulty in installing new storage capacity would have some opportunity to forgo bringing biodiesel into their terminal

Another question is whether the storage tank construction industry would be able to keep pace with the increased demand for new tanks that would result from today’s proposal. The storage tank construction industry recently experi enced a sharp increase in demand after years of relatively slack demand for new tankage. Much of this increase in demand was due to the unprecedented increase in the use of ethanol. Storage tank construction companies have been increasing their capabilities which had been pared back during lean times. Given the projected gradual increase in the need for biofuel storage tanks, it seems reasonable to conclude that the storage tank construction industry would be able to keep pace with the projected demand.

Petroleum terminals would need to install additional equipment to blend ethanol, cellulosic distillate fuel/renewable diesel fuel, and biodiesel into petrol eum-based fuels. In the case of ethanol other miscella neous 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/i nsulated under cold conditions. All terminals with biofuel blending capability would need to provide facilitie s for receipt of biofuels via tank truck.

There are currently 1,063 petroleum terminals that carry gasoline. 447 We project that 899 of these terminals (85% of the total) woul d install E10 blending equipment absent the implementation of the RFS2 requi rements in order to support the consumption of 13.18 BGY of ethanol by 2022 under the AEO reference case. This is based on 85% of the gasoline needing to be blended with ethanol in order to consume 13 .18 BGY of ethanol considering the projected use levels of E10 versus E8 5 and total motor vehicle fuel consumption in 2022. 448 We project that essentially all gasoline w ould be either E10 or E85 by 2022 unde r the RFS2 standards. Thus, we228 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 install ethanol blending equipment to meet the RFS2 volumes re lative 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 refere nce case. The volume of ethanol projected to be used under the RFS1 reference case is 53% of the volume projected to be used under the AEO reference case. We estimated that the number of terminals that blend ethanol under the RFS1 reference case is 53% of the number under the AEO refere nce 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. BBBBB 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 rema ining 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-ethanol scenario. By multiplying our 90% estimate of the number of terminals that would need to install E85 under the high-ethanol scenario by 60%/70%, wearrived 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 facilities 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 operators indicates that the modification of E10 blending e quipment to handle E85 primarily involves an upgrade to the blending equipment software. CCCCC We estimate that the vapor recovery systems at all terminals that had not received ethanol before would n eed to be upgraded to handle ethanol-blended

BBBBB A discussion of our E85 use projections is contained in chapter 1.7 of this RIA.

CCCCC Additional ethanol storage and modifications to terminal piping would also be needed to supply additional quantity of ethanol needed to blend E85. Deleted:229 gasoline. The potential need to provide special blendstocks at petroleum terminals for the manufacture of E85 is discussed in Section 1.6.8 of this RIA.

Our estimate of the number of terminals that would install biodiesel blending capability under the RFS2 standards is based on an extrapol ation of the analysis conducted for the NPRM. We estimate that 853 terminals handle diesel fuel. 449 We estimate that approximately 62.5 billion gallons of diesel fuel would be used in 2022. DDDDD Thus, the average diesel throughput per terminal would be approximately 73.2 MGY. In the NPRM analysis, we estimate that on a national average basis biodiesel w ould represent approximately 2.9% of the diesel fuel pool. For the purposes of our calculation of the number of terminals that woul d carry biodiesel, we assumed that 2.9% of the diesel fuel they dispense would be biodiesel. This is likely to result in a conservatively high number of terminals that would need to carry biodiesel, since those terminals that do carry biodiesel would be expected too blend at higher than the national average concentration. Assuming that 2.9% of a terminal’s diesel fuel throughput would be biodiesel, we arrive at an estimate that 377 terminals would n eed to blend biodiesel to support the projected use of 810 MGY of biodiesel assumed to be used by 2022 under the RFS2 standards in the
NPRM.

We estimated the number of terminals that would need to blend biodiesel for our FRM analysis by increasing the NPRM estimate in propor tion to volume of biodies el that we project would be used in the FRM by 2022 relative to that projected in the NPRM (1,671 Mgal/yr / 810 Mgal/yr). By so doing, we estimate that 777 terminals will be needed to blend biodiesel by 2022 to support the use of the biodiesel volume projected to be used in this FRM. We estimate that 200 terminals would need to 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 th e RFS1 reference case and 600 under the AEO reference case.

The Independent Fuel Terminals Operators A ssociation (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. 450 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 implementa tion of the RFS2 standards in order to allow the market sufficient time to adjust. 451 We believe that given the time over which biofuel volumes ramp up under the RFS2 standards, it should be feasible for terminals to adapt sufficiently within the time frame established by the EISA.

1.6.8 Potential Need for Special Blendstocks at Petroleum Terminals for E85

ASTM International is considering a proposal to lower the minimum ethanol concentration in E85 to facilitate meeting ASTM minimum volatility specifications in cold

DDDDD 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.230 climates and when only low vapor pressure gasoline is available at terminals. EEEEE 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 proposal to further decrease the minimum etha nol concentration. Absent such an adjustment, a hi gh-vapor pressure pe troleum-based blendsto ck 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 equipment would be needed at petroleum terminals.

Automated inline butane blending systems located at terminals can be used to blend butane into gasoline before it is blended with de natured 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 vola tility specification for the finished product. The analyzer, variable frequency butane pump, an d supporting equipment are self-contained on a skid-mounted unit, and require at leas t one 60,000 gallon butane storage tank.

We estimated the number of automated inlin e butane blending systems, butane storage tanks, tanks trucks, railcars, trans-loading facilities, and other facility changes needed for butane blending as follows. Of the existing 1,063 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 ble nding 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 tank storage. In the case of the other fifty-percent of the terminals, butane is assumed to be transloaded from railcars to tank trucks for final de livery to terminals. This requires that each terminal have a skid-mounted inline butane blendi ng system and two 60,000 gallon butane tanks. Usable tank volumes are assumed to be 51,000 gallons per tank. Tank trucks are assumed to carry 8,200 gallons of butane. Railcars are a ssumed to carry 31,500 gallons of butane.

Our estimates of the number of tank trucks and railcars requi red to deliver butane varies by control scenario (see Table 1.6 -1 1).

EEEEE Minimum volatility specifications were established by ASTM to address safety and vehicle driveability considerations. Deleted: s

Deleted: .8-231 Table 1.6 -1 1. Estimated Number of Tank Trucks and Rail Cars Needed for Shipment of Butane

Number of Tank Trucks a nd Rail Cars Needed to Transport Butane Low Case Medium Case High Case Tank Truck (8,200 gallons) 2,165 3,280 5,530 Railcar (31,500 gallons) 236 358 602

Instead of lowering the minimum ethanol c oncentration of E85, some stakeholders are discussing establishing a new high-e thanol blend for use in flex-fue l vehicles. Such a fuel would have a minimum ethanol concentration that would be sufficient to allow minimum volatility specifications to be satisfied while using finished gasoline that is already available at petroleum terminals. FFFFF E85 would continue to be marketed in addition to this new fuel for use in flexfuel vehicles when E85 minimum volatility considerations could be satisfied.

We believe that industry will resolve the concerns over the ability to meet the minimum volatility needed for high-ethanol blends used in flex-fuel vehicles in a manner that will not necessitate the use of high-va por pressure blendstocks in th eir 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. GGGGG

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 substan tially 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 ha ve reasonable access to E85 in 70% of the nation by 2022 under the high-ethanol scenario given our projections regarding the population of flexible fuel vehicles (FFVs) and E85 refueling frequencies. 452 Under the primary mid-ethanol scenario we estimate that reasonable access would be needed in 60% of the nation, and 40% under the low-et hanol 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 been 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.

FFFFF Such a new fuel might have a lower ethanol concentration of 60% and a maximum ethanol concentration of 85%.

GGGGG EPA may consider reevaluating its policies regarding the blendstocks used in the manufacture of E85 to facilitate this practice. Deleted: .8-232 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. 453 The National Association of Convenience Stores (NACS) reported that in 2006, 36.6% of the respondents to their survey offered diesel fuel. 454 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 re tailers make most of their money from in-store sales as opposed to fuel sales, it seems likely that more retailers recognized an opportunity to attract additional customers by offering diesel fuel since 1999. In any event, the number of diesel fuel refueling facilities available in 1999 or 2006 has not hindered the use of diesel fuel vehicles. Unlike diesel fuel vehicles that can refuel only on diesel fuel or alternative fuel vehicles that can only be fueled on the alternative fuel, flex fuel vehicles can refuel on gasoline as well as E85. Thus, we believe that fewer E85 stations should be necessary than were provided for diesel fuel. HHHHH

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 th at had been dedicated to mid-grad e gasoline storage to diesel fuel service. A number of retail facilities (40% of the total that installed diesel fuel tanks had low annual diesel throughput vol umes of less than 60,000 gallons per year in 2000. 455 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 se ems reasonable to assume that some fraction of low-volume retailers may not be absolutely necessary to ensure adequate diesel availability. Therefore, somewhat less than 32% of retail facilities might actually be needed to ensure adequate diesel fuel availability. We believe that this comparison to the number of diesel fuel retail facilities available supports our estimate that one in four retail facilities would be sufficient to provide reasonable access to E85.

The National Petroleum News (NPN) estima tes that there were a total of 161,768 gasoline retail facilities in the United States in 2008. 456 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 throughput while maintaining timely access of customers to an E85 dispenser, we estimated that all E85 retail facilities would have 3 E85 dispensers under the hi gh-ethanol scenario. IIIII Under the primary mid-ethanol scenario, we estimate that half of E85 retail facilities would have a single dispenser and the other half would

HHHHH 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.

IIIII Each dispenser has two E85 refueling positions.233 have 2 dispensers. Under the low-ethanol scenario, we estimate that all E85 retail facilities would have a single dispenser. These estimates are based on ensuring that E85 throughput per refueling position is consistent with historical data for gasoline throughput per refueling position. We believe that this approach provides an estima te consistent with ensuri ng that consumers have reasonable access to a E85 refueling position while providing the retailer with sufficient throughput to justify their investment in installing E85 refueling facilities.

The National Association of Convenience Stores (NACS) reports throughput per refueling position. 457 For all types of fuel dispensed, NACS reports that from 2001 through 2006, the annual throughput varied from approxima tely 142,000 to 164,000 gallons per refueling position. These data include reports on the sales of all fuels including premium, mid-grade, and regular gasoline, diesel fuel and other fuels. The most appropriate comp arison 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 offe r 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). JJJJJ 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 no zzles, and other fuels from one pump with one nozzle. By multiplying the percentage of retailers that offer diesel fuel/other fuel by the assumed refueling positions for these fuels where they are present, we arrived at an estimate of 0.9 refueling positions per facility on average dedicated to diesel fuel and other fuel. This translates to an average of 7.7 refueling positions per facility that dispenses gasoline. NACS reports that 92.7% of fuel volumes sold by respondents to their survey is gasoline (of all grades). By dividing 92.7% of the total average throughput for all fuels per facility reported by NACS by 7.7 refueling positions, we arrived at an estima te of annual gasoline throughput per nozzle of 177,000 gallons for 2003. KKKKK

The National Ethanol Vehicle Coalition (NEVC) estimates there are currently 2,095 E85 refueling facilities. 458 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. 459 The Near85 estimate includes only retail facilities. Based on these data, we are assuming that there are approximately 1,300 E85 retail facilities currently in service. By increasing the number of E85 retail facilities by the same proportion as the growth in ethanol use under the AEO reference from now until 2022, we estimate that 4,500 E85 refueling facilities would be in place by 2022 absent the RFS2 standa rds. 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 th e 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

JJJJJ In many cases, we expect that the “other” fuel is kerosene.

KKKKK The year 2003 had the highest average throughput per refueling position over the years 2001- 2006.234 under the REFS1 and AEO reference cases would ha ve a single E85 dispenser (with 2 refueling positions).

To estimate the E85 refueling facility changes which that may be needed to reach the RFS2 volumes, we compared the changes needed to support the use of the total volume of E85 projected to be used under the 3 control scenarios to the E85 refueling facilities needed under the 2 reference cases. Our estimates of the of the E85 facility changes that will take place to reach the RFS2 volumes are contained in Tables 1.6 -12 and 1.6 -13

Table 1.6 -12

. 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 -13

. 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 ne eded each year from 2010 through 2022 under our primary s cenario 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 aggr essive 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. LLLLL To date, no complete E85 dispenser systems have been certified by UL. We

LLLLL See http://ulstandardsinfonet.ul.com/outscope/0087A.html Deleted: .9-1

Deleted: .9-2

Deleted: .9-1

Deleted: .9-2235 understand that all the fuel dispenser components w ith the exception of the hoses that connect to the refueling nozzle have successfully passed the necessary testing. There does not appear to be a technical difficulty in finding hos es that can pass the required testing. Therefore, we anticipate this situation will be resolved once the demand for new E85 facilities is demonstrated. Hence, we believe that the current lack of a UL certification for complete E85 dispenser systems will not impede the installation of the additional E85 facilities that we projected will be needed.

Petroleum retailers expressed concerns about their ability to bear the cost of installing the needed E85 refueling equipment given that most retailers are small businesses and have limited capital resources. They also expressed concern regarding their ability to discount the price of E85 relative to E10 sufficiently to persuade flex ible fuel vehicle owners to choose E85 given the lower energy density of ethanol. Today’s rule does not contain a require ment 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 co sts and that this could become an issue. However, if obligated parties are going to comply with the RFS2 standards, they will have to find a way to get the appropriate incentives to retailers. In addition, the projections regarding the future cost of gasoline relative to ethanol indicate that as crude oil prices rise it may be possible to price E85 more profitably. While the $3 billion total cost for E85 refueling facilities is a substantial sum under our primary E85 facility scenario, it equates to 3 cents per gallon of E85 throughput. MMMMM 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. NNNNN Given the projections regarding ethanol pricing relati ve to gasoline and other fact ors that may tend to encourage ethanol consumption, we believe th at 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. OOOOO

1.6.10 Fuel Distribution Acco mmodations to Support the Intr oduction of E15 Should a Waiver be Granted

We evaluated the changes to the fuel distribu tion 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 cha nges. Our nation’s system of gasoline fuel regulation, fuel production, fuel distribution, an d 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 C AA, there are a number of other actions that would have to occur to bring mid-level blends to retail . This discussion focuses on the changes which may impact the costs associated with the introduction of E15. A number of changes/accommodations would also be needed to federal, state, and local regulations.

MMMMM Our estimates of the cost of the E85 retail facilities that would be needed to support the use of the volume of ethanol that we project would be used under the RFS2 standards is contained in Section 4.2 of this RIA. E85 retail costs were amortized over 15 years at a 7% cost of capital.

NNNNN See Section 1.7.1.2.3 of this RIA for a discussion of government incentives to install E85 retail refueling equipment.

OOOOO This issue is discussed in Section 1.7.1.2.5 of this RIA.236 The CAA provides a 1 pound RVP waiver for et hanol blends of 10 volume percent or less. This waiver was granted at a time when ethanol use was not widespread. Thus, the environmental considerations at the time were relatively minor. Now that the nation is moving to E10 nationwide, the 1 psi waiver may have significant environmental implications for all conventional gasoline. Lacking a similar RVP waiver, a special low-RVP gasoline blendstock would be needed at terminals to allow the 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 cha llenges and costs to the fuel dist ribution system. It should be possible for refiners to formulate a gasoline ble ndstock that would be suitable for manufacturing both mid-level ethanol blends and E10 at the term inal. 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 infrastructure 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-level ethanol blend. However, in most if not all cases this would only involve a modification to the software for the blending system to allow a mid-level as well as an E10 or E0 blend rate rather than necessita ting a physical change to the system. Terminal operators would also need to provide for the receipt and storage of the greater volumes of ethanol needed to manufacture a mid-level ethanol blend. PPPPP

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 substance stored in the system. A number of authorities require that fuel retailers use equipment that has been certified as compatible with the fuel being sold. Such a certification is required by the Occupational Safety and Health Administrati on (OSHA), many local fire mars hals, tank insurance and state tank fund policies, and the pr ovisions contained in many business loan agreements.

Underwriters Laboratories (UL) is the lead ing safety certificati on 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. QQQQQ 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. RRRRR However, UL stated that it could not recertify e quipment that was originally certified for up to

PPPPP 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. QQQQQ The UL announcement can be found at http://www.ul.com/newsroom/newsrel/nr021909.html

RRRRR 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.237 E10 blends for a higher ethanol blend. SSSSS 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 ble nd could demonstrate compliance with the EPA requirement that such systems are compatible with the substance stored in the system. TTTTT The Department of Energy in coordination with UL is conducting testing to evaluate the suitability of existing retail fuel dispensing equipment to accomm odate a mid-level ethanol blend. UUUUU Depending on the results of the OUST and DOE/UL efforts, the authorities referenced above may be encouraged to allow the use of certain existing equipment originally certified for E10 to handle a mid-level ethanol blend. One potential appr oach in lieu of requiring a UL certification might be for AHJs to require that fuel retailers have records to es tablish what type of equi pment is present and to obtain manufacture certifications th at the equipment is suitable fo r a mid-level ethanol blend.

Documenting the manufacturer and model num ber of the various components of their fuel storage and dispensing equipment may be a relatively simple undertak ing 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. VVVVV Many UST installation companies and components manufactures may have gone out of business, further complic ating 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 granted which provides for the use of a mid-level ethanol blend in a subset of vehicles, then E10 would need to continue to be made available for use in vehicles/equipment not covered by the waiver. WWWWW We believe that this might be most

SSSSS 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-certification-pathfor-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.

TTTTT The EPA OUST requirement is located at 40 CFR Part 280.32. Enforcement of this requirement is typically delegated to the State level.

UUUUU This is the above ground equipment commonly referred to as the fuel pump stand or fuel dispenser.

VVVVVThese are the UST components where there may be the most concern regarding compatibility with a midlevel ethanol blend.

WWWWW E0 will also be needed for use in gasoline piston engine aircraft.238 practicably accomplished by switching some or all dispensers of regular gasoline at a retail facility to handle the mid-level ethanol blend. XXXXX The premium dispenser could continue to handle E10 (or E0) for use in legacy vehicles/equipment. YYYYY Some of the nonroad equipment currently requires the use of a premium grade fuel . Thus, premium gasoline would continue to be the “universal fuel” as it is today, capable of being used in an y 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 customers 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 ta nks that are currently interconnected.

If the OUST and DOE evaluations show that cu rrent retail fuel equipment is largely compatible with a mid-level ethanol blend, it ma y be possible for a substa ntial number of retail facilities to introduce a mid-level ethanol blend at a modest cost. If some components of the above ground existing retail hardware are found to be incompa tible with a mid-level ethanol blend, it may be possible for them to be re placed through normal attrition. For example the “hanging hardware” which includes the nozzle and hose from the dispenser is typically replaced every 3 to 5 years. If more extensive modifications are shown to be necessary, the costs could approach those necessary to introduce E85. If this is the case, the costs would tend to inhibit the rapid introduction of a 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 fi rst 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 surroundi ng pricing and the environmenta l implications of fossil fuels has continued to drive ethanol use.

As shown in Table 1.7-1, a record 9.5 billi on gallons of ethanol we re blended into U.S. gasoline in 2008 and EIA is forecasting additional growth in the years to come. According to their recently released Short-Term Energy Outlook (STEO), EIA is forecasting 0.7 million

XXXXX Commenters stated that this arrangement could encourage misfueling if the “premium grade” E10 was substantially more costly than the “regular grade” E15.

YYYYY 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

BBBBBB Under the CAFE program, the production of FFVs provides credits toward meeting the required standards. However, the EPCA incrementally phases out these credits through MY 2019, after which they are no longer available to help demonstrate CAFE compliance. EPA recently proposed similar FFV credits as part of their Rulemaking to Establish Light-Duty Vehicle GHG Emission Standards and Corporate Average Fuel Economy Standards. (74 FR 49454 September 28, 2009) Under the proposed program, the credits would remain available in 2016 and later model years, but the FFV credits would be based on estimated actual use of E85. Deleted:

.
Deleted: ZZZZ Z

Deleted: predicts239 barrels of daily ethanol use in 2009, which e quates to 10.7 billion gallons. The October 2009 STEO projects that total ethanol usage (domes tic production plus imports ) will reach 12.1 billion gallons by 2010

. 460

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)



### 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

. 461 

### The vast majority is blended as E10 or 10 volume perc ent ethanol, although a small amount is blended as E85 for use in flexible fuel vehicles (FFVs). California, the largest U.S. consumer of gasoline is yet to reach 100% E10 saturation. Historically, the state has only blended ethanol into gasoline at 5.7% vol%, limited by its Predictive Model blending constraints. However, California has since adjusted its model and effective January 1, 2010, ethanol blending is expected to increase to 10%. A recent HART publication estimating ethanol penetration by state is provided in Figure 1.7-1. 462 Formatted: Don't keep with next Deleted:

.

