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Mark J. Riedy, Esq.PartnerAndrews Kurth LLP1350 I Street, NW, Suite 1100, Washington, D.C., USA 20005Office: 202-662-2756; Mobile: 703-201-6677Email: markriedy@andrewskurth.com Website: www.andrewskurth.com

The Challenges of Biofuels Finance – Fuel Ethanol, Biodiesel and Renewable Diesel 2008 Farm To Fuel Summit Program

Rosen Shingle CreekOrlando, FloridaJuly 30-August 1, 2008

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Andrews Kurth LLP

Mark Riedy, Esq., Partner, Andrews Kurth LLP Has Represented Clients In Renewable Energy (Fuels Power) Project Finance

Since 1978, Domestically And Internationally.

A Founder And Original General Counsel:• Renewable Fuel Association –1979-1984.• Clean Fuels Development Coalition – since 1985.• Clean Fuels Foundation – since 1990.• American Council On Renewable Energy – since 2001.

A Key Lobbyist on The Creation of the Alternate Energy Tax Incentives in the 1978 and 1980 Tax Acts, and Their Expansions and Extensions Thereafter.

A Key Lobbyist for The Renewable Fuels And Renewable Power Industries in the 1978 Public Utility Regulatory Policies Act, 1983 Caribbean Basin Economic Recovery Act, 1990 Clean Air Amendments (and Reformulated Gasoline Regulations thereto), 1992 Energy Policy Act, 2005 Energy Policy Act, and the 2007 Energy Independence and Security Act.

Renewable fuels/power finance attorney, 1978-present.

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I. Biofuels Have Come Full Circle

1970sEnergy Security

(1973 Saudi Arabian Oil Embargo/1979 Iranian OilEmbargo and High Oil Prices)

2005-2008Energy Security(crisis in the Middle East

and High Oil Prices)

1990sClean Air

(reduction of air pollution)

ENERGY

Energy Security Act of 1978

Alternative Motor Fuels Act of 1988

Energy Policy Act of 1992

Energy Policy Act of 2005

Energy Independence & Security Act of 2007

ENVIRONMENT

Clean Air Act of 1990

AGRICULTURE

Farm Bill of 2002

Ag Appropriations – Commodity Assistance Bills

Farm Bill of 2008

TRANSPORTATION

Highway Bill of 1978

TAXES AND ECONOMIC DEVELOPMENT

Energy Tax Act of 1980

Corporate Tax/Jobs Bill of 2004

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A. Need For Energy Independence1. Political Instability in the Middle East.2. High Petroleum prices.3. Impacts National Security.

B. Benefits To The Environment And Economy1. Increased economic activity and creation of jobs.2. Emission reductions cause reductions in cancer and lung

disease.

C. Incentives – Both Federal And State1. Tax Incentives.2. RFS.3. Emissions Reduction Credits/Renewable Energy Certificates

under State Renewable Portfolio Standards.

D. Cost Competitiveness 1. As per the Energy Management Institute Survey, alternative

fuels are more cost-competitive than their hydro-carbon based counterparts – Biodiesel is 29.2% more cost-competitive while ethanol is 17.4% more cost-competitive.

II. Factors For Biofuels Growth

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A. The Energy Policy Act of 2005 (the “2005 Energy Act”) defined “Renewable Diesel” as diesel fuel derived from biomass using a thermal depolymerization process that meets:

1. The registration requirements for fuel and fuel additives established by the EPA under Section 211 of the Clean Air Act.

2. The requirements of the American Society of Testing (“ASTM”) D-975 (for petroleum diesel fuel) or D-396 (for home heating oil).

B. The Renewable Diesel Provision was inserted, in the later discussions of the 2005 Energy Act by Congressman Roy Blunt (R-Mo.), during the extension of the biofuels tax incentives, at the behest of Changing World Technologies, Inc., to convert turkey offal into Renewable Diesel through a thermal depolymerization process.

III. Renewable Diesel Versus Biodiesel

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1. Renewable Diesel was provided a $1.00/gallon (“Renewable Diesel”) tax credit without distinguishing between virgin (e.g., unprocessed oils, plant matter and animal fats) and non-virgin (e.g., processed waste materials like recycled restaurant greases) feedstocks.