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. AAAAA A

### 240 Figure 1.7-1. E10 Market Penetration by State

Complete saturation of the gasoline market with E10 is referred to as the ethanol “blend wall.” The height of the blend wall in any given year is directly related to gasoline demand. In AEO 2009, EIA projects that gasoline energy demand will peak around 2013 and then start to taper off due to vehicle fuel economy improvements. As shown below in Figure 1.7- 2 , not only is EIA forecasting a flattening of gasoline energy demand in the future due to vehicle improvements, AEO 2009 also shows an additional decline due to the recent economic downturn. This is a considerably different projection of the future than EIA made in their prior forecasts. Although we have presented AEO 2008 and AEO 2007 for illustrative purposes, the final release of AEO 2009 is the basis for all energy and ethanol consumption calculations utilized in this analysis. Formatted: Indent: First line: 0.5" Deleted:

Deleted: 1

Deleted: but

### 241 Figure 1.7- 2. Projected Gasoline Energy Demand 463

0 5 10 15 20 25

2 00

4

2 00

5 200

6

2 00

7

2 00

8

2 0 09

2 01

0

2 01

1 2 0 12

2 01

3

2 01

4

2 0 15

2 01

6

2 01

7 2 0 18

2 01

9

2020 2021 2 02

2

2023 2024 2 0 25

2026 2027 202

8

2029 2030

YearMotor Gasoline + E85 Energy (Quadrillion BTUs)

AEO 2007

AEO 2008

AEO 2009 Final



### 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 (refer ahead to Figure 1.7-3) . There are many challenges associated with getting beyond the ethanol blend wall and consuming more than 14- 15 billion gallons including rapid growth in FFV/E85 infrastructure, problems with meeting ASTM specs, testing and potential approval of mid-level blends, etc. As such, as discussed in Sections 1.4.3 and 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 st andard. The benefit of synthetic hydrocarbon fuels is that there is virtually no blend wall issue, they are fungible with existing fuel infrastructure and they can be priced at parity with petroleum at retail. In many ways, they are essentially drop-in replacements for gasoline a nd diesel. However, like all second-generation biofuels, there are technological and financial hurdl es that need to be overcome before biomassbased synthetic hydrocarbon fuels can be brought to market.

These factors make it difficult to project the mix of renewable fuels types that will be used in the future to meet the RFS2 standards. To address the uncertainty of which fuels will be used, we have analyzed three control cases with va rying levels of ethanol as part of this final rule. As shown below in Table 1.7.2, total ethanol usage (corn, imported and cellulosic) could

range from 17.5 to 33.2 billion gallons in 2022. Formatted: Keep with next Deleted: 1

Deleted:

Deleted: earlier in Section

Deleted: there’s

Deleted: future

Deleted: in the future under RFS2

Deleted: ranges

### 242 Table 1.7-2

. Potential Ethanol Usage Scenarios Under RFS2

Scenario 2022 Total Ethanol Use

RFS1 Reference Case 7.1

AEO 2007 Reference Case 13.2

Low-ETOH Control Case 17.5 Mid-ETOH Control Case (Primary) 22.2 High-ETOH Control Case 33.2



### Under the primary control case, ethanol consumption will need to be about three times higher than RFS1 levels, more than twice as much as today’s levels, and about 9 billion gallons higher than the ethanol consumption predicted to occur in 2022 absent RFS2 (according to AEO 2007). A summary of the projected ramp up in ethanol usage in each of these three cases compared to the blend wall is provided in Figure 1.7- 3. For more information on how the control case volumes were derived, refer to Section 1.2 of the RIA. Deleted: 2.

### 243 Figure 1.7- 3. Projected Increase in Ethanol Under RFS2

0 5 10 15 20 25 30 35

2 0 10 201 1 2 01

2 2013 2014 2 01

5 2016 2017 2 01

8 2 01

9 2020 2021 2 02

2

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 expected, the more aggressive the ethanol usage, the sooner the nation will hit the blend wall. As shown above, the nation is expected to hit the blend wall in 2013 under our high- ethanol control case, in 2014 under our primary mid- ethanol control case and closer to 2015 under our low- ethanol control case. Regardless, to meet today’s RFS2 requirements using increased volumes of ethanol we are going to need to see growth in the FFV fleet , in E85 infrastructure, and in E85 refueling ra tes (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 versus other renewable fuels. As expected, the lowethanol case would require only moderate change s in FFV/E85 infrastructure and refueling whereas the high- ethanol case would require very dramatic changes and likely a mandate.

Once the nation gets past the blend wall, more ethanol will need to be blended as E85 and less as E10. FFV owners who were formerly refueling on E10 will need to start filling up on E85. As shown in Figure 1.7- 4 , under our primary mid-ethanol 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. Deleted: 2

Deleted: hits

Deleted: ETOH

Deleted: ETOH

Deleted: ETOH

Deleted: the

Deleted: vs

Deleted: ETOH

Deleted: ETOH

Deleted: 3

### 244 Figure 1.7- 4

. 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 volume s 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 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 consumption would come from the mid-level ethanol blends (E15 or E20) since they are not currently approved for use in non-FFVs. However, in light of the Growth Energy waiver request, we discuss how approval of E15 for use in conventional vehicles could help the nation postpone the blend wall in Section 1.7.6.

1.7.2 Projected Growth in Flexible Fuel Vehicles

Over the years there have been several policy attempts to increase FFV sales including Corporate Average Fuel Economy (CAFE) credits BBBBBB 

### and government fleet alternative-fuel vehicle requirements. As a result, there are an estimated 8 million FFVs on the road today, up Deleted: 3

Deleted: ¶ ¶

Deleted: quite

### 245 from just over 7 million in 2008

. CCCCCC,464 

### While this is not insignificant in terms of growth, FFVs continue to make up less than 4 percent of the total gasoline vehicle fleet.

According to EPA certification data, over one million FFVs were sold in both 2008 and 2009. Despite the recession and current state of the auto industry, automakers are incorporating more and more FFVs into their light-duty production plans. While the FFV system (i.e., fuel tank, sensor, delivery system, etc.) used to be an option on some vehicles, most are moving in the direction of converting entire product lines over to E85-capable systems. Still, the number of FFVs that will be manufactured and purchased in future years is uncertain.

To measure the impacts of the RFS2 program, we considered three different FFV production scenarios that might correspond to the three biofuel control cases analyzed for the final rule. For all three cases, we assumed that total light-duty vehicle sales would follow AEO 2009 trends. The latest EIA report suggests lower than average sales in 2008-2013 (less than 16 million vehicles per year) before rebounding and growing to over 17 million vehicles by 2019 as shown below in Figure 1.7- 5. 465 

### We also used EIA’s car-to-truck sales split adjusted for NHTSA’s new car definition beginning in 2011

. DDDDDD 

### Accordingly, by 2022, cars are expected to comprise over 70% of new light-duty vehicle sales.

CCCCCC Based on DOE’s Energy Efficiency and Renewable Energy (EERE) FFV sales data for 1998-2005 and EPA’s vehicle certification data for 2006-2008 FFVs adjusted to account for scrappage. Vehicle survival rates taken from EPA’s proposed Rulemaking to Establish Light-Duty Vehicle GHG Emission Standards and Corporate Average Fuel Economy Standards (“EPA’s Proposed Light-Duty Vehicle GHG Rule”).

DDDDDD According to NHTSA’s 2011 Rule (73 FR 16615 March 28, 2008), beginning in MY 2011, 2WD versions of SUVs are no longer classified as off-highway capable light trucks under 49 CFR § 523.5(b), simply because the SUV also comes in a 4WD version. Based on an estimate used in EPA’s Proposed Light-Duty Vehicle GHG Rule, approximately 22% of the forecasted AEO 2009 light-duty truck sales are cars based on the new NHTSA definition. Deleted:

.

Deleted: 4.

Deleted:

.

### 246 Figure 1.7- 5

. 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 2 0 07 2 0 08 2 0 09 2 01

0 2 01

1 2 01

2 2 01

3 2 01

4 2 01

5 2 01

6 2 01

7 2 01

8 201 9 202 0 202 1 2022

Model YearLight-Duty Vehicle Sales

Trucks

Cars

NPRM



### Although we assumed that total vehicle and car/truck sales would be the same in all three cases, we assumed varying levels of FFV production. For our low-ethanol control case, we assumed steady FFV growth according to AEO 2009 predictions

. 466 

### For our primary midethanol control case, we assumed increased FFV sales under the presumption that GM, Ford and Chrysler (referred to hereafter as the “Detroit 3”) would follow through with their commitment to produce 50% FFVs by 2012. Despite the current state of the economy and the hardships facing the auto industry, the Detroit 3 appear to still moving forward with their voluntary FFV commitment

. 467 

### And finally, for our high-ethanol control case, we assumed a theoretical 80% FFV mandate based on the Open Fuel Standard Act of 2009 that was reintroduced in Congress on March 12, 2009. 468 

### Based on reduced vehicle sales and gasoline demand, we believe an FFV mandate would be the only viable means for consuming the 32.2 billion gallons of ethanol in 2022 required under the high-ethanol control case.

For the two reference cases, we assumed more modest business-as-usual growth in FFV sales. For the RFS1 reference case, we assumed that automakers would continue to make about 8% of all light-duty vehicles FFVs (current 2008 marketshare based on EPA certification data). For the AEO 2007 reference case, we assumed FFV growth according to EIA’s AEO 2007 predictions. 469 

### The annual FFV sales assumptions for our three control cases and two reference Deleted: 4

Deleted: business-as-usual

Deleted:

. EEEEEE

Deleted:

. FFFFFF

Deleted: recently

Deleted:

.

Deleted: All three sets of FFV production assumptions are presented in Table 1.7-5 (below) and more information on our primary case is presented below.

### 247 cases are presented below in Table 1.7-3. Mo re information about FFV cost and assumptions made with respect to our primary mid-ethanol control case are presented below.

We estimate that the cost to produce FFVs could be anywhere from $50 to $100 per vehicle, depending on the vehicle and how many FFV-capable systems the automaker is producing. Current estimates suggest that the per-FFV cost could easily be as high as $100

. HHHHHH470 

### However, in the event of a hypothetical mandate, automakers would likely find a more economical way to mass produce the necessa ry ethanol-compatible fuel tanks, sensors, etc. As such, we assigned higher per-vehicle FFV production costs in the low- ethanol control case and lower production costs in the high- ethanol case. For more on this rationale and the resulting FFV production costs, refer to Section 4.2 of the RIA.

Table 1.7- 3

. Annual FFV Sales Assumptions

RFS1
Based on Today's
Marketshare AEO 2007
Based on AEO
2007 Predictions Low-ETOH
Based on AEO
2009 Predictions Mid-ETOH
Based on 50%

Domestic 3
Commitment High-ETOH
Based on OFS

Mandate in

Congress

2010 983,267 1,669,998 1,253,426 1,848,835 3,617,298
2011 1,083,940 1,746,847 1,598,610 2,661,252 5,439,471
2012 1,162,875 1,768,321 1,903,862 3,523,548 7,393,103
2013 1,234,554 1,795,684 2,251,284 3,740,737 9,418,573
2014 1,281,162 1,826,871 2,523,575 3,881,960 11,403,172
2015 1,306,173 1,817,706 2,693,557 3,957,744 13,286,614
2016 1,309,814 1,817,699 2,761,794 3,968,776 13,323,649
2017 1,321,421 1,826,073 2,804,322 4,003,948 13,441,727
2018 1,334,395 1,834,957 2,929,336 4,043,259 13,573,697
2019 1,348,016 1,855,352 2,825,574 4,084,529 13,712,247
2020 1,358,903 1,899,794 2,771,285 4,117,519 13,822,998
2021 1,352,943 1,913,799 2,669,883 4,099,459 13,762,369
2022 1,351,996 1,913,938 2,607,584 4,096,590 13,752,738 Reference Cases Control Case FFV Production

For our primary mid- ethanol control case, we assumed that The Detroit 3 would continue to comprise 45% of total light-duty vehicle sales – 2008 production levels less Hummer, Landrover, Jaguar, Saab, Saturn, and Volvo (brands that were recently or are in the process of being sold off). We assumed that domestic auto makers would continue to dominate truck sales and car sales would gradually increase to allow The Detroit 3 to continue to maintain 45% marketshare in future years. With respect to FFV sales, we assumed that the Detroit 3 would follow through with their FFV commitment and increase FFV production from 16% of total sales

HHHHHH According to the Department of Energy (DOE), conventional gasoline engines need to be modified slightly (at an additional cost of about $100) to handle higher blends of ethanol. Deleted:

. GGGGG G

Deleted: it’s

Deleted: that automakers would

Deleted: as explained further in Section 4.2 of the RIA,

Deleted: ETOH

Deleted: ETOH

Deleted: cost analysis, as well as assumptions made for the control cases,

Deleted: 5

Deleted: ETOH

### 248in 2008 to 50% of total sales in 2012. With respect to vehicle type, we assumed that about twothirds of the Detroit 3’s FFV sales would be tr ucks – based on histor ical sales and 2009 MY offerings. Under our primary mid- ethanol scenario, as shown in Table 1.7- 3 , Detroit 3 and nondomestic FFV sales amount to just over 4 million per year in 2017 and beyond.

We assumed that non-domestic automakers would continue to maintain 55% marketshare in 2009 and beyond (based on adjusted 2008 production levels). Although non-domestic automakers have not made any official FFV production commitments, Nissan, Toyota, Mercedes, Izuzu, and Mazda all included at least one flexible fuel vehicle in their 2009 model year offerings

. 471 

### We do not currently anticipate that the non-domestic automakers will follow through with an FFV commitment. However, it seems reasonable that we could expect a small amount of FFV growth in the future. As such, for our primary mid-ethanol control case, we assumed that non-domestic FFV production would grow from 1% in 2008 to 2% in 2009 and future years based on current FFV offerings. With respect to FFV vehicle type, we assumed about equal car and truck FFV sales (52% and 48% , respectively) based on 2008 sales.

Using the annual FFV sales estimates in Table 1.7- 3 and applying the car/truck splits, our standard factors for annual VMT and scrappage, and projected vehicle fuel economy (based on EPA’s proposed Light-Duty Vehicle GHG Rule 472 

### ), we estimate that the maximum percentage of fuel (gasoline/ethanol mix) that could feasibly be consumed by FFVs in 2022 would be about 20% under our mid- ethanol control case. Under our low- ethanol control, the 2022 fuel fraction was estimated at 14%. And under the high- ethanol control case, with the FFV mandate, the fuel fraction was 56% in 2022. A summary of the FFV fuel fraction over time for each of these scenarios is presented in Figures 1.7- 6 through 1.7- 8

.

LLLLLL Based on National Petroleum News gasoline station estimate of 161,768 in 2008. Deleted: ETOH

Deleted: 5

Deleted:

. IIIII I

Deleted: FFV

Deleted: 5

Deleted: the recentlyDeleted: Greenhouse Gas

Deleted: JJJJJ J ),

Deleted: ETOH

Deleted: ETOH

Deleted: ETOH

Deleted: 5

Deleted: 7

Deleted: ¶ Figure 1.7-5¶

Lo w

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

2010 2011 2012 2 0Gasoline Fuel Fraction

Nonroad, Mot o

### 249 Figure 1.7-6

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 1.7-7

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 FFVs Formatted: Left

### 250 Figure 1.7-8

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/vehicles that might be capable of handling E15 in the event of a waiver. The basis for these assumptions and more information on the data sources is presented in Section 1.7.6.

1.7.3 Projected Grow th in E85 Access

According to the National Ethanol Vehicle Coalition (NEVC), there are currently 2,100 gas stations offering E85 in 44 states plus the District of Columbia

. 473 

### While this represents significant industry growth, it still only translates to 1.3% of U.S. retail stations nationwide carrying the fuel. LLLLLL 

### As a result, most FFV owners clearly do not have reasonable access to E85. For our FFV/E85 analysis, we have defined “reasonable access” as one-in-four pumps offering E85 in a given area. MMMMMM 

### 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). NNNNNN

MMMMMM For a more detailed discussion on how we derived our one-in-four reasonable access assumption, refer to Section 1.6 of the RIA. For the distribution cost implications as well as the cost impacts of assuming reasonable access is greater than one-in-four pumps, refer to Section 4.2 of the RIA.

NNNNNN 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). Deleted:

. KKKKK K

### 251 There are a number of states promoting E85 usage by offering FFV/E85 awareness programs and/or retail pump incentives. A growing number of states are also offering infrastructure grants to help expand E85 availability. Currently, 10 Midwest states have adopted a progressive Energy Security and Climate Stewardship Platform

. PPPPPP,474 

### The platform includes a Regional Biofuels Promotion Plan with a goal of making E85 available at one third of all stations by 2025. In addition, the Stimulus Bill recently increased the existing federal income tax credit from $30,000 or 30% of the total cost of improvements to $100,000 or 50% of the total cost of needed alternative fuel eq uipment and dispensing improvements

. 475



### Given the growing number of subsidies, it is clear that E85 infrastructure will continue to expand in the future. However, like FFVs, we expect that E85 station growth will be somewhat proportional to the amount of ethanol realized under the RFS2 program. As such, we analyzed three different E85 growth scenarios for the final rule that could correspond to the three different RFS2 control cases. As an upper bound for our high-ethanol control case, we maintained the 70% access assumption we applied for the NPRM. This translates to about 1:6 stations nationwide.

PPPPPP The following states have adopted the plan: Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Missouri, Ohio, South Dakota and Wisconsin.

SSSSSS Fleet average VMT and MPG estimates based on modeling assumptions used in the Proposed Light-Duty Vehicle GHG Rule. Deleted:

. OOOOOO

Deleted:

. QQQQQQ

### 252 As explained in the NPRM, one way to provide 70% of the nation with reasonable 1-in-4 access would be to make it available in urban areas. For analysis purposes, we defined “urban”

areas as:

• 

### The top 150 metropolitan statistical areas according to th e U.S. Census Bureau and/or counties with the highest 150 VMT projections according the EPA MOVES model.

• 

### Federal RFG areas

• 

### Winter oxy-fuel areas

• 

### Summertime low-RVP areas

• 

### Other relatively populated cities in the Midwest. Cities with populations greater than 100,000 people in states with a potential ethanol surplus in 2022.

For an illustration of the urban areas representing about 70% of the nation’s VMT, refer to Figure 1.7- 9

Figure 1.7- 9

. A Look at 70% E85 Access - Concentrating Pumps in Urban Areas

.

For our other control cases we assumed access to E85 would be lower with the logic that retail stations (the majority of which are in dependently owned and operated and net around Deleted: 8

Deleted: 8

### 253 $30,000 per year) would not invest in more E85 infrastructure than what was necessary to meet the RFS2 requirements. As explained in Section 4.2.1.1.9 of the RIA, the cost to install E85 could be anywhere from $131,000 to $177,000 per station depending on the configuration and number of dispensers. For our primary mid-ethanol control case we assumed reasonable access would grow from 4% in 2008 to 60% in 2022 and for our low-ethanol control case we assumed that access would only grow to 40% by 2022. As a simplifying assumption, we assumed a linear phase-in as shown below in Figure 1.7- 10. As discussed in Section 1.6, we believe these E85 growth scenarios are possible based on our assessment of distribution infrastructure capabilities. For more on the number of new E85 stations compared to the reference cases and the associated cost, refer to Section 4.2 of the RIA.

Figure 1.7- 10

. Projected Growth in 1-in-4 Station Access to E85

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

20 1 0 2011 2012 2013 2014 2 015 2 016 2017 2018 2019 2020 2 021 2 02

2

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 just over 7 million FFVs on the road in 2008. If all FFVs refueled on E85 100% of the time, this would translate to about 8.3 billion gallons of E85

use. This is based on the assumption that the average FFV in 2008 traveled about 16,500 miles and got about 19 miles per gallon of gasoline under actual in-use driving conditions. SSSSSS,476 Deleted: 9.

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### 254 The estimate also assumes is takes about 1.3 gallons of E85 for an FFV to travel the same distance as a gallon of gasoline due to the difference in energy density of the fuels. TTTTTT



### Although we computed the theoretical E85 usage potential to be around 8.3 billion gallons in 2008, according to EIA, actual E85 usage was only about 12 million gallons in 2008

. VVVVVV,477 

### This means that, on average, FFV owners were only tapping into about 0. 15 % of their vehicles’ E85/ethanol usage potential. Assuming only 4% of the nation had reasonable one-in-four access to E85 in 2008 (as discussed in Section 1.7.3 ), this equates to an estimated 4 % E85 refueling frequency for those FFVs that had reasonable access to the fuel.

There are several reasons behind today’s low E85 refueling frequency. For starters, many FFV owners may not know they are driving a vehicle that is capable of handling E85. As mentioned earlier, more and more automakers are starting to produce FFVs by engine/product line, e.g., all 2008 Chevy Impalas are FFVs

. 478 

### Consequently, consumers (especially brand loyal consumers) may inadvertently buy a flexible fuel vehicle without making a conscious decision to do so. And without effective consumer awaren ess programs in place, these FFV owners may never think to refuel on E85. In addition, FFV owners with reasonable access to E85 and knowledge of their vehicle’s E85 capabilities may still not choose to refuel on E85. They may feel inconvenienced by the increased refueling re quirements. Based on its lower energy density, FFV owners will need to stop to refuel 22% more often when filling up on E85 over E10 (and 24% more often when refueling on E85 over conventional gasoline). XXXXXX 

### In addition, some FFV owners may be deterred from refueling on E8 5 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, we’ll also need to see a dramatic increase in the FFV E85 refueling frequency relative to today. Based on the FFV and retail assumptions presented in Sections 1.7.2 and 1.7.3, our analysis suggests that FFV owners with reasonable access to E85 would need to refuel on it 42-70% of the time, depending on the scenario (refer to Figure 1.7- 11 ). This is a significant increase from today’s estimated 4 % refueling frequency.

TTTTTT Assuming E85 contains approximately 74 vol% denatured ethanol on average (77,012 BTU/gal) and 26 vol% of E0 gasoline (115,000 BTU/gal).

VVVVVV 0.007 quadrillion BTUs of ethanol from E85 (from AEO 2009) converted into Bgal using EIA’s HHV (84,262 BTU/gal) and divided by 0.74 (EIA’s assumed average ethanol content of E85).

XXXXXX 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. Deleted: around

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### 255 Figure 1.7- 11

. Necessary FFV E85 Refueling Rates (Given 1-in-4 Access to Fuel)

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

201 0 2 01

1 2 01

2 2013 2 0 14 2015 2016 2 0 17 2018 2019 2 02

0 202 1 2 02

2

Year% of Time FFVs Refuel on E85 (Given Access) Low-ETOH: AEO 2009 FFVs, 40% Access to E85

Mid-ETOH: Committed FFVs, 60% Access to E85

High-ETOH: Mandated FFVs, 70% Access to E85 Max = 70%

Max = 42% Max = 58%



### As shown above, modeling an FFV mandate and E85 station access reaching 70% by 2022, results in the lowest required FFV E85 refueling frequency (42%) for the high- ethanol control case. Similarly, the infrastructure assumptions modeled for the low- ethanol 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 an d E85 access constant for all three control cases (i.e., applied more aggressive infrastructure assumptions across the board), we would have come up with the lowest required FFV E85 refueling frequency for low- ethanol case and the highest requirements for the high- ethanol case. The computed required refueling frequency would also look more linear. However, this would mean large investments in FFV production and E85 refueling infrastructure despite low demand for E85. We figured that, at costs of up to $100 per FFV and as much as $177 ,000 per E85 station, the nation would not build more FFV/E85 infrastructure than what was needed to meet the RFS2 requirements Regardless, in order for any significant increase in FFV E85 refueling rates to occur, there will need to be an improvement in the current E85/gasoline price relationship.

1.7.5 Market Pricing of E85 Versus Gasoline Deleted: 10

Deleted: ETOH

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Deleted: ETOH

Deleted: ETOH

Deleted: (refer back to Section 1.7.2)

Deleted: $23

Deleted: outlet (refer to Section 4.2.1.1.9)

### 256 According to an online fuel price survey, E85 is currently priced almost 40 cents per gallon or about 15% lower than regular grade conventional gasoline

. 479 

### To increase our nation’s E85 refueling frequency to the levels described above, E85 needs to be priced competitively with (if not lower than) conventional gasoline based on its reduced energy content, increased time spent at the pump, and limited availability. Overall , we estimate that E85 would need to be priced about 25% lower than E10 at retail in 2022 in order for it to make sense to consumers ( as outlined below )

.
First, E85 needs to be priced lower than E10 based on its reduced energy density . For our ethanol consumption analysis and this E85/gasoline price assessment, denatured ethanol was assumed to have a lower heating value of 77 ,012 BTU/gal based on the new 2% denaturant requirement. AAAAAAA,480 

### Conventional gasoline (E0) was assumed to have an average lower heating value of 115,000 BTU/gal. E10 was assu med to contain 10 vol% denatured ethanol and 90 vol% gasoline and E85 was assumed to contai n 74 vol% denatured ethanol and 26 vol% gasoline on average (based on EIA’s AEO 2009 report). 481 

### As shown below, E85 would need to be priced about 78% lower than E10 based on its reduced energy density.

% 1

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

In 2022, based on EIA’s $116/ba rrel crude oil projections, w holesale gasoline (E10) is expected to be pr iced at $3.42/gallon. BBBBBBB Factoring in transportation costs, taxes, and markup at retail (about $0.60/gallon tota l), gasoline can be expected to be priced at $4.02/gallon at retail in 2022. To be cost-competitive with gasoline, E85 would have to be priced at least 78% lower than E10 at retail, or around $3.14/gallon.

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. 482 Adjusting the 2005 VOT estimate to 2007 dollars, yields a $31.61 per hour estimate. Assuming it takes about six minutes for a 15-gallon refill, E85 needs to be priced an additional $0. 05 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 refu el on E85 over gasoline, there needs to be an

AAAAAAA The 2008 Farm Bill1 contained a provision that stipulates the full value of the Volumetric Ethanol Excise Tax Credit (VEETC) is only available to blenders when using fuel ethanol denatured at a maximum of 2%.

BBBBBBB Refer to Table 4.4-9 in Section 4.4 of the RIA. Deleted:

. YYYYYY

Deleted: On average

Deleted: gasoline

Deleted: about 78% less

Deleted: as shown below. ZZZZZZ In 2022, based on $116/gallon crude oil projections, gasoline can be expected to be around $4.10/gallon at retail. That means E85 should be priced at about $3.20/gal.

Deleted: 04

Deleted:

.257 additional price incentive at the pump acco rding to a 1997 Oakridge National Lab report. CCCCCCC,483 As shown below in Figure 1.7- 12 , 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- ethanol control case), it needs to be gi ven 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.



### Figure 1.7- 12

. 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 around $ 2.95 per gallon ($3. 14 /gal - $0. 05 /gal - $0.14/gal) in order for it to be competitive with $4. 02 gasoline in 2022. Essentially E85 would need to be pri ced 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 for the most past , as long as crude oil prices remain high (as projected by AEO 2009), it should look attractive to re finers as a blendstock. Based on our retail

CCCCCCC Although the 1997 David Greene study was based on asking consumers about a hypothetical fuel that “works just as well as gasoline”, we assumed that Figure 6 from the report (pictured) could also be used to determine the retail price incentive given to E85 to account for its limited availability . As explained in the preceding text, this was in addition to the incentives assigned to E85 to account for its reduced energy density and additional time spent at the pump. Deleted: 11

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Deleted: 10258 cost calculations , summarized in Figure 1.7-13 below , ethanol would have to be priced at $1.97/gallon in order for it to be attractive to refiners for E85 blending in 2022.



### Figure 1.7-13. Required Ethanol Pricing Needed in 2022 to Encourage E85 Blending



### TAX

402 c/gal 3 c/gal 342 c/gal 47 c/gal



### Gasoline Pricing

E85 Pricing

TAX

402 c/gal 47 c/gal 3 c/gal 235 c/gal E85

X 0.78 FE effect - 5 c/gal (refueling time) 295 c/gal for E85 235 c/gal = 0.26*342 + 0.74* 197

Ethanol would have to be priced at 197 c/gal or less to be attractive to refiners in 2022. 10 c/gal

10 c/gal E10

- 11 c/gal (limited availability)

According to the DTN Ethanol Center, the current rack price for ethanol is around $ 2.20 /gallon

. 484 However, as explained in Section 4.4 of the RIA, we project the average ethanol delivered price (volume-weighted average produc tion cost of corn, cellulosic and imported ethanol plus distribution) will come down to around $1.67/gallon in 2022 under our mid-ethanol primary control case. DDDDDDD 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 in the future.



### 1.7.6 Consideration of >10% Ethanol Blends

On March 6, 2009, Growth Energy and 54 ethanol manufacturers submitted an application for a waiver of the prohibition of th e introduction into commerce of certain fuels and fuel additives set forth in section 211(f) of the Ac t. This application seeks a waiver for ethanolgasoline blends of up to 15 percent by volume ethanol. On April 21, 2009, EPA issued a Federal Register notice announcing receipt of the Grow th Energy waiver application and soliciting comment on all aspects of it

. 485 On May 20, 2009, EPA issued an additional Federal Register

DDDDDDD Refer to Table 4.4-4 in Section 4.4 of the RIA.

HHHHHHH 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 Deleted: (considering fuel taxes, markup at retail, and distribution)

Deleted: around $2/gal

Deleted: The

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Deleted:

.

Deleted: based on energy content

Deleted: As explained in the preamble,

on

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. EEEEEEE259 notice extending the public comment period by an additional 60 days

. 486 The comment period ended on July 20, 2009, and EPA is now evaluati ng the waiver application and considering the comments which were submitted.

In a letter dated November 30, 2009, EPA no tified the applicant th at, because crucial vehicle durability information being developed by the Department of Energy would not be available until mid-2010, EPA would be delaying its decision on the application until a sufficient amount of this information could be included in its analysis so that the most scientifically supportable decision could be made. 487 As the current Growth Energy waiver application is still under review, EPA believes it is appr opriate to address aspects of the mid-level blend waiver in its decision announcement on the waiver applica tion as opposed to dealing with the comments and evaluation of the poten tial waiver in the preamble of today’s final rule.

Although EPA has yet to make a waiver d ecision, since its appr oval 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 th e 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 ne ed to continue to co-exist for legacy and non-road equipment based on consum er demand regardless of any waiver decision. As shown in Figures 1.7-5 through 1.7-7, the percentage of nonroad gasoline consumption was held constant at about 8% based on inform ation obtained from ORNL’s 2009 Transportation Energy Data Book

. 488 For analysis purposes, we assumed E10 w ould 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 bl ended from the two to make a 12.5 vol% blend (E12.5). In addition, we assumed that some E 15-capable vehicles would continue to choose E10 or E12.5 based on today’s premium and mi dgrade sales shown below in Table 1.7- 4.



### Table 1.7- 4

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### Mid-level Ethanol Blend Assumptions

Grade of Gasoline % of CG
Sales* Ethanol Content

Regular 86.5% 10.0%

Midgrade 5.0% 12.5%

Premium 8.5% 15.0%
*Petroleum Marketing Annual 2008, Table 45

In the event of a partial waiver, it is unclear how long it would take for E15 to be fully deployed or whether it would ever be available nationwide. For analysis purposes, we made the simplifying assumption that E15 would be fully phased in and available at all retail stationsnationwide by the time the nation hit the blend wall, or by around 2014 for our primary midethanol control case shown below in Figure 1.7-14.



### Figure 1.7-14 Max E15 Ethanol Consumption Compared to Mid-Ethanol Control Case

0 5 10 15 20 25 30 35 40

2010 2 01

1 2012 2 01

3 2 01

4 2015 2 01

6 2017 2 01

8 2 01

9 2020 2 02

1 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 waiv er for E15 could increase th e ethanol consumption potential from conventional vehicles to about 19 billion gallons. Under our primary RFS2 control case (shown in Figure 1.7-14), E15 could postpone the blend wall by up to five years, or to 2019. Although E15 would fall short of meeting the RF S2 requirements under this scenario, it could provide interim relief while the country ramps up non-ethanol cellulosic biofuel production and/or expands E85/FFV infrastructure. Formatted: Don't keep lines together Deleted: ETOH

Deleted: 12.¶ ¶ Figure 1.7-12¶ Max E15 Ethanol Consumption Compared to Mid-ETOH Control Case ¶

0 5 10 15 20 25 30 35 40

2010 2 01

1 2012 2 01

3Billion Gallons of Fuel (ETOH-Eq) Non-Ethanol Biofuels

Cellulosic Ethanol

Imported Ethanol

Corn Ethanol

E15 Blendwall (Partial W a

E10 Blendwall

¶ As modeled, a partial waiver for E15 could increase the ethanol consumption potential from conventional vehicles to about 19 billion gallons. Under our primary RFS2 control case (shown in Figure 1.7-12), E15 could postpone the b lend wall by up to five years, or to 2019. Although E15 would fall short of meeting the RFS2 requirements under this scenario, it could provide interim relief while the country ramps up non-ethanol cellulosic biofuel production and/or expands E85/FFV infrastructure. ¶ ¶ Under our low-ETOH case, a partial waiver for E15 could eliminate the need for additional FFV/E85 infrastructure all together. Similarly, for our high-ETOH case, E15 could postpone the blend wall by about 3 years from 2013 to 2016.

Deleted:

Deleted: Figure 1.7-13¶ Max E15 Ethanol Consumption Compared to Low-ETOH Control Case¶ ... [20]

... [21]261 Under our low-ethanol case, a partial waiver for E15 could eliminate the need for additional FFV/E85 infrastructure all together. Si milarly, for our high-ethanol case, E15 could postpone the blend wall by about 3 years from a bout 2013 to 2016. These scenarios are shown in Figures 1.7-15 and 1.7-16.262 

### Figure 1.7-15 Max E15 Ethanol Consumption Compa red to Low-Ethano l Control Case

0 5 10 15 20 25 30 35 40

2010 2 01

1 2012 2 01

3 2 01

4 2015 2 01

6 2017 2 01

8 2 01

9 2020 2 02

1 2022

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

Cellulosic Ethanol

Imported Ethanol

Corn Ethanol

E15 Blendwall (Partial Waiver)

E10 Blendwall263 

### Figure 1.7-16 Max E15 Ethanol Consumption Compared to High- Ethanol Control Case

0 5 10 15 20 25 30 35 40

2010 2 01

1 2012 2 01

3 2 0 14 201 5 2 0 16 201 7 2018 2019 2 02

0 2021 2 02

2

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 re flects 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 cha llenges, e.g., E10 blendwall, etc. The information presented in these sections serves as the basi s for various final rulemaking im pact analyses, including cost. However, the air quality modeling and some of the fuel distribution analyses had to begin prior to this assessment being completed. As a resu lt, they relied on industry assessments carried out for the NPRM. Section 1.8 presents the relevant NPRM assessment which served as the basis for these analyses.



### 1.8.1 Ethanol Inputs

1.8.1.1 Corn Ethanol Inputs

1.8.1.1.1 Existing Corn/S tarch Ethanol Production

At the time of our May 2008 corn ethanol plant assessment used for air quality modeling, there were 158 fuel ethanol plants operating in the U.S. with a combined production capacity of 9.2 billion gallons per year. HHHHHHH489490 The majority of ethanol (nearly 89% by volume) was Deleted: ETOH264 produced exclusively from corn. Another 11% came from a blend of corn and/or similarly processed grains (milo, wheat, or barley) and le ss than half a percent was produced from cheese whey, waste beverages, and sugars/starches combined. A summary of the feedstocks utilized by the U.S. ethanol industry as of May 2008 is found in Table 1.8-1.



### Table 1.8.1 May 2008 Corn/Starch Ethanol Production Capacity by Feedstock

Plant Feedstock (Primary Listed First) Capacity
MGY % of Capacity No. 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 re lies primarily on natural gas. At the time of our May 2008 plant assessment, 134 of the 158 corn/starch et hanol plants burned natu ral gas (exclusively). IIIIIII In addition, three burned a combin ation of natural gas and bioma ss, 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 burne d 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 a ssessment. 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.

IIIIIII Facilities were assumed to burn natural gas if the plant boiler fuel was unspecified or unavailable on the public domain.265 Table 1.8.2. May 2008 Corn/Starch Ethanol Produc tion Capacity by Energy Source

Plant Energy Source (Primary Listed First) Capacity
MGY % of Capacity No. of
Plants % o f
Plants CHP
Tech.
Coal a 1,720 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 biomas s, tires, petroleum coke, and wood waste in addition to coal and one facility that intends to transition to biomass in the future.

b Includes one facility that intends to burn thin stillage biogas, five facilities that intend to transition to coal, and one facility that intends to switch to biomass in the future.

c Includes one facility processing bran in addition to natural gas.

Besides a few plants located out side of the Corn Belt, the ma jority of ethanol is produced in PADD close to where the corn is grown. At the time of our May 2008 ethanol industry characterization, PADD 2 accounted for 94% (or 8.6 billion gallons) of the estimated ethanol production capacity as shown in Table 1.8.-3 below.

Table 1.8-3. May 2008 Corn/Starch Ethanol Production Capacity by PADD

PADD Capacity
MGY % 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. For a map of th e ethanol plant locations and a summary of ethanol production capac ity by state, refer to Figure 1.8.1 and Table 1.8.4 below.266 Figure 1.8.1. May 2008 Corn/Starch Et hanol Plant Locations267 Table 1.8-4 May 2008 Corn/Starch Ethanol Pr oduction 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%268 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. JJJJJJJ These projects were at various phases of cons truction 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 we re at advanced stages of planning at the time of our May 2008 industry assessment.

Once all the aforementioned projects are complete, we projected that there would be 216 corn/starch ethanol plants operati ng 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 Charac terization)

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)

JJJJJJJ 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.269 Based on May 2008 industry plans, the majo rity of new corn/gra in ethanol production capacity (82% by volume) was predicted to come from new or expanded plants burning natural gas. Additionally, we forecasted one new plant burning a combination of natural gas and syrup (from the process) and an expansion at an existing facility burning natural gas and biomass. Ourpredictions also suggest two new coal-fired ethanol plants and three expansions at existing coalfired plants. KKKKKKK Finally, we projected three new pl ants burning alternative fuels – one relying on manure biogas, one burning biomass, and one burning a combination of biomass and thin stillage from the process. LLLLLLL 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 so urces 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 Ethano l 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 mentioned in Section 1.5.1.2, we anticipate additional growth in advanced ethanol production technologies in the future under the proposed RFS2 program. For more on our projected 2022 utilization of these technologies under the RFS2 program, refer to Section 1.5.1.3.

KKKKKKK We anticipate that all the coal-fired corn ethanol plants would be grandfathered under the RFS2 program. For more on our grandfathering assessment, refer to Section 1.5.1.4.

LLLLLLL Thin stillage is a process liquid with 5–10 percent solids taken out of the distillers grains via centrifuge. However, construction on this alternatively fuel ethanol plant near Heyburn, ID was since terminated. Accordingly, this plant was not included in our November 2009 RFS2 projections.270 Based on our May 2008 asse ssment, 85% of new ethano l 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.

Table 1.8-7. Projected RFS2 Corn/Starch Ethanol Production Capacity by PADD (Based on May 2008 Ethano l Industry Characterization)

Capacity
MGY No. of
Plants Capacity
MGY No. of
Plants
PADD 1 214 2 264 4 PADD 2 5,002 47 13,620 187
PADD 3 215 2 385 5
PADD 4 70 2 230 9
PADD 5 328 5 499 11 Total 5,829 58 14,998 216 New Plants/Exp.