2. Biodiesel was accorded a $1.00/gallon (“Agri-Biodiesel”) tax credit for virgin and a $0.50/gallon (“Biodiesel”) tax credit for non-virgin feedstocks under the tax provisions of the 2004 American Jobs Creation Act.

3. The term “Thermal Depolymerization” was left undefined by Congressman Blunt/Congress in the 2005 Energy Act. Congress never had a chance to debate the provision inserted late in the legislative process.

4. As such, the Internal Revenue Service (“IRS”) would not permit refiners and chemical processors, who saw the provision as a significant opportunity to claim the credit on Renewable Diesel produced in their refineries and chemical processing facilities as well as petrochemical complexes, to claim the tax credit until the term “Thermal Depolymerization” was formally defined. Thus, they applied to the IRS for a formal ruling.

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A. IRS Notice 2007-37, under its new broad definition of “Thermal Depolymerization”, enables refiners and chemical processors (using Fischer Tropsch technologies – (e.g., coal-to-liquids (“CTLs”), gas-to-liquids (“GTLs”), biomass-to-liquids (“BTLs”)) and other chemical processes) to by-pass Biodiesel manufacturers and, thus, purchase biomass-based, virgin and non-virgin feedstock directly from their feedstock producers and then introduce such feedstock directly into (i) a refinery’s existing hydrotreating and/or isomerization units co-processing these feedstocks with petroleum feedstocks and/or (ii) newly-constructed, independent stand-alone hydrotreaters and/or isomerization units, to create essentially the same product as Biodiesel.

IV. New IRS Notice 2007-37 (March 2, 2007, Published April 3, 2007) For Renewable Diesel Potentially Adversely Impacts The Biodiesel Industry

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B. The IRS Defined “Thermal Depolymerization,” very broadly after expressly consulting with the U.S. Department of Energy (“DOE”), as a process for the reduction of complex organic materials through the use of pressure and heat, with or without the presence of catalysts, to decompose long-chain polymers of hydrogen, oxygen and carbon into short-chain hydrocarbons with a maximum length of around 18 carbon atoms.

C. The IRS Notice 2007-37 Creates a “Win-Win-Win” scenario for refiners and chemical processors, as well as for refiners and other owners with petrochemical complexes, as follows:1. Tax Credits

a. Renewable Diesel -- $1.00/gal. (without distinguishing between virgin/non-virgin feedstocks).

b. Biodiesel – Distinguishes different rates for different feedstocks -- $1.00/gal. (AgriBiodiesel Tax Credit -- virgin feedstock) and $0.50/gal. (Biodiesel Tax Credit -- non-virgin feedstock).

c. Each tax credit currently expires on December 31, 2008.d. Fuel Ethanol – The 2008 Farm Act reduced the Volumetric Excise Tax Credit

(“VEETC”) from 51 cents/gal. to 46 cents/gal. It remains effective through December 31, 2010. It also provided a new 1.01 tax credit (including the 46 cents/gal VEETC) for cellulosic ethanol. The cellulosic ethanol producer also receives the small ethanol producer credit of 10 cents/gal., no matter how much ethanol is produced. This credit previously was limited to receiving the credit only on the first 15 million gallons produced on a plant limited to less than or equal to 60 million annual gallons of rated capacity.

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e. Refiners/Chemical Processors, as well as Petrochemical Complex Owners, thus, are incentivized to pay feedstock producers a high price in competition with Biodiesel Manufacturers for the same already-costly feedstock. Also, with the enormous existing storage infrastructure of refiners/chemical processors/Petrochemical Complex Owners, and the enormous profits made by them over the past several years, these hydrocarbon manufacturers could purchase tremendous quantities of a Biodiesel Manufacturer’s feedstock on a long term basis and simply place these feedstocks in storage. This potential aggressive approach could force Biodiesel Manufacturers into a tremendous short position.

f. House-Passed Tax Bill: i. It extends the $1.00/gal. biodiesel tax credit for one year through December 31,