PADD Total RFS2 Est.

Our May 2008 assessment suggested that Iowa, Nebraska, and Illinois would continue to dominate ethanol production under RFS2 with a collective annua l production capacity of about 7.5 billion gallons. Minnesota a nd Indiana were projected to be the fourth and fifth largest ethanol producers. A map of the forecasted corn ethanol plant locations based on our May 2008 assessment is provided in Figure 1.8-2 and a summary of the et hanol production capacity by state is presented in Table 1.8-8.

Formatted: Don't keep lines together Deleted: ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶ ¶271 Figure 1.8-2 Projected RFS2 Corn/Starch Ethanol Plant Locations (Based on May 2008 Ethanol Industry Characteri zation)

Deleted: ¶272 Table 1.8-8. Projected RFS2 Corn/Starch Ethanol Production Capacity by State (Based on May 2008 Ethanol Industry Charac terization)

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 distribution purposes, we needed to estimate imports based on their country of origin and projected U.S. destination, i.e. , port location.273 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 th e International Trade Commission (ITC) and trends regarding pot ential growth in such imports . Table 1.8-9 contains 2005-2007 data from the ITC on ethanol imports from CBI countries. 491 Table 1.8-10 contains January – March 2008 data from the ITC on etha nol imports from CBI countries. 492

Table 1.8-9. Ethanol Impo rts 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 th e January through March 2008 data , we assumed that ethanol exports from the Virgin Islands would continue to grow to equal those of Trinidad and Tobago in 2022. By accommodating this assumption into our review of 2005 though 2007 historical ethanol import data, we arrived at our projections regarding th e future breakdown of ethanol imports from CBI countries whic h is contained in Table 1.8-11274 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 enter the United States, we started by looking at hist orical ethanol import data and made assumptions as to which countries would likely contribute to the CB I 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. 493 Based on these countries’ geographic loca tions and import histor ies, 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 de stination 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 imports in 2006. We chose to include ports which imported finished gasoline (in a ddition to ethanol) because we be lieve finished gasoline will be one of the first petroleum products to be replaced under the proposed RFS2 rule. And presumably, these ports cities already have existing gasoline storage tanks that could be275 retrofitted to accommodate fuel ethanol. All together, we a rrived at 28 potential ports in 16 coastal states that could receive ethanol imports in 2022 (refer to Figure 1.8-3 below). MMMMMMM

To determine how much ethanol would arrive at each por t location, we started by examining each receiving state’s imported ethanol consumption potential. To do this, we considered each state’s maximum ethanol consumption potential (based on projected gasoline energy demand) and deducted the projected 2022 corn and cellulosic ethanol production (detailed in Sections 1.8.1.1 and 1.8.1.3, respectively). On ce 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 vehi cle miles traveled (VMT) from EPA’s MOVES model 2022 VMT. A summary of the projected ethanol imports volume s by port location is found in Figure 1.8-3.

Figure 1.8-3. Projected RFS2 Ethanol Import Loca tions and Volumes (Million Gallons) NNNNNNN

MMMMMMM 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.

NNNNNNN 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.276 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 feedstoc ks can be used for cellulosi c biofuel production, including: agricultural residues, forestry biomass, the certa in 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 billio n gallons cellulosic biofuel by 2022. Our original plant siting analysis for cellulosic ethanol facilities used the most current version of outputs from FASOM at the time, which was from April 2008. Therefore, the version used for th e majority of other analyses in the rest of this package is different from the results presented below.

Our cellulosic ethanol plant siting analysis assumed that the following cellulosic feedstock and volumes would be used, as shown in Table 1.8-13.

Table 1.8-13. Cellulosic Feedstocks Assu med to Meet EISA in 2022 (NPRM version for AQ Modeling)
Feedstock Volu me (Ethanolequivalent Bgal) Agricultural Residues 9.1
Corn Stover 7.8 Sugarcane Bagasse OOOOOOO 1.2

Sweet Sorghum Pulp 0.1 Forestry Biomass 3.8 Urban Waste 2.2 Dedicated Energy Crops (Switchgrass) 0.9

Total 16.0

OOOOOOO Bagasse is a byproduct of sugarcane crushing and not technically an agricultural residue. Sweet sorghum pulp is also a byproduct of sweet sorghum processing. We have included it under this heading for simplification due to sugarcane being an agricultural feedstock. Deleted:277 Future cellulosic biofuel plant siting was base d on the types of feedstocks that would be most economical as shown in Table 1.8-13, above. As cellulosic biofuel re fineries will likely be located close to biomass resources in order to take advantage of lowe r 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 ac res by county for crops that are currently grown today, such as corn stover and sugarcane (for bagasse). 494 In some cases, crops are not currently grown, but have the potential to replace other crops or pastur eland (e.g., dedicated energy crops). We used the output from our economic modeling (FASOM) to help us determine wh ich 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.278 Table 1.8-14. Projected Cellulosic Ethanol Volume s 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 3,955279 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 82280 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 89281 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 110282 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 16039283 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 th e biofuel. Banks are anticipat ed to require excess feedstock supply as a safety factor to ensure that the plant will have adequate feedstock available for the plant, despite any feedstock emergency, such as a fire, drought, infestation of pests etc. For our analysis we assumed that twice the feedstock of MSW, C&D waste, a nd 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 la rger 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). PPPPPPP

Another assumption that we made is that if multiple feedstocks are available in an area, each would be used as feedstocks for a prospective cellulosic ethanol plant. For example, a particular area might comprise a small or medium sized city, some forest and some agricultural land. We would include the MSW and C&D wastes available from the city along with the corn stover and forest residue for projecting the feedst ock that would be proce ssed 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 ye ar because relatively close materials were available that would otherwise go unused. In addition, we limited biomass transport distances to be approximately 100 m iles each way or less (radius from proposed

PPPPPPP 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 Plant284 facility), as large transport distances are economica lly prohibitive. We found that the majority of corn stover cellulosic facilities required smaller transport distances than the assumed 100 mile limit due to relatively close proximity to available feedstocks. Forest residues, on the other hand, typically required greater distances as collectable material appeared to be sparser.

Our analyses also take into account the locations of planned cellulosic facilities as well as any corn facilities or pulp and paper mills when we project where cellulosic plants are located into the future. While not all planned cellulosi c facilities will likely come to fruition, it was important to look at the locations of these facilities as their locations are likely to be chosen for good reasons (i.e. close to resources, infrastructure in place, etc.). We analyzed current corn facilities and pulp and paper mill sites as well since they are likely to be close to their respective feedstocks (i.e. corn stover 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. 495

For this analysis, we estimated MSW a nd C&D wood waste by state (similar to the analysis described in Section 1.1.2.4) and ca lculated the tons of MSW and C&D wood waste material generated per person pe r state. We used the estimate of MSW and C&D wood waste material generated per person per state (i.e. tons /person) along with data on the population sizes of the largest cities within the stat e 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 pot ential ethanol producer, we calculated a minimum size for a cellulosic plan t dedicated to MSW an d 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 ce llulosic ethanol plant with suffi cient feedstock. However, where non-MSW and C&D wood waste f eedstocks are not available, we needed to estimate what the minimum plant size that would be competitive with other cellulosic ethanol plants.

We conducted this analysis ear ly on before NREL provided us with the cost information for a biochemical cellulosi c ethanol plant. Instead we used a representation made by NREL in 2007 for of a thermochemical ethanol plant. Using that cellulosi c plant model we estimated the production cost for a 100 million gallon per y ear thermochemical plant which processed a cellulosic feedstock. We conducted this analysis in different parts of th e 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 we285 have plant insta llation costs. In each part of the country , we estimated the cost of the ethanol produced processing the cellulosi c feedstock assuming that the f eedstock 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 a nd 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 la rge 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 cellulo sic MSW and C&D wood waste is approximately 640 million gallons.286 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 th at urban waste could he lp contribute to the production of approxima tely 2.2 billion gallons of ethanol. QQQQQQQ

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). RRRRRRR Smaller contributions were expected to come from bagasse, which is a by-p roduct from the production of sugarcan e, (1.2 bgal et hanol) and sweet sorghum pulp (0.1 bgal ethanol). At the tim e of the proposal, FASOM was able to model agricultural residues but not forest ry biomass as potential feedstocks . As a result, we had relied on USDA-Forest Service (FS) for information on the forestry sector for our plant siting analysis.

Using the assumptions from FASOM on residue a nd ethanol yields, we determined if it is possible to site potential cellulosic plants based on the acres currently harvested. We identified that there are enough harvested acres to produce 7.8 Bgal of ethanol from corn stover by 2022 without having to rely on new lands. Therefore, the siting of many of th e cellulosic facilities will likely be located where corn is typically grown today. See Table 1.8-18 for a summary of the

QQQQQQQ Assuming approximately 90 gal/dry ton ethanol conversion yield; Note that this is slightly different from the 2.3 billion gallons of ethanol assumed in other analyses in this package.

RRRRRRR Assuming 94 gal/dry ton ethanol conversion yield for corn stover in 2022287 states producing corn stover, a nd their projected volume contribution to meeting the EISA cellulosic requirement by 2022.288Table 1.8-18.Projected Ethanol Produced to Meet EISA in 2022 from Corn Stover (NPRM version for AQ Modeling)175TotalHarvestedAcresTotal 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% 432175Corn stover is given in dry tons/acre and assumes an ethanol yield of 94 gal/dry ton(this was updated in the final rule to 92.3 gal/dry ton based on NRELestimates); Sustainably removable residue yields assumes only the fraction that can be removed after accounting for sustainable removal rates based on tillagepractices. This table gives approximate averages by state based on our April 2008 version of the agricultural modeling, actualyields will vary greatly dependingon specific soil type, slope, etc. The values above are calculated using the FASOM data outputs from April 2008 and thus are different from those found in othersections of this package which use more updated runs from 2009.289 Sugarcane, on the other hand, is grown mainly in Florida, Louisiana, and Texas, although plans are underway to also grow sugarcane in Cali fornia 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 economic ally 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 harveste d by county (data on hay acres were unavailable and appeared to show small changes compared to corn and soy). 496 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 pr ovided by the USDA-FS (biomass supply curves for various sources i.e., loggi ng residues, other removal residue s, thinnings 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 required290 under the Act). See Section 1.1.2.3 for more information on forest residue feedstock availability. However, much of the forest material is in small pockets of forest which because of its regional low density, could not help to ju stify the establishment of a cellulosic ethanol plant. After conducting our availability analysis, we estimated that approximately 44 million dry tons of forest material could be used, which would make up approximately one fourth, or 3.8 billion gallons, of the 16 billion gallons of cellulosic biofuel required to meet EISA.

The April 2008 version of the FASOM results projected that 0.9 billion gallons of cellulosic ethanol from switchgrass is economica lly 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 switchgr ass 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 assume d to be produced and consumed in the NPRM. For this analysis, we also applied NPRM assump tions with respect to FFV and E85 availability, described in more detail below.

With respect to FFVs, we assumed that the Detroit 3 would fo llow through with their 50% by 2012 FFV commitment and the non-domestic automakers would follow suit and produce 25% FFVs by 2017. This corresponded to the primary Optimistic FFV Production Scenario outlined in the NPRM. The annual FFV sales by vehicle type are summarized in Table 1.8-20 below. For analysis purposes, we made the si mplifying assumption that all FFVs would be distributed homogeneously and tota l vehicle sales would remain c onstant around 16 million units per year. This differs from vehicle assumptions made for the final rule, outlined in Section 1.7.1.2.291 Table 1.8-20. Optimistic FFV Production Scenar io – FFV Production Assumptions

Tot FFVs FFV-Cars FFV-Trucks Tot FFVs FFV-Cars FFV-Trucks 2002 1,000,000 200,000 800,000 0 0 0 2003 1,000,000 200,000 800,000 0 0 0 2004 1,000,000 200,000 800,000 0 0 0 2005 1,000,000 200,000 800,000 0 0 0 2006 1,000,000 200,000 800,000 0 0 0 2007 1,000,000 200,000 800,000 0 0 0 2008 1,600,000 320,000 1,280,000 80,000 0 80,000 2009 2,200,000 440,000 1,760,000 160,000 0 160,000 2010 2,800,000 560,000 2,240,000 240,000 0 240,000 2011 3,400,000 680,000 2,720,000 320,000 0 320,000 2012 4,000,000 800,000 3,200,000 400,000 0 400,000 2013 4,000,000 800,000 3,200,000 720,000 0 720,000 2014 4,000,000 800,000 3,200,000 1,040,000 0 1,040,000 2015 4,000,000 800,000 3,200,000 1,360,000 0 1,360,000 2016 4,000,000 800,000 3,200,000 1,680,000 0 1,680,000 2017 4,000,000 800,000 3,200,000 2,000,000 0 2,000,000 2018 4,000,000 800,000 3,200,000 2,000,000 0 2,000,000 2019 4,000,000 800,000 3,200,000 2,000,000 0 2,000,000 2020 4,000,000 800,000 3,200,000 2,000,000 0 2,000,000 2021 4,000,000 800,000 3,200,000 2,000,000 0 2,000,000 2022 4,000,000 800,000 3,200,000 2,000,000 0 2,000,000 Year GM, Chrysler & Ford Non-Domestic Automakers

Based on these FFV production assumptions 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/et hanol mix) that could feasibly be consumed by FFVs in 2022 would be about 30%. The resulting gasoline energy consumption by vehicle type under the Optimistic FFV Production Scenario is shown below in Figure 1.8-5. For analysis purposes, we assumed that the percentage of ga soline energy consumed by nonroad, heavy-duty gasoline vehicles (HDGVs), and motorcycles woul d be about 8% based on historical information provided by DOE. cdxcvii292 Figure 1.8-5. Optimistic FFV Production Scenario - Gasoline Consumption by Vehicle Type

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

2 0 1 0 2011 2 0 1 2 2013 2014 2 0 1 5 2016 2017 2018 2019 2020 2021 2022% of Gasoline Consumption FFVs Tier 2 Vehicles (Non-FFVs)

Pre-Tier 2 Vehicles Nonroad, HDGVs & Motorcycles

For the primary ethanol usage scenario anal yzed in the NPRM and used for the AQ modeling work, we assumed practical, yet aggressive growth in E85 access. We considered the possibility that 70% of the nation could have reasonable one-in-four-station access to E85 by 2022. This is roughly equivalent to all urban areas in the United St ates offering E85. For this analysis, we have defined “urban” areas as:293 • The top 150 metropolitan statisti cal 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 - Con centrating Pumps in Urban Areas294 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 standpoi nt, 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 sta ndpoint, it makes sense that E85 mi ght be offered in more populated metropolitan areas with high gasoline throughput. For more on fuel distribution logistics and costs, refer to Sections 1.6 and 4.2 of the RIA.

Assuming that reasonable E85 access grows linearly to 70% by 2022, we can iteratively compute the corresponding nationwide E0 and E10 access assuming that a.) each fuel retailer only carries one type of conventional gasoline (E0 or E10) and b.) the nation does not exceed the RFS2 ethanol volume requirements analyzed fo r the NPRM. Under a very aggressive FFV production scenario, we estimate that E0 could th eoretically remain in existence until 2016 as shown below in Figure 1.8-7. However, we anticipate that E10 will likely replace E0 sooner based on current market trends.

Figure 1.8-7. Assumed Phase-Out of E0 and Phase-In of E10 & E85

0% 20% 40% 60% 80% 100%

2010 2 0 1 1 2012 2013 2 0 1 4 2 0 1 5 2 0 1 6 2 0 1 7 2 0 1 8 2 0 1 9 2 0 2 0 2021 2 0 2 2

YearNationwide Access to Fuel

E0

E10

E85295 To comply with the proposed RFS2 progra m and consume 34.1 billion gallons of ethanol by 2022, not only would we need more FFVs a nd more E85 retailers, we’ll need to see a significant increase in FFV E85 refueling. Under the Optimistic FFV Production Scenario (assuming practical growth in E85 access), our analysis suggests that FFV owners with reasonable one-in-four access to E85 would need to fill up on it 74% of the time in 2022 - a significant increase from today’s refueling frequency.

To estimate where E85 might be consumed under the proposed RFS2 program in 2022, we conducted a cost effectiveness study. For each area of the county, we began by looking at gasoline delivered prices. We started with state-level gasoline prices (excluding taxes) provided by EIA’s Petroleum Marketing Annual 2006. cdxcviii We relied on Table 31 for average gasoline prices, looked to Table 34 fo r RFG prices and back-calculated CG prices by applying the respective gasoline fuel volumes provided in Table 48. For states requiring 7 or 7.8-lb gasoline in the summertime, we applied PADD-average low-RVP gasoline production costs derived from the Mobile Source Air Toxics (MSAT) rule cdxcix to come up with the respective low-RVP and 9- lb conventional gasoline prices in these states . From there, we added in the corresponding gasoline taxes (state plus fe deral) according to the Ameri can Petroleum Institute (API). d This gave us the average retail cost of gasoline by state and fuel type.

Next we converted the gasolin e prices into competitive retail E85 prices by adjusting for the reduced energy density of E85, the increased refueling time, and E85’s presumed limited availability in 2022. For a more on this general methodology, refer to Section 1.7.1.2.5 of the RIA. From there, we deducted fuel taxes (assu med 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. 176 Once we computed the retail value of ethanol, we compared it to the estimated ethanol delivered pr ice (based on transportation costs presented in Section 4.2 of the proposal) to come up wi th the respective E85 profit margin.

To conclude, we assigned E85 to the areas of the county with the highest E85 profit margins, or in some cases, the least negative E85 profit margins until we arrived at approximately 34 billion gallons of ethanol in 2022. For a graphical representation of the areas of the country we assumed would receive /consume E85, refer to Figure 1.8-8.

176 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.296 Figure 1.8-8 Projected E85 Availability in 2022 Under RFS2

1.8.2 Biodiesel & Rene wable Diesel Inputs

1.8.2.1 Upstream Production Inputs

In order to generate c ounty-level emissions inputs for the control case, we needed projected locations of bi odiesel 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 pr imary control case, a fact which suggests the industry may downsize in the long term.

We developed a method to de termine where biodiesel producers were most likely to remain based on state incentives to biodiesel produ cers and for biodiesel sale s or use. Data on state incentives was taken from an online databa se maintained by the Department of Energy Office of Energy Efficiency and Renewable Energy. di Two other criteria 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. dii Based the volume of the primary control case, assuming a capacity utilization factor of approximately 80%, a list of pl ants for the 2022 scenarios was Deleted: factors297 generated choosing first from those plants w ith most favorable status of the four criteria and working downward. We projected that a number of very small plants processing waste greases/fats would continue to operate based on local market niches regardless of these criteria. In an effort to be realistic in this forecast, other practical considerations were made, such as avoiding siting several plants in the same state (except in the Midwest)

.
We project that between now and 2022 plants w ill continue to compete and consolidate tomake fewer plants of larger size. During this period most plants will have added the pretreatment and feedstock se gregation capacity to process any mi x of feedstock types available in their area.

From the projected list of plant locations , emission quan tities were gene rated for each county based on each plant’s bi odiesel production rate. Spread sheets showing lists of the representative plants and their emission factors as input in the inventory and air quality models can be found in the docket. This information is summarized he re in Table 1.8-21 and Figure 1.8- 9.

Table 1.8-50. Summary of biodiesel industry and forecast used for AQM. diii

2008 2022 Total production capacity on-line (million gal/yr) 2,610 1,050 Number of operating plants 176 35 Median plant size (million gal/yr) 5 30 Total biodiesel production (million gal) 700 810 Average capacity factor 0.27 0.77 Deleted: factors

Deleted: Efforts were made to choose a mix of large and small plants, and to place plants in all regions, with the intention being to form a representative list

Deleted: 2022

Deleted: list298 Figure 1.5-18. Biodiesel industry forecast for 2022

1.8.2.2 Downstream Consumption Inputs

Biodiesel, like ethanol, is generally blended at the end of the distribution chain, just before delivery to retail outlets. Because of its chemical properties, it is not currently considered fungible with diesel fuel, and thus its blend level in fuels offered for sale is typically deliberate and explicit. Renewable diesel, on the other hand , is a fuel or hydrocarbon blendstock which can be blended into fungible fuel at any point in the distribution system, such that the blend level at the final point of use is not typically of con cern and, in fact, would probably be difficult to determine. Because of its nature, and the relatively small volumes we are projecting (less than 0.5 billion gallons per year), we have not anal yzed distribution or use impacts for renewable diesel. The remainder of this section addresses biodiesel use.

Vehicle and engine manufacturers recognize biodiesel as a lubricity improver at low levels, something that is useful with ultra-low sulfur diesel fuel now phasing in across the country. Therefore, most state that their products are compatible with blends up to 5%, and a few suggest blends up to 20% can be used without problems. Therefore, our analysis assumes blends up to 5% can find widespread use.

In order to conduct our distribution and emissions analyses, we needed to forecast approximate volumes of biodiesel to be used in each state. We considered transportation diesel fuel and home heating oil as the primary uses for biodiesel. For transportation fuel estimates, we 13/15

105/123 0.8/1 0.4/0.5 35/85 41/60

113/158

56/60 9.2/22 75/80 13/30 17/20

38/45

NJ: 38/40 CT: 3.3/4

MA: 0.4/0.5

RI: 0.2/0.3

42/50

67/80 25/30

FL: 17/18 8.3/10 88/105

0.4/0.5

7.5/8

Biodiesel Production/Capacity (million gal/yr) in 2022 13/15

105/123 0.8/1 0.4/0.5 35/85 41/60

113/158

56/60 9.2/22 75/80 13/30 17/20

38/45

NJ: 38/40 CT: 3.3/4

MA: 0.4/0.5

RI: 0.2/0.3

42/50

67/80 25/30

FL: 17/18 8.3/10 88/105

0.4/0.5

7.5/8

13/15

105/123 0.8/1 0.4/0.5 35/85 41/60

113/158

56/60 9.2/22 75/80 13/30 17/20

38/45

NJ: 38/40 CT: 3.3/4

MA: 0.4/0.5

RI: 0.2/0.3

42/50

67/80 25/30

FL: 17/18 8.3/10 88/105

0.4/0.5

7.5/8

Biodiesel Production/Capacity (million gal/yr) in 2022299 assumed that biodiesel would be preferentially used in states that have blend mandates or significant per-gallon incentives. Table 1.8-21 shows the states with such mandates and incentives on record as of summer 2008, as well as the associated poten tial biodiesel volumes based on 2005 diesel fuel use. div State-level forecasts were not available for transportation fuel use, thus the reliance on histori cal data for this estimate.

Table 1.8-21. State biodiesel incent ives as of summer 2008 and potential volumes based on 2005 data. dv

Diesel fuel use 2% biodiese l 5% biodiese l ( 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 uirement 1,660 33.2

KS p er- g allon tax incentive ( s ) for B2+ 816 16.3 LA B2 mandate with some conditions 1,734 34.7 MA B2 mandate, increasing to B15 with
some conditions 491 24.5

MI p er- g allon tax incentive ( s ) for B5+ 1,071 53.5 MN B2 mandate; state fleet re q uirement 999 20.0 NC per-gallon tax incentive(s), B2 school
b us re q uirement 1,234 24.7

ND p er- g allon tax incentive ( s ) 358 7.2
NE p er- g allon tax incentive ( s ) 547 10.9
NM 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 poten tial biodiesel use in heating oil at 89 million gallons per year based on a 2% blend in all heating oil north of the Washington, DC, area (i.e., PADD 1A and 1B). This area was chosen because it is where the majority of heating oil is used, and should have adequate biodiesel access from New Jersey, Pennsylvania, and Connecticut in our forecasted production scenarios. To the extent that heating oil use declines over time, the blend levels may increase in some areas or in the shoulder seasons, such that the total biodies el volume used in this market would not decline drastically.300 Table 1.8-22. Potential biodie sel use in heating o il based on 2005 data. dvi
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, refe r 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 Markets,” May 2007 (a revised version is available from Ju ly 2007); USDA Agricultural Projections to 2018, Report OCE-2009-1, February 2009 (also USDA Agricultural Projections to 2016, Report OCE-2007-1, Februa ry 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 Biofue l Demand on U.S. Agriculture,” May 2007.

2 USDA/NASS. “Quick Stats: U.S. and All States Data- Corn field”301 3 USDA/NASS. “Corn: Yield by year, US,” http://www.nass.usda.gov/Charts_and_Maps/Field_Crops/cornyld.asp, November 10, 2009.

4 USDA Agricultural Projections to 2018, Report OCE-2009-1, February 2009

5 USDA, National Agricultural Statistics Serv ice, Crop Production and Grain Stocks; USDA, World Agricultural Outlook Board, World Supply and Demand Estimates; and U.S. Department of Commerce, Bureau of the Census.

6 USDA Agricultural Projections to 2016, Re port OCE-2007-1, Februa ry 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, “Bioet hanol as Basis for Re gional Development in Brazil: An Input-Output Model with Mixed Technologies.”

15 CGEE, ABDI, Unicamp, and NIPE, “Scaling Up the Ethanol Program in Brazil,” n.d. cited in Rothkopf, Garten, “A Blueprint fo r Green Energy in America,” 2006.

16 CGEE, ABDI, Unicamp, and NIPE, “Scaling Up the Ethanol Program in Brazil,” n.d. cited in Rothkopf, Garten, “A Blueprint fo r 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., “B iofuel Feedstock Assessment for Sel ected 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 Hoffma n, Managing Member of California Renewable Energies, LLC, August 27, 2008.

21 Christiansen, Ryan, “Analysis: Sugarcane Ethanol Has 95% Less Emissions,” Ethanol Producer Magazine, March 2009.

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

23 Voegele, Erin, “Sugarcane plays role in de velopment of green polyethylene, Sugarcorn,” Ethanol Producer Ma gazine, March 2009.

24 Saballos, Ana. in W. Vermerris (ed.), (2008) “Development and Utilization of Sorghum as a Bioenergy Crop,” Genetic Improvement of Bioenergy Crops DOI: 10.1007/978-0-387-70805- 8_8

25 W. W. Wilhelm, USDA-ARS, Univ. of Nebras ka, Lincoln, NE 68583-0934, J. M. F. Johnson, USDA-ARS, Morris, MN 56267-1065, J. L. Hatfie ld, 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 Corn302 Residue Removal A Literature Review; FORUM, © American Society of Agronomy, Madison, WI 53711 USA, Published in Agron. J. 96:1-17 (2004)

26 Predicting Soil Erosion by Water. A Guide to Conservation Planning with the Revised Universal Soil Loss Equation (RUSLE). United States Department of Agriculture, Agricultural Research Service, Agricultural Handbook Number 703, 1997.

27 Richard G. Nelson, Enersol Resources, Manhattan, KS 66502, USA, Resource Assessment and Removal Analysis for Corn Stover and Whea t Straw in the Eastern and Midwestern United States—Rainfall and Wind-indu ced Soil Erosion Methodology, Biomass and Bioenergy 22 (2002) 349 – 363, Published by Elsevier Science Ltd

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

29 http://www.nrcs.usda.gov/technical/Standards/nhcp.html

30 Richard G. Nelson, Enersol Resources, Manhattan, KS 66502, USA, Resource Assessment and Removal Analysis for Corn Stover and Whea t Straw in the Eastern and Midwestern United States—Rainfall and Wind-induced Soil Er osion Methodology, Biomass and Bioenergy 22 (2002) 349 – 363, Published by Elsevier Science Ltd.

31 W.W. Wilhelm, USDA-ARS; J.M.F. Johnson, USDA-ARS; D.L. Karlen, USDA-ARS; D.T. Lightle, National Soil Survey; Corn Stover to Sustain Soil Or ganic Carbon 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 Conser vation Service Crop, White Paper: Residu e Removal for Biomass Energy Production: Effect s 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 S upply; Sponsored by the U.S. Department of Energy and the U.S. Departme nt of Agriculture; April 2005.

35 Elbehri, Aziz. USDA, ERS, “An Evaluation of the Economic s of Biomass Feedstocks: A Synthesis of the Litera ture,” Prepared for the Biomass Research and Development Board, 2007.

36 Milbrandt, A., “Geographic Perspective on the Current Biomass Resource Availability in the United States,” NREL Report No. TP-560-39181, 2005.

37 Gallagher, P. et. al., “Supply and Social Cost Estimates for Biomass from Crop Residues in the United States,” Environmental and Resource Economics 24: 335-358, 2003.

38 Walsh, Marie, “U.S. Cellul osic Biomass Feedstock Supplie s 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) “His torical 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 Biol ogical Barriers to Cellulosic Ethanol: A Joint Research Agenda.” (2006).303 42 Kumar, A., & Sokhansanj, S., “Switchgrass (Panicum vigratum, L.) delivery to a biorefinergy using integrated biomass supply anal ysis and logistic s (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-Brow n, 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 Biol ogical Barriers to Cellulosic Ethanol: A Joint Research Agenda,” 2006.

56 Saballos, op. cit

. 57 McCutchen, Bill et. al. High-Tonnage Dedicated Energy Crops: The Pote ntial of Sorghum and Energy Cane.

58 U.S Department of Energy. “Breaking the Biol ogical Barriers to Cellulosic Ethanol: A Joint Research Agenda,” 2006.

59 Ibid.

60 Campbell, J.E. at al., ”The Global Potential of Bioenergy on Abandoned Agriculture Lands,” Environ. Sci. Technology , 2008.

61 Adapted from additional information received from J. Elliot Campbell. “The Global Potential of Bioenergy on Abandone d 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 Statis tics: Monthly Summary November 2009.”

64 Ibid.

65 Perlack, R.D., Wright, L.L., Turhollow, A.F, Graham, R.L., Environmental Sciences Division, Oak Ridge National Laboratory; St okes, B.J., Forest Service, USDA.; Erbach, D.C., Agricultural Research Service, USDA, “Biomass as Feedst ock for a Bioenergy & Bioproducts Industry: The Technical Feasibility of a Billion-Ton Annual Supply (A Joint Study Sponsored by DOE and USDA, Prepared by Oak Ridg e National Laboratory),” 2005

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; St okes, B.J., Forest Service, USDA.; Erbach, D.C., Agricultural Deleted: a

Deleted: 65 Ibid.304 Research Service, USDA, “Biomass as Feedst ock for a Bioenergy & Bioproducts Industry: The Technical Feasibility of a Billion-Ton Annual Supply (A Joint Study Sponsored by DOE and USDA, Prepared by Oak Ridge National Laboratory),” 2005.

69 Ibid.

70 Dickerson, K., et. al. (revised November 2007). Biomass and Biofuels in Maine: Estimating Supplies for Expanding the Fo rest Products Industry . Margaret Chase Smith Policy Center.

71 Puttock, G.D. (1995). Estimating cost for integr ated harvesting and rela ted 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; St okes, B.J., Forest Service, USDA.; Erbach, D.C., Agricultural Research Service, USDA, “Biomass as Feedst ock for a Bioenergy & Bioproducts Industry: The Technical Feasibility of a Billion-Ton Annual Supply (A Joint Study Sponsored by DOE and USDA, Prepared by Oak Ridge National Laboratory),” 2005.

73 Dickerson, K., et. al. (revised November 2007). Biomass and Biofuels in Maine: Estimating Supplies for Expanding the Fo rest Products Industry . Margaret Chase Smith Policy Center.

74 Ibid.

75 Timko, B., 2003. USDA, Forest Service, personal communication as noted in the “Billion-ton Study” by Perlack, R.D., et. al.

76 F. Bohlin and A. Roos, Wood fuel supply as a function of forest owner preferences and management styles, Biomass & Bioenergy 22 (2002), pp. 237–249.

77 Sanchez, Felipe G., Effects of organic ma tter removal and soil compaction on fifth-year mineral soil carbon and nitrogen contents for sites across the United States and Canada, Canadian Journal of Forestry Research, 36;:565 – 576, 2006.

78 Powers, Robert F., The North American l ong-term soil productivity experiment: Findings from the first decade of res earch, Forest Ecology and Management, 220: 31 – 50, 2005.

79 Zobrist, K.W.; T. M. Hinckley; M.G. Andreu. A literature review of management practices to support increased biodiversity in in tensively managed loblolly pine plantations. Final Technical Report to the National Commission on Science for Sustainable Forestry (N CSSF). July 31, 2005. 16 p.

80 Jonsell, M. 2007. Effects on Bi odiversity of Forest Fuel Extr action, Governed by Processes Working on a Large Scale. Biomass and Bioenergy, Issue 31 pg. 726-732.

81 T.B. Wigley and T. H. Roberts. 1994. Forest ma nagement and wildlife in forested wetlands of the southern Appalachians. Water, Air and Soil Pollution 77: 445-456.

82 Kozlowski, T.T., 1999. Soil Compaction and Grow th of Woody Plants. Scandinavian Journal of Forest Research, Volume 14, Number 6. Taylor and Francis Ltd.

83 Rummer, B.; Len, D.; and O’Brien, O. (2004). Forest Residues Bundling Project-New Technology for Re sidue Removal. USDA Forest Service, Southern Research Station

84 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.

85 Aden, Andy. December 10, 2009. “Feedstock C onsiderations and Impacts on Biorefining.” National Renewable Energy Laboratory

86 Perlack, Robert D.; Biomass as Feedstocks for a Bioenergy and Bioproducts Industry: The Technical Feasibility of a Billion Ton Annual S upply; Sponsored by the U.S. Department of Energy and the U.S. Department of Agriculture; April 2005.305 87 Walsh, Marie E., U.S. Cellulosic Biomass F eedstock Supplies and Dist ribution; January 10, 2008.

88 Gordon, Gayle of the Western Governors A ssociation; Strategic A ssessment of Bioenergy Development in the West, Kansas State University and the US Forest Service, multiple reports dated September 1, 2008.

89 Data provided by e-mail by Perlack, Robert D., May 2008.

90 EPA. “Municipal Solid Waste Generation, Recycling, and Disposal in the United States: Facts and Figures for 2008,”

91 USEPA. “Municipal Solid Waste in the United States,” 2007; See Tables 1-3.

92 Biocycle, “The State of Garbage in America,” Vol. 49, No. 12, December 2008, page 22.

93 Midwest Assistance Program, Inc. “The 2006-2007 Missouri Municipal Solid Waste Composition Study,” October, 2007.

94 R. W. Beck, “Georgia Statewide Characterization Study,” June 2005.

95 Engineering Solutions and Design, Inc., “State of Ohio Waste Characterization Study,” April 2004.

96 NYC Department of San itation, “2004-2005 NYC Waste Characterization Study.”

97 R.W. Beck, “Statewide MSW Composition Study: A Study of Discards in the State of Minnesota,” 2000.

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

99 DSM Environmental Services, Inc, “Vermont Waste Composition Study,” June 2002.

100 R.W. Beck, “1992 Washington Stat e Waste Characterization Study.”

101 R.W. Beck, “Wisconsin Statewide Waste Characterization Study,” May 2003.

102 Department of Environmental Quality, “Oregon 2002 Waste Composition Study,” 2002.

103 Williams, Robert and California Biomass Co llaborative, “Biofuels from Municipal WastesBackground Discussion Pa per,” March 28, 2007.

104 Ibid.

105 Walsh, Marie, “U.S. Cellul osic Biomass Feedstock Supplie s and Distribution,” Unpublished Manuscript, January 10, 2008.

106 Falk, Robert and McKeever, David. 2004. “Recovering Wood for Re use and Recycling A United States Perspective” USDA Forest Service

107 Fricke, K. (1989). “Technology and undesira ble components on com post of separately collected organic wastes” Agriculture, Ecosystem, Environment

. 108 McKeever, David. (December 1999). “How Wo ody Residues Are Recycled in the United States" BioCycle

109 Center for Sustainable Systems “U.S. Food System Fact Sheets,”2008

110 USEPA, Construction and Demolition (C&D) Materials. http://www.epa.gov/osw/nonhaz /industrial/cd/basic.htm Acce ssed August 10, 2008.

111 Fehrs, J., “Secondary Mill Residues and Urban Wood Waste Quantities in the United StatesFinal Report,” Northeast Regi onal Biomass Program Washington, D.C., December 1999.

112 Wiltsee, G., “Urban Wood Waste Resource A ssessment,” Appel Consu ltant, Inc. Valencia, CA. November, 1998.

113 Seabra, Joaquim. (July 2009) . “Comparison of options for advanced ethanol production in Brazilian sugarcane biorefineries” draft manuscript, anticipated to be available in Biomass and Bioenergy soon.306 114 Kline, K. et. al. Biofuel Feedstock Assessme nt for Selected Countries. Oak Ridge National Laboratory. February 2008.

115 See F.O. Licht World Ethanol and Biofuels Report, vol 7, no 21, p 434 (July 8, 2009).

116 Mueller, Steffen. An analysis of the projected energy use of future dry mill corn ethanol plants (2010-2030). October 10, 2007. Available at http://www.chpcentermw.org/pdfs/ 2007CornEethanolEnergySys.pdf

117 “Essential Rendering”, published by the National Rendere r’s Association, edited by David Meeker. 2006. Available at http://nationalrenderers.org/assets/essential_rendering_book.pdf

118 “Statewide Feasibility Study for a Potential New York State Biodiesel Industry”, prepared by LECG, LLC. Report number 04-02, April 2004. Available at http://www.nyserda.org/publications/biodieselreport.pdf

119 A copy of this letter is available in the docket.

120 Sheehan, John, Terri Dunahay, John Benemann, and Paul Roessler, “A Look Back at the U.S. Department of Energy’s Aquatic Species Prog ram—Biodiesel from Alg ae,” National Renewable Energy Laboratory. Office of Fuels Development. Golden, Colorado, 1998.

121 Ibid.

122 Ryan, Catie. op. sit.

123 Ryan, Catie, “Cultivating Clean Energy: Th e Promise of Algae Biofuels,” NRDC and Terrapin Bright Green, LLC. October 2009.

124 Davis, Ryan. November 2009. Techno-economic analysis of microalgae-derived biofuel production. National Re newable Energy Laboratory. Te chnical Memorandum to EPA.

125 Davis, Ryan. op. sit.

126 Chisti, Yusuf, "Biodiesel from Microalgae." Biotechnology Advances 25, 294-306, 2007.

127 Schenider, David, "Grow Your Own?" American Scientist , Sept.-Oct. 2006.

128 Campbell, Matthew N., "Biodiesel: Algae as a Renewable Source for Liquid Fuel." Guelph Engineering Journal , 1, 2-7, 2008.

129 Chisti, op. sit.

130 Pienkos, Philip T., "The Potential for Biofuels from Algae," Algae Biomass Summit. San Francisco, CA. Nov. 15, 2007.

131 Campbell, op. sit.

132 Pienkos, op. sit.

133 Pienkos, op. sit.

134 Campbell, op. sit.

135 Putt, Ron. “Algae as a Biodies el Feedstock,” Nov. 20, 2007.

136 Sheehan, op. sit.

137 "Algae Bloom Again." Nature , 447, 520-21 2007.

138 Deshayes, Pierre-Henry, "As planet swelters, are algae unlikely saviour?" AFP, July 10, 2008.

139 Sheehan, op. sit.

140 Pienkos, op. sit.

141 “PV Solar Radiation,” Digital image. Na tional Renewable Energy Laboratory. May 2004.

142 Bullock, Cary, "Algae Corrals Carbon Dioxide," EnergyBiz Magazine , 68-70, Mar.-Apr. 2007.

143 Chisti, op. sit.

144 Sheehan, op. sit.

145 Davis, Ryan. op sit.307 146 Ryan, Catie, op. sit.

147 Jongschaap, R.E.E, W.J. Corre, P.S Bindraban , and W.A. Brandenburg, “Claims and Facts on Jatropha curcas L,” Plant Research International , Vers. Report 158, Oct. 2007.

148 Euler, Hartlieb, and David Gorriz, “Case Study "Jatropha Curcas"” Rep. No. Global Facilitation Unit for Underutilized Species , Frankfurt, 2004.