2009, and provides the $1.00/gal. tax incentive for all biodiesel regardless of whether it is virgin or non-virgin feedstock. It also extends the 10 cents/gal. small producer biodiesel tax incentive through December 31, 2009. It also closes the “splash and dash” loophole currently permitting foreign (but not U.S.) – produced fuel from claiming the biodiesel tax incentive and then shipping the blended fuel to a third country for claiming additional incentives and ultimately being consumed. This action of obtaining a U.S. tax incentive and then a European tax incentive on the same blended biodiesel is the basis of the European Biodiesel Commission’s current anti-dumping and countervoiding duty proceedings against U.S. biodiesel manufacturers. This House action does not close the loophole entirely, as U.S. manufacturers still would be able to blend in the U.S. and claim a $1.00/gal tax credit and then ship the blend to Europe for further blending, claiming additional European tax incentives and having the product consumed in Europe. As such, Europe will continue these proceedings against U.S. manufacturers. The only way to entirely close the loophole would be to require U.S. producers to have their biodiesel blends consumed in the U.S. in order to obtain the tax incentives.

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ii. It would reduce the $1.00/gal. tax credit for Renewable Diesel produced from the co-processing of biomass feedstock with petroleum feedstock in existing refinery/chemical processing units, as well as in petrochemical complexes, to 50 cents/gal. However, Renewable Diesel produced from biomass only at existing refineries/chemical processing/units or free-standing units would continue to qualify for the $1.00/gal. tax credit through December 31, 2009.

iii. The National Biodiesel Board (“NBB”) sought to reduce the latter tax credit to $0.50/gal. and impose a “60 million gallon per-producer” limit on this tax incentive. The House, however, did not agree.

iv. The House Tax Bill also (a) expands the Renewable Tax Credit to become a “Biomass-Based Diesel Credit” at free-standing units (i.e., not co-processing in existing refinery/chemical processing units) and (b) creates a $1.00/gal. tax credit for biomass-based Jet Fuel through December 31, 2009.

v. Furthermore, the House Tax Bill removes the requirements of (a) thermal depolymerization and (b) the satisfaction of ASTM D-975 and D-396. Thus, the House Tax Bill removes any doubt that Renewable Diesel and other such renewables fuels processed through a Fisher Tropsch processing system would qualify for the $1.00/gal. tax credit through December 31, 2009, if this conclusion already was not clearly established, as it seemingly had been, through IRS Notice 2007-37.

g. Senate-Unpassed Tax Bill: i. The original Senate Tax Bill had no provision.ii. The new Senate Tax Bill reduces the $1.00/gal. tax credit for Renewable Diesel to

$0.50/gal. for co-processing, but does not reduce the existing $1.00/gal. tax credit for Renewable Diesel produced in stand-alone facilities. It also does not impose an annual “per-producer” limitation. Instead the Senate proposes a “60 million gallon/year per facility limitation on the tax credit. To date, the Senate has not passed its Tax Bill.

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2. Cetane Ratinga. Renewable Diesel – 85 to 100. b. Biodiesel – 60 to 65 at the high end with palm oil or tallow; otherwise it is

closer to 55 with vegetable oil, fats and greases.c. Petroleum Diesel – 40 to 45.

3. Pipeline Fungibilitya. Renewable Diesel – entirely pipeline-fungible, as it is indistinguishable

from petroleum diesel. b. Biodiesel – U.S. “perception” is that it is “not” pipeline-fungible (i.e., could

contaminate aviation gasoline/jet fuel) – while B-2 and B-5 blends are pipelined safely in Europe without fear of contamination by Europe’s airline industry. In fact, Virgin Air has conducted a successful biodiesel aviation test in a commercial airliner from London to Amsterdam earlier in 2008.

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4. RFS

a. Renewable Diesel – 1.7 credits/gal. b. Biodiesel – 1.5 credits/gal.

i. Each could increase to 2.5 credits/gal., if the respective production facility is powered on 90% or more of a non-hydrocarbon-based fuel. However, new EPA rules expected to be issued later this year would eliminate this feature effective Jan. 1, 2010, without any grandfathering.

c. Refiners and chemical processors potentially can meet RFS purchase obligations, because Renewable Diesel is produced within the refinery and chemical processing units, as well as within petrochemical processing complexes. Thus, they potentially would not need to purchase RFS qualified-fuel to meet their RFS obligations, depending on the amounts of RFS qualified Renewable Diesel produced versus the size of their RFS obligations. In fact, depending upon the fulfillment of their RFS purchase obligations, refineries and chemical processors could save money, as they, instead, potentially would create new revenue streams from selling excess RFS fuel/credits.