149 Jongschaap, op. sit.

150 Ibid.

151 Fairless, Daemon. "The little shrub that could - maybe." Nature 449 (2007): 652-55.

152 Francis, G., R. Edinger, and K. Becker. "A concept for simultaneous wasteland reclamation, fuel production, and socio-economi c development in degraded area s in India: need, potential and perspectives of Jatropha planta tions." Natural Resources Forum 29 (2005): 12-24. As sited in Jongschaap, R.E.E, W.J. Corre, P.S Bindraban, and W.A. Brandenburg, “Claims and Facts on Jatropha curcas L,” Plant Research International , Vers. Report 158, Oct. 2007.

153 Woltjer, Lyanne. Size does matter. Expertise Centrum voor Duurzame Ontwikkeling (ECDO). Dec. 2006.

154 Jongschaap, op. sit.

155 Li Guo, T. "The photosynthesis and water use efficiency of eight garden tree species." Forest Research 15 (2002): 291-96. As sited in Jongschaap , R.E.E, W.J. Corre, P.S Bindraban, and W.A. Brandenburg, “Claims and Facts on Jatropha curcas L,” Plant Research International

, Vers. Report 158, Oct. 2007.

156 Jongschaap, op. sit.

157 Fairless, op. sit.

158 Jongschaap, op. sit.

159 Ghosh, A., J.S. Patolia, D.R. Chaudharry, J. Ch ikara, S.N. Rao D. Kumar, G.N. Boricha, and A. Zala. Response of Jatropha curcas under different sp acing to Jatropha de-oiled cake. Discipline of Phytosalinity, Central Salt and Marine Chemicals Research Institute. 2007.

160 Jongschaap, op. sit.

161 Kumar, op. sit.

162 Ibid.

163 Pant, K.S., V. Khosla, D. Kumar, and S. Ga irola, "Seed oil conten t variation in Jatropha curcas Linn. in different altitudinal rang es and site conditions in H.P. India," Lyonia 11 (2006): 31-34.

164 Jongschaap, op. sit.

165 USDA, "PLANTS Profile for Jatropha curcas L." USDA Natural Resources Conservation Service. http://plants.usda.gov/java/profile?symbol=jacu2, November 3, 2008.

166 Jongschaap, op. sit.

167 Oregon Climate Service, “State Annual Precip Maps,” http://www.ocs.oregonstate.edu., November 3, 2008.

168 Carney, Dan. "Second- generation biodiesel." Automotive Engineering , May 2008: 20-22.

170 Koch, Blair. “Canola yield light, but growers pleased with first crop.” Ag Weekly August 21, 2007. <http://www.agweekly.com/artic les/2007/09/10/news/ag_news/news32.txt>

172 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/newcr op/proceedings1993/v2-314.html>308 174 Great Plains: The Camelina Company < https://www.camelinacompany.com/marketing/agronomics.aspx#Facts>

175 W.M. Breene, et. al. op sit.

176 McCormick, Margaret. “Oral Comments of Targeted Growth, Incorporated” Submitted to the EPA on June 9, 2009.

178 Schill, Susanne R. “Making Pennycress Pay Off.” Biodiesel Magazine February 2008.

180 Biofuel Manufacturers of Illinois. http://www.growpennycress.com/

181 Schill, Susanne R. op sit.

198 Figures taken from European Biodiesel Board website as of December 2009. See http://www.ebb-eu.org/stats.php.

199 Food and Agricultural Policy Research Institute, 2009 Agricultural Outlook. See http://www.fapri.iastate.edu/outlook/2009/text/14WorldBiofuels.pdf.

200 Biofuels Barometer. Eurobserv’er, July 2009. See http://www.eurobserver.org/pdf/baro192.pdf

201 DTN Ethanol Center, ”EU Biodiesel Feedstock Challe nge,” October 11, 2007, http://www.dtnethanolcenter.com/index.cfm?show=10&mid=66&pid=27

202 Food and Agricultural Policy Research Institute, 2009 Agricultural Outlook. See http://www.fapri.iastate.edu/outlook/2009/text/14WorldBiofuels.pdf.

203 National Renewable Energy Laboratory estimat e based on biomass portion available at $45- $55/dry ton.. Using POLYSYS Polic y Analysis System, Agricultural Policy Analysis Center, University of Tennessee. http://www.agpolicy.org/polysys.html. Accessed May 2008.

204 Milbrandt, A. (2005). “Geographic Perspective on the Current Biomass Resource Availability in the United States.” 70 pp.; NREL Report No. TP-560-39181

205 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.

206 Rummer, B.; Len, D.; and O’Brien, O. (2004). Forest Residues Bundling Project-New Technology for Re sidue Removal. USDA Forest Service, Southern Research Station

207 Ibid.

208 Rawlings, C., et. al. (2004). A Study of How to Decrease the Costs of Collecting, Processing and Transporting Slash. USDA Forest Service.

209 D. Montross, Associate Professor, Scott A. Shearer, Professor, Ti mothy S. Stombaugh, Associate Extension Professor, St ephen F. Higgins, Research Speci alist, and Samuel G. McNeill, Associate Extension Professor, Department of Biosystems and Agricultural Engineering, University of Kentucky, Lexington, Kentucky; and Shahab Sokhansanj, Professor, Oak Ridge National Laboratory, Environmental Sciences Di vision, 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 E xperiment Station and designated Paper No. 04-05-066. Trans actions of the ASABE, Vol. 50(3): 705

− 711 – 2007 American Society of Agricultural and Biological Engineers, ISSN 0001

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210 S. Sokhansanj1, A. Turhollow, and R. Pe rlack, Oak Ridge National Laboratory, Tennessee, USA 37830, Stochastic Modeling of Costs of Corn Stover Costs Delivered to an Intermediate Storage Facility, Paper Number: 024190, Presented at : 2002 ASAE Annual International Meeting / CIGR XVth World Congress, Spons ored by ASAE and CIGR, Hyatt Regency Chicago, Chicago, Illinois, USA, July 28-July 31, 2002309 211 P. Savoie, L. D’Amours, F. Lavoie, G. Lechasseur, H. Joa nnis. Development of a CutterShredder-Baler to Harvest Long-Stem Willow. Paper Number: 061016, Presented at: 2006 ASABE Annual Internati onal Meeting, Sponsored by ASAB E, Portland Convention Center, Portland, Oregon, USA, July 9 – July 12, 2006

212 Kevin J. Shinners, Professor of Agricultura l Engineering, Ben N. Binversie, Graduate Research Assistant, Department of Biological Systems Engineering, University of Wisconsin, Madison, WI, Philippe Savoie, Re search Scientist, Agriculture and Agri-Food Canada, Quebec, Canada; Harvest and Storag e Of Wet and Dry Corn Stover As A Biomass Feedstock, Paper Number: 036088, 2003 ASAE Annua l Internationa l Meeting Riviera Hotel and Conventi on Center, Las Vegas, Neva da, USA, 27- 30 July 2003

213 Christopher T. Wright, Peter A. Pryfogle, Nathan A. Stevens, J. Richard Hess, Corey W. Radtke, Idaho National Laboratory, Idaho Falls, ID, USA, Value of Distributed Preprocessing of Biomass Feedstocks to a Bioenergy Industry, Paper No: 066151, 2006 ASABE Annual International Meeting, Oreg on Convention Center, Portland, Oregon, 9 - 12 July 2006

214 Biomass Research Development Board. The Econ omics of Biomass Feed stocks in the United States. Occasional Paper 1, October 2008.

215 ICM website, Ethanol Production Process, http://www.icminc.com/ethanol/production_process (Supplemented with information provided by EPA’s Region 7).

216 Renewable Fuels Association website, Ho w Ethanol is Made: The Ethanol Production Process –Wet Milling, http://www.ethanolrfa.org/resource/made.

217 Renewable Fuels Associati on, Annual Energy Outlook 2006 (http://www.ethanolrfa.org/object s/pdf/outlook/outlook_2006.pdf)

218 POET website, Technology - BPX TM , http://www.poetenergy.com/learn/bpx.asp.

219 Kirkbride McElroy, Anduin , “Poe t, ISU partner for BPX research,” Ethanol Producer Magazine, http://www.ethanol-producer.com/ar ticle.jsp?ar ticle_id=3770, March 2008.

220 U.S. Environmental Protection Agency, Combin ed Heat & Power Part nership website, Basic Information, http://www.epa.gov/chp/basic/index.html.

221 Smeets, Edward, et. al. “Sustainability of Brazilian bio-ethanol”. August 2006

222 Saeman, J.F., Kinetics of Wood Saccharification: Hydrolysis of Cellulose and Decomposition of Sugars in dilute Acid at High Temperature , Industrial and Engineering Chemistry , 37(1): 43– 52 (1945). http://pubs3.acs.org/acs/journals/toc.page?inc oden=iechad&indecade=3& involume=37&inissue= 1]

223 Harris, E.E., Beglinger, E., Hajny, G.J., an d Sherrard, E.C., , Industrial and Engineering Chemistry , 37(1): 12–23 (1945) http://pubs3.acs.org/acs/journals/toc.page?inc oden=iechad&indecade=3& involume=37&inissue= 1]

224 DOE National Laboratories. “30x30 A Scenario for Supplying 30% of 2004 Motor Gasoline with Ethanol by 2030: A Production Scenario for Ce llulosic Ethanol from Corn Stover,” June 23, 2006.310 225 LaMonica, Martin. “Investor Vi nod Khosla: Advanced biofuels are closer than you think”. Accessed at: http://www.news.com/8301-11128_3-9811702-54.html

226 DOE. “Biomass Program: ABC’s of Biofuels”. Accessed at: http://www1.eere.energy.gov/biomass/abcs_biofuels.html#content

227 Starch Hydrolysis ; http://www.bio-link.org/pdf/starch.pdf

228 Glossary of Biomass Terms, National Renewable Energy Laboratory, Golden, CO. http://www.nrel.gov/biomass/glossary.html

229 Glossary of Biomass Terms, National Renewable Energy Laboratory, Golden, CO. http://www.nrel.gov/biomass/glossary.html

230 Condensation and Hydrolysis; http://www.biotopics .co.uk/as/disacchari deformation.html

231 BlueFire Ethanol. “Review of Compe ting Processes,” May 2006. Accessed at: http://www.bluefireethanol.com/images/Technology_Comparison_051206.ppt#295,1, 31 Musick Irvine, California 92618.

232 Stephanopoulos, Gregory, et. al., “Challeng es in Engineering Microbes for Biofuels Production,” Science , 315, 801, February 9, 2007.

233 Dipardo, Joseph, “Outlook for Bioma ss Ethanol Production and Demand,” Energy Information Administration, 2002.

234 Tao, Ling and Aden, Andy. November 2008. Techno-economic Modeling to Support the EPA Notice of Proposed Rulemaking (NOPR). Nati onal Renewable Energy Laboratory (NREL)

235 Aden, Andy, Ethanol Process Design and Economics Utilizing Co-current Dilute Acid Prehydrolysis and Enzymatic Hydrolysis fo r Corn Stover, Contract DE-AC36-99-GO10337, National Renewable Energy La boratory, June 2002.

236 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.

237 A. Aden, M. Ruth, K. Ibsen, J. Jechura, K. Neeves, J. Sheehan, and B. Wallace National Renewable Energy Laborat ory (NREL); L. Montague, A. Slayton, and J. Lukas Harris Group, Seattle, Washington, Ethanol Process Design and Economics Utilizing Co-Current Dilute Acid Prehydrolysis a nd Enzymatic Hydrolysis for Corn Stover ; June 2002;NREL is a U.S. Department of Energy Laboratory Operated by Midwest Research Institute • Battelle • Bechtel; Contract No. DE-AC36-99-GO10337

238 Graf, Angela, et. al., “Oregon Cellulose-Etha nol Study: An evaluation of the potential for ethanol production in Oregon using cellulose-based feedstocks,” Bryan & Bryan Inc and Oregon Office of Energy, 2000.

239 Tim Eggeman, Neoterics In ternational, Lakewood, CO 80228 , USA, Richard T. Elander, National Renewable Energy Laboratory, Go lden, CO 80401, USA, Process and economic analysis of pretr eatment t echnologies, Bioresource Technology 96 (2005) 2019–2025

240 Gray, K., et. al., “Bioethanol,” Current Opinion in Chemical Biology , 10:141-146, 2006.

241 Graf, op. sit.

242 Aden, Andy. December 10, 2009. “Feedstock C onsiderations and Impacts on Biorefining.” National Renewable Energy Laboratory

243 DOE, “From Biomass to Biofuels: A Roadmap to the Energy Future.” based on a workshop held in Rockville, MD, on December 7-9, 2005. As sited in Stephanopoulos, Gregory, et. al.,311 “Challenges in Engineering Micr obes for Biofuels Production,” Science , 315, 801, February 9, 2007.

244 Presentations of K.C. McFarland (Novozymes) a nd G. Anderl (Genencor International) at the World Congress on Industrial Bi otechnology and Bioprocessing, Orlando, FL, July 2006. As sited in Stephanopoulos, Gregory, et. al., “Challenges in Engi neering Microbes for Biofuels Production,” Science , 315, 801, February 9, 2007.

245 Genencor Launches First Ever Commercial Enzyme Pr oduct for Cellulosic Ethanol, Rochester, NY, World-Wire, Oc tober 22, 2007 Copyright © 2007,. All rights reserved. WorldWire is a resource provided by Environment News Service. http://worldwire.com/news/0710220001.html

246 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

247 Stephanopoulos, op. sit.

248 US. DOE. Technologies: Processing and Conversion. Accessed at: http://www1.eere.energy.gov/biomass/processing_conversion.html on October 28 , 2008

249 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

250 Aden, Andy, Mixed Alcohols from Woody Bi omass – 2010, 2015, 2022, National Renewable Energy Laboratory (NREL), September, 23 2009.

251 Lin Wei, Graduate Research Assistant, Lester O. Pordesimo, Assistant Professor Willam D. Batchelor, Professor, Department of Agricultural and Biological Engineering, Mississippi State University, MS 39762, USA, Ethanol Production from Wood: Comparison of Hydrolysis Fermentation and Gasification Biosynthesis, Paper Number: 076036, Written for presentation at the 2007 ASABE A nnual International Me eting. Minneapolis Convention Center, Minneapolis, MN, 17 - 20 June 2007

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

253 Ciferno, Jared P., Benchmar king Biomass Gasification Tec hnologies for Fuels, Chemicals and Hydrogen Production, National Energy Technology Laborator y, Department of Energy, June 2002.

254 S. Phillips, A. Aden, J. Jechura, and D. Dayton, National Renewable Energy Laboratory, Golden, Colorado 80401-3393, T. E ggeman, Neoterics In ternational, Inc., Thermochemical Ethanol via Indir ect Gasification and Mixe d Alcohol Synthesis of Lignocellulosic Biomass, Technical Report, NREL/ TP-510-41168, April 2007

255 Aden, Andy, Mixed Alcohols from Woody Bi omass – 2010, 2015, 2022, National Renewable Energy Laboratory (NREL), September, 23 2009.

256 BRI Energy Bioengineering Resources for Renewable Energy. “The Co-Production of Ethanol and Electricity From Ca rbon-based Wastes,” A Report fro m BRI Energy, Inc. Regarding a New Technology That Addresses Multiple Ener gy and Waste Disposal Solutions, March 2006.312 257 DOE EERE. “Biomass Program: Thermochemical Conversion of Corn Stover,” April 2006. Accessed at: http://www1.eere.energy.gov/biomass/pdfs/thermochemical_stover.pdf.

258 S. Phillips, A. Aden, J. Jechura, and D. Dayton, National Renewable Energy Laboratory, Golden, Colorado 80401-3393, T. E ggeman, Neoterics In ternational, Inc., Thermochemical Ethanol via Indir ect Gasification and Mixe d Alcohol Synthesis of Lignocellulosic Biomass, Technical Report, NREL/ TP-510-41168, April 2007

259 Davis, Ryan; Techno-economic analysis of current technology for Fischer-Tropsch fuels production, National Rene wable Energy Laborator y for EPA, August 14, 2009.

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

261 Zeman, Nicholas, “Thermoche mical Versus Biochemical,” Biomass Magazine , June 2007.

262 Information derived from staff-level communication with National Biodiesel Board personnel.

263 “Tyson ConocoPhillips Venture in Jeopardy.” The Morning News, article dated 9/26/08. http://www.nwaonline.net/articles/2008/09/26/business/092708fuelcredits.txt

264 See Syntroleum Investor Presentation, dated Novemb er 2009. Available here: http://www.syntroleum.com/Presentations/Syntr oleumInvestorPresentation.November%205.200 9.FINAL.pdf. Accessed December 16, 2009.

265 “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

266 Based on presentation material s by Lars Peter Lindfors date d 29 September 2009, available here: http://www.nesteoil.com/default.asp?path =1,41,538,2496,12947. Accessed December 16, 2009.

268 Total ethanol usage from EIA, Monthly Energy Review, Se ptember 2009 (Table 10.2) and EIA imports reported online at: http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm.

269 Total projected ethanol consumption according to a letter from Richard Newell, EIA Administrator to Lisa Jackson, EPA Administ rator dated October 29, 2009 (Table 1) and projected imports according to 2009 YTD reported online at: http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm.

270 110 th Congress of the United States of America, First Session, The Energy Independence and Security Act of 2007, House Rule 6 (December 19, 2007) available at: http://www.govtrack.us/congress/billtext.xpd?bill=h110-6.
271 Total ethanol usage from EIA, Monthly Ener gy Review, September 2009 (Table 10.2) and EIA imports reported online at: http://tonto.eia.doe.gov/dnav/pet/hist/mfeimus1a.htm.

272 Sources include Renewable Fuel s Association (RFA), Ethanol Biorefinery Loca tions (updated October 22, 2009) and Etha nol Producer Magazine (EPM), Produc ing plant list (last modified on October 22, 2009) in addition to information gathered from producer websites and follow-up correspondence.

273 Form 10-Q/A submitted by Greenshift Corporation to the United States Securities and Exchange Commission for the quarterly period ending June 30, 2009. The Q2 2009 SEC filing can be found at: http://www.greensh ift.com/pdf/GERS_Form10Q_Q209_FINAL.pdf

274 Spreadsheet provided to EPA by Neeharika Naik-Dhungel at EPA’s Combined Heat & Power Partnership on December 17, 2009.

275 Spreadsheet provided to EPA by Bruce Wo erner at Airgas on August 14, 2009.

276 Total plants less those denoted as “farmer owned” b ased on Renewable Fuels Association (RFA) Ethanol Biorefinery Loca tions (updated October 22, 2009). Deleted: 2008.

Deleted: 271 Ibid

Deleted: Ibid.313 277 “Valero Renewables to Purchase Three Ethanol Plants,” December 15, 2009. Valero press release available at: http://www.va lero.com/NewsRoom/Pages/PR_20091215_0.aspx

278 Based on Valero refinery information provided at http://www.valero.com/OurBusiness/OurLocations/

279 Sources include Renewable Fuel s Association (RFA), Ethanol Biorefinery Loca tions (updated October 22, 2009) and Ethanol Producer Magazine (EPM), Pr oducing, Not Pr oducing, Under Construction, and Expansions lists (last m odified on October 22, 2009) in addition to information gathered from producer websites and follow-up correspondence.

280 Data based on “An Analysis of the Projected Energy Use of Future Dry Mill Corn Ethanol Plants (2010-2030)”; Steffen Muelle r, University of Illinois at Chicago Energy Resource Center, October 10, 2007, Av ailable online at: http://www.chpcentermw.org/pdfs/ 2007CornEethanolEnergySys.pdf

281 Data based on “An Analysis of the Projected Energy Use of Future Dry Mill Corn Ethanol Plants (2010-2030)”; Steffen Muelle r, University of Illinois at Chicago Energy Resource Center, October 10, 2007

282 Data based on “An Analysis of the Projected Energy Use of Future Dry Mill Corn Ethanol Plants (2010-2030)”; Steffen Muelle r, University of Illinois at Chicago Energy Resource Center, October 10, 2007, with the exception of Membra ne Separation da ta based on conv ersation with Leland Vane, EPA

283 According to an e-mail from ADM’s Dean Frommelt dated May 7, 2009, “The new dry mills for Cedar Rapids, IA and Columbus, NE comm enced construction July 2007 and October 2006, respectively.” According to information posted on Riverland Biofuels we bsite, the Canton, IL plant broke ground in October 2006. According to the Southwest Iowa Renewable Energy website, the Council Bluffs, IA plant had a groundbreaking ceremony on November 11, 2006 (plant was assumed to break ground sometime shortly after that).

284 Ministry of Agriculture in Brazil (MAPA), http://www.agricultura.gov.br/ Accessed: April 3, 2009

285 F.O. Licht’s, “World Etha nol Markets: The Outlook to 2015,” pg. S-22 to S-23, 2006.

286 F.O. Licht’s, “World Ethanol and Biofue ls Report,” Vol. 5, No. 22, July 23, 2007.

287 Agra FNP, “Sugar and Ethanol in Brazil: A Study of the Brazilian Sugar Cane, Sugar and Ethanol Industries,” 2007.

288 Agra FNP, op. sit.

289 ANFAVEA (Associação Nacional dos Fabr icantes de Veículos Automotores Assessoria de Planejamento Econômico e Estatí stico Indústria Automobilística Brasileira - Empresas Associadas). Internal Sales in Brazil 2009. http://www.anfavea.com.br/tabelas.html, November 24, 2009.

290 Ministerio da Agricultura, Pecularia E Abastecimento (MAPA), “Brazilian Ethanol Production,” http://www.agricultura.gov.br/pls/portal/ docs/PAGE/MAPA/ESTATI STICAS/PR ODUCAO/06- PROD.%20BR%20%C1LCOOL.PDF, December 9, 2009.

291 Ewing, Elizabeth, “Pipeline Projects on Hold.” Ethanol Producer Magazine , July 2008.

292 Rothkopf, Garten, “A Blueprint for Green Energy in the Americas,” 2006.

293 Ibid.

294 World Biofuels: FAPRI 2007 Agricultural Outlook; OECD-FAO Agricultural Outlook 2007- 2016, 2007 (note: this was interpreted from a graph); Bioenergia: Liquid Biofuels, “18 Billion314 Liters a Year!” March 2007; Rothkopf, op. sit . (note: years 2007-2019 were interpreted from a graph); EPE, “Plano National de Energia 2030,” Presentation from Mauricio Tolmasquim, 2007 (note: years were interpreted from a graph) ; UNICA, “Sugarcane Industry in Brazil: Ethanol, Sugar, Bioelectricity” brochure, 2008.

297 Agra FNP, op. sit.

298 Carpenter, Claudia, “Sugar Gains Capped by Braz il Ethanol Expansion, Czarnikow Says,” Bloomberg , June 19, 2008.

299 UNICA, “Sugarcane as a key element against Global Warming to be highlighted at Green Week in Brussels,” Press Release on June 23, 2009.

300 F.O. Licht GmbH, “89 New Ethanol Facilities to Come Online in 2007-11 – BNDES,” F.O. Licht’s World Ethanol & Biofuels Report , Vol. 5, No. 22, July 23, 2007.

301 AFP, “Brazil says biofuel production not to blame for food crisis,” June 1, 2008.

302 Business News Americas, “Odebrecht to invest US$2.6 bn to Lead Ethanol Sector – Brazil,” June 28, 2007.

303 The Wall Street Journal, “ADM Plans Entry In to Sugar-Cane Ethanol in Brazil,” June 22, 2007.

304 Agra FNP, op. sit.

305 Petrobras Magazine No. 122. “Ethanol: Fr om Brazil to the World,” August 13, 2007.

306 Ibid.

307 Ewing, op. sit.

308 Rothkopf, op. sit.

309 Ibid.

310 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.

312 Agra FNP, op. sit.

313 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. (not e: only 2006, 2015 & 2025 values were reported, other values are interpolated); World Biofuels: FAPRI 2007 Agricultural Outlook; EPE, op. sit. (note: years were interpreted from a graph); UNICA, “Sugarcane Industry in Brazil: Ethanol, Sugar, Bioelect ricity” brochure, 2008.

314 Ewing, op. sit.

315 Walter, A. et. al., “Perspectives on Fuel Ethanol Consumption and Trade,” Biomass and Bioenergy , 32, 730-748, 2008.

316 AFP., “EU Deputies Seek to Limit Us e of Biofuels,” September 11, 2008.

317 Energy Information Administration (EIA), “R eference 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

318 BP, “BP Statistical Review of World Ener gy 2007 (revised with 2008 statistics) Historical Data,” http://www.bp.com/statisticalreview.

319 Walter, A., op. sit.

320 Ayoub PM. Biofuels for She ll-biomass based blending co mponents for transport fuels (gasoline and diesel). In: World biofuels symposium-China, Bei jing, 2006. As s ited in Walter, op. sit.

321 Ribeiro, F., “The New European Challenge for Brazilian Ethanol Exports,” Frost & Sullivan Market Insight , February 7, 2008.315 322 European Bioethanol Fuel A ssociation (eBio), “The Industry, Statistics: Pr oduction Data,” http://www.ebio.org/statistics.php?id=4, September, 2009.

323 European Bioethanol Fuel Association (e Bio), “Production Capac ity 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.

324 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.

325 Fukuda, Hisao, et. al.,“J apan Bio-fuels Production Report,” USDA, FAS, May 26, 2006. http://www.fas.usda.gov/gainfiles/200605/146197881.pdf

326 Iijima, Midori. (2009) “ Japan to Focus on Next Generation Biofuels,” USDA FAS GAIN Report.

327 Rothkopf, op. sit.

328 Fukuda, op. sit.

329 Ibid.

330 Rothkopf, op. sit.

331 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.

332 Iijima, op sit.

333 Rothkopf, op. sit.

334 Iijima, Midori. op. sit.

335 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

336 Ewing, op. sit.

337 Fukuda, op. sit.

338 Rothkopf, op. sit.

339 Iijima, op sit.

341 Singh, Santosh, “India: Biofue ls Annual 2009,” USDA FAS GAIN Report

342 Ibid.

344 Jagannathan, Prabha, “Fuel doping: Govt to rework pricing formula for ethanol” The
Economic Times , December, 23, 2009.

345 Nayak, D., “Weak Crude, Cane Shorta ge Hit India Etha nol Expansion” Wall Street Journal

, April, 1, 2009.

348 Ohga, op. sit.

349 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.

350 Renewable Fuels Associa tion (RFA), “2008 World Fu el Ethanol Production, ” http://www.ethanolrfa.org/industry/statistics/#E, December 23, 2009.

352 Ohga K. & Tatsuji K. Biofuels Policies in Asia: Trade effects on World Agricultural and Biofuels Trade. Presentation to USDA Ag ricultural Outlook Forum, March 2, 2007.

353 Beckman, Chanda et. al., “China-Peoples Republic of: Biofuels Annual” USDA FAS GAIN Report, July 17, 2009.

354 Rothkopf, op. sit. Deleted: Ibid.316 355 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

356 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.

357 Rothkopf, op. sit.

358 Beckman, op. sit.

359 Ohga, op. sit . Note: Metric Tons are assumed to be of ethanol and values are converted to ethanol volumes based on the density of ethanol and other conversion factors.

360 Rothkopf, op. sit.

361 Ibid.

362 Ibid.

363 F.O. Licht GmbH, “New Ethanol Plants Will Rely on Non-Grain Feedstocks,” F.O. Licht’s World Ethanol & Biofuels Report , Vol. 5, No. 22, July 23, 2007.

364 Rothkopf, op. sit.

365 EIA, “U.S. Oxygenates: Fuel Ethanol Im ports,” Last updated on October 10, 2008. http://tonto.eia.doe.gov/dnav/pet/pet_move_impcus_a2_nus_EPOOXE_im0_mbbl_m.htm

366 Joseph, Ken, “Argentina Bio-Fuels Argentin e Bio-Fuels Report 2007,” USDA, FAS, May 21, 2007. http://www.fas.usda.gov/gainfiles/200706/146291490.pdf

367 Deborah O’Connell, et. al., “Biofuels in Aust ralia - Issues and Prospects. A Report for the Rural Industries Research and Development Corporation,” CSIRO Australian Government Rural Industries Research and Developm ent Corporation, May 2007.

368 Roberts, Greg, “Rees scraps biofuel mandates,” The Australian: Online Newspaper of the
Year , September 20, 2008. http://www.theaustralian.news.com.au/story/0,25197,24373888- 11949,00.html

369 Sobolik, Jessica, “Canadian Government Passes Renewable Fuels Standard,” Ethanol Producer Magazine , August 2008.

370 Pinzon, L., “Colombia Bio-fuels Annua l 2007,” USDA, FAS, June 1, 2007. http://www.fas.usda.gov/gainfiles/200706/146291386.pdf

371 Chavez, L., et. al., “Mexico Bio-fuels Annual Report 2007,” USDA, FAS, June 12, 2007. http://www.fas.usda.gov/gainfiles/200706/146291366.pdf

373 Office of the United States Trade Representative (USTR), “Caribbean Basin Initiative,” November 12, 2008. http://www.ustr.gov/Trade_Development/Preference_Programs/CBI/Section_Index.html

374 Bryan, Tom, “Entering Tariff-Free,” Ethanol Producer Magazine, January 2004.

375 Office of the United States Trade Representative (USTR), “Ethanol Provisions in the CAFTA-DR,” July 2007.

376 Bryan, op. sit.

377 Rapoza, Kenneth, “UPDATE: Tax Loophole Help s US Import Ethanol ‘Duty Free’- ED&F,”
INO News

, Dow Jones Newswires , March 2008. http://news.ino.com/

378 Peter Rohde, “Senate Finance May Take Up Dr awback Loophole As Part of Energy Bill,” EnergyWashington Week , April 18, 2007. As sited in Yac obucci, Brent, “Ethanol Imports and the Caribbean Basin Initiative,” CRS Report for Congress, Order Code RS21930, Updated March 18, 2008.317 379 Perkins, Jerry, “BRAZIL: Loophole Hurt U.S. Ethanol Prices,” De sMoinesRegister.com, October 18, 2007.

380 Public Law Version 6124 of the Farm Bill. 2008. http://www.usda.gov/documents/Bill_6124.pdf.

381 Lundell, Drake, “Brazilian Ethanol Export Surge to End; U.S. Customs Loophole Closed Oct. 1,” Ethanol and Biodiesel News , Issue 45, November 4, 2008.

382 MacDonald, T., et. al., “Ethanol Supply Outlook for California,” California Energy Commission, October 2003. http://www.ethanolrfa .org/objects/documents/ 100/castaffreport.pdf

383 Petrojam Limited, “Official Opening of Petrojam Ethanol Limited,” November 12, 2008. http://www.pcj.com/petrojam/whats_new.htm

384 Petrojam Limited, “About Us,” November 12, 2008. http://www.petrojambunkering.com/petrojam_aboutb.htm

385 F.O. Licht GmbH, “Company News- JB G Commences Fuel Ethanol Production,” F.O. Licht’s World Ethanol & Biofuels Report , Vol. 5, No. 22, July 23, 2007.

386 Email Correspondence with Jeffrey Tu ite, ED&F Man, September 6, 2007.

387 Yacobucci, Brent, “Ethanol Imports and the Caribbean Basin Initiative,” CRS Report for Congress, Order Code RS21930, Updated March 18, 2008.

388 Email Correspondence with Jeffrey Tu ite, ED&F Man, September 6, 2007.

389 Ethanol Producer Magazine, “Ethanol Dehydration Facility to be Built in Trinidad,” December 2006.

390 Etter, Lauren, and Millman, Joel, “Ethanol Tariff Loophole Sparks a Boom in Caribbean Islands Build Plants To Process Brazil’s Fuel; Farm Belt Cries Foul,” Wall Street Journal , March 9, 2007.

391 Homer, Louis, “Another Energy Sector St imulus,” PetroleumWorld.com. November 22, 2006. http://www.petroleumworldt rinidad.com/storytrini06112606.htm

392 Etter, op. sit.

393 Browne, J., “Angostura La unches US$11m Ethanol Plant,” The Trinidad Guardian . August 6, 2004. http://www.guardian.co.tt/archives/2004-08-06/business1.html

394 Email Correspondence with Jeffrey Tu ite, ED&F Man, September 6, 2007.

395 Ramjeet, Oscar, “Barbados to Build $72 Million Ethanol Dehydration Plant,” Caribbean Net News, August 22, 2008.

396 Jamaica Gleaner News, “US $36m Ethanol Plant for Barbados,” August 23, 2008. http://www.jamaica-gleaner.com/gleaner/20080823/business/business1.html

397 Email Correspondence with Jeffrey Tu ite, ED&F Man, September 6, 2007.

398 Bryan, op. sit.

399 Etter, op. sit.

400 Ibid.

401 Email Correspondence with Jeffrey Tuite, ED&F Man, September, 7, 2007.

402 Etter, op. sit.

403 Bell Bio-Energy funding based on Press Release, “Defense En ergy Support Center and Army Test Turning Waste into Fuel,” (October 2, 2008) available at: http://www.bellbioenergy.com/html/newsle tter/Press%20Releases/DLA_PR_10-3-08.pdf. Clearfuels Technology funding based on DOE Press Release, “Recovery Act Announcement: Secretaries Chu and Vilsack Announce More th an $600 Million in Advanced Biorefinery Projects,” (December 4, 2009) available at: http://www.energy.gov/8352.htm . Verenium318 funding based on DOE Press Releas e, “DOE to Provide up to $40 Million in Funding for SmallScale Biorefinery Projects in Wisconsin and Louisiana,” (July 14, 2008) available at: http://www.energy.gov/news/6413.htm.

404 Letter from Richard Newell, EIA Administrator to Lisa Jackson, EPA Administrator dated October 29, 2009 (Table 2).

405 DOE Press Release, “Recove ry Act Announcement: Secretar ies Chu and Vilsack Announce More than $600 Million in Advanced Biorefinery Projects,” (December 4, 2009) available at: http://www.energy.gov/8352.htm

. 406 Based on the following DOE press releases, “U .S. Department of Ener gy Selects First Round of Small-Scale Biorefinery Projects for Up to $114 Million in Federal Funding,” (January 29, 2008) available at: http://www.energy.gov/news/5903.htm; “DOE Selects 3 Small-Scale Biorefinery Projects for Up to $86 Million of Federal Funding in Maine, Tennessee and Kentucky,” (April 18, 2008) av ailable at: http://www.energy.gov/news/6164.htm; “DOE to Provide up to $40 Million in Funding for Small- Scale Biorefinery Projects in Wisconsin and Louisiana,” (July 14, 2008) available at: http://www.energy.gov/news/6413.htm ; “Recovery Act Announcement: Secretaries Chu and Vilsack Announ ce More than $600 Million in Advanced Biorefinery Projects,” (December 4, 2009) av ailable at: http://www.energy.gov/8352.htm

. 407 DOE Press Release, “DOE Selects Six Cellulosic Ethanol Plants for Up to $385 Million in Federal Funding,” (February 28, 2007) availa ble at: http://www.energy.gov/news/4827.htm.

408 110 th Congress of the United States of America, Second Session, The Food, Conservation, and Energy Act of 2008, House Rule 6124 (June 18, 2008) available at: http://www.usda.gov/documents/Bill_6124.pdf,

409 DOE Press Release , “DOE Selects Five Ethanol Conv ersion Projects for $23 Million in Federal Funding ,” (March 27, 2007) available at: http://www.energy.gov/print/4896.htm.

410 DOE Press Release , “Energy and Agriculture Depts. Provide $8.3 Million in Funding for Biofuels Research ,” (June 7, 2007) available at: http://www.energy.gov/print/5115.htm.

411 DOE Press Release , “Energy Department Selects Three Bioenergy Research Centers for $375 Million in Federal Funding ,” (June 26, 2007 ), http://www.energy.gov/print/5172.htm.

412 DOE Press Release , “Department of Energy to Invest up to $7.7 Million for Four Biofuels Projects ,” (December 4, 2007) available at: http://www.energy.gov/print/5757.htm.

413 DOE Press Release , “U.S. Department of Energy to Inve st up to $33.8 Million to Further Development of Commercially Viable Renewable Fuels ,” (February 26, 2008) available at: http://www.energy.gov/print/6015.htm.

414 DOE Press Release , “USDA, DOE to Invest up to $18 .4 Million for Biomass Research, Development and Demonstration Projects ,” (March 4, 2008) available at: http://www.energy.gov/print/6035.htm.

415 Midwest Governors Associ ation, “Energy Security and Climate Stewardship Platform for the Midwest 2007,” (November 2007) available at: http://www.midwesterngovernors.org/resolutions/Platform.pdf

. 416 Midwest Governors Association, “The Midwestern Energy Ac cord,” (October 2009) available at: www.midwesterngovernor s.org/publications.htm.

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

418 Capacity data taken from Na tional Biodiesel Board as of November 2009. Production, import, and export figures taken from EIA M onthly Energy Review, Table 10.4 as of December 2009. Deleted: U.S. Department of Energy

Deleted: ” (Press Release),

Deleted: , March 27, 2007

Deleted: U.S. Department of Energy

Deleted: ” (Press Release),

Deleted: , June 7, 2007

Deleted: U.S. Department of Energy

Deleted: ” (Press Release & Attachments

Deleted: , June 26, 2007

Deleted: U.S. Department of Energy

Deleted: ” (Press Release),

Deleted: , December 4, 2007

Deleted: U.S. Department of Energy

Deleted: ” (Press Release),

Deleted: , February 26, 2008

Deleted: U.S. Department of Energy

Deleted: ” (Press Release),

Deleted: , March 4, 2008

Deleted: , Published November 2007.

Deleted: October319 419 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.

420 Industry data for 2008 taken from Nati onal Biodiesel Board fact sheets at http://www.biodiesel.org/buyingbiodiesel/pr oducers_marketers/Producers%20Map-Existing.pdf and http://www.biodiesel.org/pdf_files/fu elfactsheets/Production_g raph_slide.pdf (both accessed April 27, 2009).

422 “Tyson ConocoPhillips Venture in Jeopardy.” The Morning News, article dated 9/26/08. Available in the docket.

423 See Syntroleum Investor Presentation, dated Novemb er 2009. Available here: http://www.syntroleum.com/Presentations/Syntr oleumInvestorPresentation.November%205.200 9.FINAL.pdf. Accessed December 16, 2009.

424 “Tyson's Fats to Fuel Plant on Schedule.” The Morning News, article dated 10/6/08. Available in the docket.

425 Syntroleum Investor Presentation dated November 5, 2009. Ava ilable in the docket or at: http://www.syntroleum.com/Presentations/Syntr oleumInvestorPresentation.November%205.200 9.FINAL.pdf

426 Ethanol and Pipeline Transpor tation 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

427 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

428 Kinder Morgan announcement that their Cent ral Florida Pipeline from Tampa to Orlando ships batches of ethanol along with batches of gasoline. http://www.kindermorgan.com/business/products_pipelines/

429 “POET Joins Magellan Midstream Partners to Assess Dedicated Etha nol Pipeline”, March 2009, http://www.poet.com/news/showRelease.asp?id=155

430 Kinder Morgan announcement that their Cent ral Florida Pipeline from Tampa to Orlando ships batches of ethanol along with batches of gasoline. http://www.kindermorgan.com/business/products_pipelines/

431 “Analysis of Fuel Ethanol Tr ansportation Activity and Poten tial Distribution Constraints”, prepared for EPA by Oak Ridge National Laboratory, March 2009.

432 “Analysis of Fuel Ethanol Tr ansportation Activity and Poten tial Distribution Constraints”, prepared for EPA by Oak Ridge National Laboratory, March 2009.

433 “The Importance of Adequate Rail Investment”, Associa tion of American Railroads, http://www.aar.org/GetFile.asp?File_ID=150

434 American Association of State Highway and Transportation Officials (AASHTO) FreightRail Bottom-Line Report, 2003.

435 Association of American Railroads (AAR), National Rail Freight Infrastructure Capacity and Investment Study , September 2007.

436 “Analysis of Fuel Ethanol Tr ansportation Activity and Poten tial Distribution Constraints”, prepared for EPA by Oak Ridge National Laboratory, March 2009. Deleted: Presenation320 437 Transportation activity data output spreadsheet that accompanied the report entitled “Analysis of Fuel Ethanol Transportation Activity and Potential Distribution Constraints”, prepared for EPA by Oak Ridge National Laboratory, March 2009.