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5. Environmental Benefits – The Environmental Benefits of Biodiesel should be captured in Renewable Diesel, as Biodiesel evidences immediate and dramatic effects by reducing harmful emissions (e.g., CO2 by 80%,Carbon Monoxide by 50%, SOX by 100%, Hydrocarbon Emissions by more than 50%, Particulate Matter by more than 50%) when compared to petroleum diesel. Thus, by using the same renewable biomass feedstocks as Biodiesel to create these tremendous Environmental Benefits, Renewable Diesel should produce similar such emissions reductions and resulting Environmental Benefits.

a. Refiners and chemical processors, as well as owners of petrochemical complexes, thus, could become “net-sellers” of Clean Air Act credits in the more-restrictive 2008 Phase II Clean Air Act regulatory regime. In such case, a reduction or elimination of their obligations to purchase such emissions credits would potentially permit them to become “net-sellers” of credits, creating new revenue streams.

b. Similarly, refiners/chemical processors, as well as owners of Petrochemical Complexes, could become “net-sellers” of carbon credits in states implementing mandatory industrial carbon offsets, if they meet their obligations by controlling the manufacture of these renewable fuels. (Utilities recently began to forecast in their business plans that the cost of complying with mandatory carbon reduction legislation will be $50/ton of carbon offset.)

c. These are only two examples of potentially new refinery/chemical processing/petrochemical complex income streams, where these hydrocarbon manufacturers otherwise would need to purchase credits to be compliant with Federal Clean Air Act and State Industrial Carbon Laws.

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6. BTU Value – Biodiesel and Renewable Diesel have similar energy content and, independently, each exceed the BTU Value of other competing alternative fuels.

7. Fuel Quality Controls – a. Renewable Diesel – Refinery, Chemical Processors’ and Petrochemical

Complex Owners’ quality control systems ensure product quality. b. Biodiesel – However, Biodiesel Manufacturers frequently encounter

product quality issues and challenges.

8. Manufacturing Facilities And Distribution Systems a. Renewable Diesel – Can be produced and distributed within existing

refineries, chemical processing facilities and petrochemical complexes, along with their existing pipeline and other distribution systems. Thus, their capital expenditures (“CAPEX”) are very small, unless they must construct stand-alone units. In the latter case, the required CAPEX could be more than double those similar expenses incurred by Biodiesel Manufacturers producing the identical product volumes.

b. Biodiesel – CAPEX can range from $0.50/gal. to more than $1.50/gal. depending on the process design, equipment and construction requirements thereto. In fact, CAPEX has increased to as high as $2/gal. in the last year for greenfield developments.

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9. Temperature Range – Renewable Diesel is chemically equivalent to conventional diesel and, thus, likely has a lower “cloud point” than does Biodiesel. The result could permit the use of Renewable Diesel at a broader range of temperatures than Biodiesel. Biodiesel, unlike Renewable Diesel, has faced many issues and challenges, when used in colder climates.

10. The oil industry has tried for more than 30 years to eliminate the ethanol industry and has failed to do so. However, in one fell swoop, the IRS, after consultation with the DOE, has served up the potential “knock-out punch” to undercut severely, if not to kill, the Biodiesel industry in the United States.

11. In an April 16, 2007 NBB Press release, a NBB Board member stated that through the IRS Notice, “the oil companies could put a stranglehold on materials used to make Biodiesel, stunting the growth of the industry, and leaving [Biodiesel] companies....standing on a bridge to nowhere.”

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12. The alternatives have been to either sue the IRS or to seek a legislative fix immediately.

a. With the rush of biofuels tax bills presently before Congress (now and in the past Congressional Session), a new Democratic Congress and an Administration now touting biofuels, an immediate legislative fix is the best path. However, it must be accomplished early in 2008, because no tax bill likely will be passed/enacted later in an election year. Also, the 2008 Presidential and Congressional elections, with a 2009 transition period thereafter, could mean that we may not see a tax bill enacted until 2010. Nevertheless, a mere extension of existing and expiring tax credits could be simply accomplished through an appropriations bill enacted during 2008 or 2009.

b. The NBB has chosen the legislative path. Even so, simultaneous pressure on the Secretary of the Treasury and his legislative counsel also should be vigorously pursued to reach a fair result. The NBB will have its “hands full” trying to defeat an historically powerful and highly-skilled oil and chemical industry lobby.