438 Transportation activity data output spreadsheet that accompanied the report entitled “Analysis of Fuel Ethanol Transportation Activity and Potential Distribution Constraints”, prepared for EPA by Oak Ridge National Laboratory, March 2009.

439 “Barge Transportation in the United States”. Timothy Casey, Presentation at the MARE Forum USA, 2006, http://www.mareforum.com/ENERGY_TRANSPORTATION_USA_2006_PRESENTATIONS_ files/CASEY.pdf

440 Energy Information Administration (EIA) hist orical company level ethanol and gasoline import data: http://www.eia.doe.gov/oil_gas/petroleum/data_publications/company_level_imports/cli_historical.html

441 “Analysis of Fuel Ethanol Tr ansportation Activity and Poten tial Distribution Constraints”, prepared for EPA by Oak Ridge National Laboratory, March 2009. The list of projected ethanol import locations is contained in Tabl e 3 in Section 3.3.2 of this report.

442 “Analysis of Fuel Ethanol Tr ansportation Activity and Poten tial Distribution Constraints”, prepared for EPA by Oak Ridge National Laboratory, March 2009.

443 Transportation activity data output spreadsheet that accompanied the report entitled “Analysis of Fuel Ethanol Transportation Activity and Potential Distribution Constraints”, prepared for EPA by Oak Ridge National Laboratory, March 2009.

444 “The U.S. Truck Driver Shortage: Analysis a nd Forecasts”, Prepared by Global Insights for the American Trucking Association, May 2005. http://www.truckline.com/NR/rdonlyres/E2E789CFF308-463F-8831-0F7E283A0218/0/ATADriverShortageStudy05.pdf 445 Our projections of the motor fuel demand can be found in chapter 1.2 of this RIA.

446 “Renewable Fuel Standard Challenges Faced by Terminals”, Andrea Grant, Independent Fuel Terminal Operators Association, May, 13, 2008, presentation at the 2008 Society of Automotive Engineers Government-Industry Meeting.

447 “Infrastructure Requirements for an Expa nded Fuel Ethanol Industry”, Downstream Alternative Incorporated, January 15, 2002.

448 A discussion of the volumes of biofuels we es timate would be used absent the RFS2 standards is located in chapter 1.2 of this RIA.

449 A discussion of the estimated number of term inals that carry diesel fuel is contained in Chapter V of the Regulatory Impact Analysis to the final highway diesel fuel rule http://www.epa.gov/otaq/highway-diesel/regs/ria-v.pdf , EPA Docket A-99-06.

450 “Renewable Fuel Standard Challenges Faced by Terminals”, Andrea Grant, Independent Fuel Terminal Operators Association, May, 13, 2008, presentation at the 2008 Society of Automotive Engineers Government-Industry Meeting.

451 “Renewable Fuel Standard Challenges Faced by Terminals”, Andrea Grant, Independent Fuel Terminal Operators Association, May, 13, 2008, presentation at the 2008 Society of Automotive Engineers Government-Industry Meeting.

452 Chapter 1.7 of this RIA contains a discussion of our projections regarding the prevalence of flexible fuel vehicles in the vehicle fleet and the relative volumes of E85 versus E10 that would be used in these vehicles.

453 “Summary Data on Diesel Fuel Retailers”, Memorandum to the Docket, Jeffery Herzog, U.S. EPA, March 23, 2000, EPA Docket A-99-06, Docket Item II-B-07.321 454 2007 National Association of C onvenience Stores State of the Industry survey data www.nacsonline.com as reported in the National Petrol eum News MarketFacts 2007, October 2007.

455 “Diesel Throughput Volume by Percentage of Diesel Fuel Retailers”, Memorandum to the Docket, Jeffery Herzog, U.S. EPA, May 05, 2000, EPA Docket A-99-06, Docket Item II-B-14.

456 National Petroleum Ne ws, “2008 marketfacts”, www.npnweb.com

457 National Petroleum News, “2007 marketfact s”, Volume 99, Number 10, October 2007, www.npnweb.com

458 The National Ethanol Vehicle Coalition estimate of E85 refueling facilities is located at http://www.e85refueling.com/ estimates http://www.e85refueling.com/

459 The “NEAR85” estimate of E85 retail facilities is located at http://www.neare85.com/

460 Letter from Richard Newell, EIA Administrator to Lisa Jackson, EPA Administrator dated October 29, 2009 (Table 1).

461 Based on comments provided by NPRA (EPA-HQ-OAR-2005-0161-2124.1)

462 Hart Energy Consulting, North American Ethanol Database Service, Revised November 2009. Included under the permission of Fred Potter, Executive VP at Hart.

463 Quadrillion BTUs based on EIA, AEO 2007 (Table 2), EIA, AEO 2008 Final Release (Table 2), and EIA, AEO 2009 – A RRA Update (Table 2).

464 1998-2005 FFV sales based on DOE’s EERE data available at: www.eere.energy.gov/afdc/data/index.html

465 EIA, Annual Energy Outlook 2009 – ARRA Update (Table 57).

466 ibid

467 Ethanol Producer Magazine, “Aut omakers Maintain FFV Targets in Bailout Plans.” February 2009. FFV commitments reiterated in Chrysler Restructuring Plan for Long-Term Viability and General Motors Corp. 2009-2014 Restructuring Pl an presented to the U.S. Department of Treasury on February 17, 2009.

468 111 th Congress of the United States of America, First Session, The Open Fuel Standard Act of 2009, House Rule 1476 (March 12, 2009) available at: http://www.opencongress.org/bill/111- h1476/text.

469 EIA, Annual Energy Outlook 2007 (Table 47).

470 For more information, visit: http://www.afdc.energy.gov/afdc/ . The $100 per FFV estimate is also cited by others, includi ng Growth Energy: http://www.growthenergy.org/2009/Brochures/Fueling_Ethanol.pdf.

471 National Ethanol Vehicle Coalition, 2009 FFV Purchasing Guide.

472 Proposed Rulemaking to Establish Light-Duty Vehicle GHG Emission Standards and Corporate Average Fuel Economy Standards, 74 FR 49454 (September 28, 2009).

473 NEVC website, accessed on November 23, 2009

474 For more information, visit: http://www.m idwesterngovernors.org/re solutions/Platform.pdf

475 http://frwebgate.access.gpo.gov/cgibin/getdoc.cgi?dbname=111_cong_bills&docid=f:h1enr.pdf

476 Proposed Rulemaking to Establish Light-Duty Vehicle GHG Emission Standards and Corporate Average Fuel Economy Standards, 74 FR 49454 (September 28, 2009).

477 EIA, Annual Energy Outlook 2009 - ARRA Update (Table 17).322 478 NEVC, “2008 Purchasing Guide for Flexible Fuel Vehicles.” Refers to all mass produced 3.5 and 3.9L Impalas. However, it is our understa nding that consumers may still place special orders for non-FFVs.

479 Based on average E85 and regular unleaded gasoline prices reported at http://www.fuelgaugereport.com/ on November 23, 2009.

480 110 th Congress of the United States of America, Second Session, The Food, Conservation, and Energy Act of 2008, House Rule 6124 (June 18, 2008) available at: http://www.usda.gov/documents/Bill_6124.pdf,

481 EIA, Annual Energy Outlook 2009 - ARRA Update (Table 17).

482 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).

483 Greene, David, Survey Evidence on the Importance of Fuel Availability to Choice of Alternative Fuels and Vehicles, Prepar ed by Oak Ridge National Laboratory ( November 11, 1997 ), available at: http://ntl.bts.gov/lib/000/700/723/survey.pdf

. 484 http://www.dtnethanolcenter.com/index.cfm?show=10&mid=32

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

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

487 http://www.epa.gov/OMS/regs/fuels/additive/lettertogrowthenergy11-30-09.pdf

488 ORNL, Transportation Energy Data Book, Edition 27 (Table 2.5). 489 Ethanol Producer Magazine we bsite, Ethanol Plant Lists (Pr oducing, Not Producing, Under Construction, Expansions), http://www.ethanolproducer.com/plant -list.jsp, Modified on April 14, 2008.

490 Renewable Fuels Association (RFA) we bsite, Ethanol Biorefinery Locations, http://www.ethanolrfa.org/industry/locations, Updated on April 2, 2008.

491 International Trade Commission 2005-2007 historical ethanol import data as reported by the Renewable Fuels Association, http://www.ethanolrfa.org/industry/statistics/

492 Communication from Douglas Newman, Interna tional Trade Commission to Doris Wu, EPA, May 20, 2008.

493 Energy Information Admini stration historical gasolin e and ethanol import data: http://www.eia.doe.gov/oil_gas/petroleum/data_pu blications/company_level_imports/cli_historic al.html

494 NASS database. http://www.nass.usda.gov/

495 USDA, WGA, Bioenergy Strate gic Assessment proj ect findings upcoming as noted in report WGA. Transportation Fuels for the Future Biofuels : Part I. 2008.

496 NASS database. http://www.nass.usda.gov/

cdxcvii U.S. Department of Energy, Energy Efficiency and Renewable Energy, Transportation Energy Book: Edition 26 , Prepared by Oak Ridge National Laboratory, ORNL-6978, 2007 (Table 2.5).

cdxcviii U.S. Department of Energy, En ergy Information Administration, Petroleum Marketing Annual 2006

, http://tonto.eia.doe.gov/FTPROOT/petroleum/048706.pdf , August 2007 (Tables 31, 34 & 48).

cdxcix 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). Deleted:

, http://ntl.bts.gov/lib/000/700/723/survey. pdf

,323 d American Petroleum Institute, Gasoline Tax Report, http://www.api.org/statistics/fueltaxes/upload/January_2008_gasoline_and_diesel_summary_pag es-2.pdf , January 2008.

di See http://www.afdc.energy.gov/afdc/fuels/biodiesel_laws.html . Incentives were evaluated as of October 2008.

dii Status taken from the online plant database as of October 2009. Current data is available at http://www.biodiesel.org/buyingbiodiesel/plants/showall.aspx

diii Industry data for 2008 taken from Nati onal Biodiesel Board fact sheets at http://www.biodiesel.org/buyingbiodiesel/pr oducers_marketers/Producers%20Map-Existing.pdf and http://www.biodiesel.org/pdf_files/fu elfactsheets/Production_g raph_slide.pdf (both accessed April 27, 2009).

div

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

dv Energy Information Administration, 2005 Prim e Supplier Sales Volumes for No. 2 Diesel. Accessed 10/7/2008. http://tonto.eia.doe.gov/dnav/pet/pet_cons_prim_a_EPD2D_P00_Mgalpd_a.htm

dvi Energy Information Administration, Fuel Oil and Kerosene Sales 2006, Table 16. 2005 data column used. http://www.eia.doe.gov/pub/oil_gas/petroleum/da ta_publications/fuel_oil_and_kerosene_sales/c urrent/pdf/table16.pdfPage 4: [1] Deleted Author 

### The fuel cost savings from the increased use of renewable fuels calls into question the degree to which the renewable fuel volumes mandated by RFS2 may occur due simply to market forces (as was the case for RFS1), or whether the RFS2 standards are binding and forcing the volumes.

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### ascertain how much of the impacts quantified in this RIA might be due to the natural growth in renewable fuel use due to

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### as crude oil prices rise versus what mi ght be forced by the RFS2 standards. Regardless, the impacts quantified in this RIA can be attributed to the increased use of renewable fuels needed to reach the RFS2 mandates.

That being said, we believe it is likely that the majority of the impacts estimated in this RIA will in fact result from the RFS2 standards. We reach this conclusion for several reasons. First, the renewable fuel co sts do not fall below those of gasoline and diesel for a number of years. Thus, the RFS2 standards are clearly binding in the early years of the program. Second, we are unlikely to reach the 2022 volumes without investments in the early years. The renewable fuel costs we project in 2022 presume investments ramp up quickly due to the RFS2 mandate, leading to increased learning and reduced costs over time.

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### we believe it is unlikely that these investments would occur anytime in the near future and at the rate needed absent

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### In 2007, the EU produced 58 percent of worldwide biodiesel. Another 20 percent was produced in the U.S., with the remainder split between South America and the rest of the world. i



### EU biodiesel output increased from 200 million gallons in 2000 to 2.3 billion gallons in 2008. ii 

### According to some analysts, however, the EU does not have the agricultural capacity to expand oilseed production and in comparison to other climates, is not particularly good for oilseed production. iii 

### Estimates for future EU biodiesel production appear to be roughly 2.5 billion gallons by 2017. iv



### 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. v 

### Even with the increase in domestic production, however, it seem s likely that the EU’s future biofuels consumption goals will not be met.

In 2007, the European Commission (EC) proposed a binding minimum target requiring 10 percent biofuel use for transport by 2020. vi,vii 

### The International Energy Outlook forecasts OECD European countries will consume 147 billion gasoline gallons equivalent (gge) of transportation fuel in 2010, growing to 151 gge by 2020. Currently, approximately 60 percent of th e EU’s transportation fuel demand is met by diesel.

### Assuming this split continues in the futu re, a 10 percent biofuel requirement would translate to roughly 8 billion gallons of biodiesel demand by 2017. Thus, it appears likely that the EU will not be able to produce enough biodiesel to meet its goals by 2020 and will need to depend on other countries to make up the remaining 5.8 billion gallon demand (after accounting for dom estic production of 2.2 billion gallons as estimated from above). So not only will the EU, the largest current producer of biodiesel, not have any biodiesel available for export in the future; they will likely be a net importer competing with the U.S. for surplus biodiesel supplies.

As imports of finished biodiesel (or biod iesel 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 lim ited historical data from which to better understand the U.S.’s position to import biodie sel. Alternatively, we analyzed the following countries that have been noted as having a large potential for producing biodiesel: Brazil, Malaysia , Indonesia, and India.

Currently, there is a large interest in Brazil to develop a strong biodiesel program. As Brazil has mandates of B2 by 2008 and B5 by 2013 much of its production of biodiesel will be consumed domestically before any biodiesel will be available for exports. viii 

### If the mandates as well as Brazil’s bi odiesel production goals are met, this would mean that approximately 500 million ga llons could be available for exports by 2010 and around 600 million gallons by 2020. ix 

### 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 dema nding biodiesel, with the amount allocated to the U.S. uncertain at this point in time. We also analyzed the biodiesel situation in the top two world producers of palm oil, Malaysia and Indonesia. Although Malaysia and Indonesia have a large potential for biodiesel production from palm oil, these countri es appear to be marketing their exports to European and Asian nations as well as impl ementing their own biofuels goals. In fact, Malaysia is anticipating biodi esel export opportunities in the European market and is expected to export biodiesel specifically to Europe in the range of 100-120 million gallons by 2010. x 

### This volume is still relatively sm all 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, Ma laysia is planning on introducing a B5 mandate which could demand up to 166 million gallons of biodiesel. xi 

### Indonesia has a smaller mandate of B2.5, as a decline in fossil fuel prices and the increase in crude palm oil prices resulted in the decrease from its original B5 mandate. xii 

### In fact, historically, palm oil prices have been lower than soybean and rapeseed oil, suggesting that the use of palm oil could be the most cost-effective. xiii 

### However, in 2006, palm oil prices began to track soybean and rapeseed oil prices. xiv 

### Since feedstock costs make up the largest portion of production costs for biodiesel, this suggests that the production of biodiesel may not be profitable if palm oil prices rema in high. With Malaysia and Indonesia’s eyes

### set on importing biodiesel to the EU and As ian nations, possible biodiesel mandates in the future, and increases in palm oil feedstock costs, it seems unlikely that the U.S. will receive large volumes of biodiesel from this part of the world.

As described above, anot her potential source of biofue l feedstock is jatropha. Although the potential for India to produce biodies el from jatropha is large, there are still great uncertainties as to whether India can meet even its own biodiesel goals (i.e., B20 by 2020) xv 

### , let alone the goals of other nations. Hi storically, India has neither imported nor exported bio-fuels for fuel purposes, nor doe s the government provide any financial assistance for these products. Given that large-scale cultivation of jatropha has yet to be seen, and that jatropha has unpredictable yi elds, it seems unlikely that India could provide large volumes of biodiesel to the U.S. xvi



### Our analysis of the countries with th e 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. Supplie s to the U.S. will be limited by factors such as mandates and goals of other countri es, preferential shipme nt of biodiesel to European and Asian nations, and how quickly non-traditional crops such as jatropha can be developed. Thus, we are not forecasting imports of biodiesel to the U.S. for our analyses.

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### 0.25 billion gallons of

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### biofuel

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### In the past, India’s largest sugar a nd ethanol manufacturing company (Bajaj Hindusthan) has tried to acquire ethanol production plants in other countries with large sugarcane outputs (i.e. Brazil). This way, the company can increase its ethanol production. Yet after several m onths, the company was unable to come to any concrete agreements. xvii

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### 12.

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 could increase the ethanol consumption potential from conventional vehicles to about 19 billion gallons. Under our primary

### RFS2 control case (shown in Figure 1.7-12), E15 could postpone the blend wall by up to five years, or to 2019. Although E15 would fall short of meeting the RFS2 requirements under this scenario, it could provide in terim relief while the country ramps up nonethanol cellulosic biofuel production and/or expands E 85/FFV infrastructure.

Under our low-ETOH case, a partial waiver for E15 could eliminate the need for additional FFV/E85 infrastructure all together. Similarly, for our high-ETOH case, E15 could postpone the blend wall by about 3 years from 2013 to 2016. These scenarios are shown in Figures 1.7-13 and 1.7-

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### Figure 1.7-13 Max E15 Ethanol Consumption Compared 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 Blendwalli 

### F.O. Licht’s World Ethanol and Biofuels Report. Vol 6, No 11, p.203. Feb 15, 2008.

ii 

### Figures taken from European Biodiesel Board website as of December 2009. See http://www.ebb-eu.org/stats.php.

iii 

### DTN Ethanol Center, ”EU Biodiesel F eedstock Challenge,” October 11, 2007, http://www.dtnethanolcenter.com/index.cfm?show=10&mid=66&pid=27

iv



### World Biofuels: FAPRI 2008 Agricultural Outlook. http://www.fapri.org/outlook2008/text/14Biofuels.pdf, November 3, 2008.

v 

### Biofuels Barometer. Geographic Information System: EurObserv'ER http://www.eufores.org/index.php?id=29, November 3, 2008.

vi 

### EUROPA Press Release, “Stricter fuel sta ndards to combat climate change and reduce air pollution,” Jan. 31, 2007.

vii 

### EU Press Release, “2782 nd 

### Council Meeting on Transpor t, Telecommunications, and Energy, February 15 th 

### , 2007, Brussels, Council of the European Union,” http://www.consilium.europa.eu/Newsroom.

viii 

### Ministry of Mines and Energy, “The Brazilian Experience with Biofuels,” Presentation by Ricardo de Gusmao Dornelles, June 1, 2007.

ix 

### EPE, “Plano National de Energia 2030.” Presentation from Mauricio Tolmasquim, 2007.

x 

### Asian Palm Oil for Euro Biodiesel, 2005 as quoted in Ohga K. & Tatsuji K., “Biofuels Policies in Asia: Trade effects on World Agricultural and Biofuels Trade,” Presentation to USDA Agricultural Outlook Forum, March 2, 2007.

xi 

### 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.

xii 

### USDA FAS, “Gain Report. Indonesia Bio- Fuels Biofuels Annual 2007,” June 13, 2007.
xiii 

### USDA FAS, “Palm oil continues to dominate global consumption in 2006/2007,” http://www.fas.usda.gov/oilseeds/ circular/2006/06-06/Junecov.pdf

xiv



### Dato’ Dr. Mohd. Basri Wahid, “Malaysi an Palm Oil Board. Presentation: Technological Progress and Commerciali zation of Biodiesel in Malaysia.”

xv



### USDA FAS, “Gain Report. India Bio-fuels Annual 2007,” June 1, 2007.

xvi 

### Fairless, op. sit.
xvii 

### Regaldo, Antonio, et. al., “Ethanol Gi ants Struggle to Crack Brazil Market,” Wall Street Journal , September 10, 2007.