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V. Marketplace Overview

A. Fuel Ethanol1. Current U.S. Market – More than 7.3 billion gallons/yr. of

Fuel Ethanol capacity exists. Several projects, amounting to nearly 500 million gallons/yr. temporarily suspended operations because of Spring 2008 flooding in the Midwest.

2. Current U.S. Production – At present, approximately 6.2 billion gallons of new Fuel Ethanol capacity/expansions are under construction.

3. By 2015 – The RFS for grain-based ethanol will cap out at 15 billion gallons of annual production under the 2007 Energy Act. Cellulosic Ethanol will continue to expand these production numbers into the future.

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B. Biodiesel (mono alkyl esters from long-chain fatty acids)1. Current U.S. Market – Approximately 1.85 billion gallons/yr.

Biodiesel capacity exists in approximately 165 Plants. However, only approximately 450 million gallons of Biodiesel were sold in 2007, with 50% to 80% being exported to Europe. Much of this capacity is in dedicated and non-dedicated oleochemical and chemical plants. Many plants are able to direct output to markets other than Biodiesel, such as soaps, detergents, and a myriad of other oleochemicals used in non-fuel-related markets.

2. Current U.S. Construction – Approximately 1.4 billion gallons/yr. production of Biodiesel is under construction in approximately 80 new plants which are to be operational by December 31, 2008. Many facilities will not be constructed, however, unless mandates and tax credits remain in place.

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3. 2008 – Expect more than 3.25 billion gallons/yr. production capacity, if all current construction is realized.

4. 2008-2015 – Additional capacity in potentially substantial amounts is dependent upon extended tax incentives, available and competitively-priced feedstocks and/or captive feedstock production (such as algae produced in significant tonnage per acre), and available RFS capacity/environmental emissions reduction credits. Captive crushing operations are a plus.

5. Europe – European Biodiesel Manufacturers are selling at 10% of their current capacity (which is currently multiple times larger than current U.S. capacity at approximately 1.7 billion gallons/yr. production as of December 31, 2007) because of the loss of tax incentives, environmental concerns involving available feedstocks, and importation of more than 50%-80% of U.S. production under an existing weak U.S. currency and subsidized with $0.50 to $1.00 biodiesel tax credits under “splash and dash” procedures.

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C. Renewable Diesel (thermo-depolymerized oils and fats)

1. Current U.S. Market – More than 200 million gallons/yr of Renewable Diesel is in production. The process is used in the EU by Neste Finland and expected to be used by ConocoPhillips.

2. New ConocoPhillips – Tyson Foods Joint Venture - Within two weeks of the IRS issuance of this severe ruling, Conoco and Tyson Foods announced, on April 16, 2006, a major agreement to produce 175 million gallons of Renewable Diesel by 2009, with each company investing more than $100 Million. Tyson will provide ConocoPhillips animal fats to refine into Renewable Diesel in Conoco’s refineries for ultimate pipeline shipment and sale. ConocoPhillips and Tyson Foods began producing ultra-low sulfur Renewable Diesel from beef fat at Conoco’s Borger, Texas refinery on December 18, 2007.

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3. New Syntroleum Corporation – Tyson Foods Joint Venture - Syntroleum Corporation, in June 2007, in partnership with Tyson Foods, formed Dynamic Fuels LLC, a 50/50 joint venture, to produce synthetic renewable fuels from animal fats targeting the Renewable Diesel, jet/aviation and military fuel markets. This jet/aviation fuel results from military requests and fits long term Department of Defense (“DOD”) planning for a single fuel (JP-8).

4. Projected U.S. Production - 2 billion gallons/yr production by 2012 with production capacity increases by using existing and stand-alone facilities – Hydrotreaters and Hydrocrackers.

5. 2015 – Could be very significant production, including “Second Generation Biodiesel.” Although under DOE planning these volumes would be derived from cellulosic feedstocks, not fats and oils (lipids), which are converted to syngas for use in FT processes to create alkanes (diesels, kerosenes, solvents, waxes and lube oils).

6. The U.S. military is moving toward renewable diesel and synthetic fuels, as it becomes increasingly concerned that dependence on foreign oil is a strategic threat.

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VI. Project Financing ModelsA. Financing Biofuels Projects Generally

1. Investors ideally seek a 25%-30% ROI. However, increased CAPEX, feedstock costs and construction time frames, along with increasing product prices and substantially increasing oil prices are challenging this expected ROI significantly.

2. Substantial Funding Needed – Equity and Debt. The Biodiesel standard CAPEX has been approximately $1/gallon constructed (some recent technology advancements are reducing Biodiesel CAPEX to below 50 cents/gallon constructed). Renewable Diesel manufactured in existing refineries/chemical processing units (i.e., “co-processing) requires little CAPEX. However, if it is produced in stand-alone units, it will require a CAPEX of at least twice that necessary to construct the same annual gallonage of Biodiesel.

3. Approximately 24 to 30 months ago, Fuel Ethanol (from grain) was $1/gallon constructed and now it can exceed $2.75/gallon constructed (all-in costs) (cellulosic ethanol CAPEX is much higher) due to the lack of recognized highly-qualified process engineers, substantial increases in the price of steel generally and stainless steel specifically, increased costs for concrete and asphalt, increased labor costs, shortages of critical components such as heat exchangers, pumps and distillation columns. These same increased cost factors also are driving Biodiesel CAPEX costs upward.

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4. Debt- Equity ratios for Biodiesel plant construction at best are 50:50. Notwithstanding, lenders generally are refusing to finance new biodiesel projects, unless the Biodiesel tax credits are extended beyond December 31, 2008. The status of the extension of the Biodiesel Tax Credits as follows:

a. $1.00 gal for Virgin Feedstocks (oils, fats) v. 50¢ gal for Non Virgin Feedstocks (greases and recycled biomass).

b. Biodiesel Tax Credit provisions were moved from Farm Bill Tax Provisions into the unpassed Energy Tax Bill.

c. Under the House version of Energy Tax Bill (passed), Virgin and Non Virgin Feedstock-based Biodiesel each will receive a $1.00/gal. tax credit, but the credit is extended for only one-year to December 31, 2009. Is that enough for lending? -- Maybe not.

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5. Ethanol was 70:30, then moved to 60:40 and today is closer to 50:50 for a conventional dry-mill facility. Cellulosic Ethanol Plants will require considerably higher percentages of equity. The Banks will not finance the initial Cellulosic Ethanol technologies. That’s why DOE/USDA grants and loan guarantees are a must! Thus, more VC/private equity is required to finance these new technologies.

6. Stand-alone units for Renewable Diesel will exhibit similar debt-equity ratios to those of Biodiesel.

7. Wall Street banks are capping equity at $100 Million to $125 Million. Increases in project capital costs, thus, will require increasingly more equity.

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8. Managing Risk – e.g. shifting technology risk to construction contractor through performance warranties.

9. Investing in company versus project level. This approach is seen through the recent use of venture capital and private equity funding and/or capital markets funding through reverse mergers into public vehicles accompanied by private investments into public enterprises (“PIPES”) at the company level. The latter financing mechanism was more prevalent 1-2 years ago.

10.Engage a very capable design-build team at very reasonable price and assemble a highly-capable management team.

11.Estimate the project’s initial seed capital needs for six (6) months to a year – Seed capital can be used towards:a. development of a feasibility study and business plan. These

documents, among other requirements, will determine if any deal-breakers exist and how to surmount them.

b. site development, pre-engineering and permitting. c. legal and accounting expenses.

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12. Equity funding is relatively straightforward, and the parties will negotiate the terms of the investment, including liquidation preferences, board seats and other preferential rights.

13. Typical debt funding requirements are:a. lender having a first mortgage on all real estate. b. no other party having a prior security interest in any of the

assets. c. legal opinions regarding (i) enforceability of the loan

agreements and (ii) confirming that required permits and governmental authorizations have been obtained.

d. Delivery of collateral assignments of significant contracts to the lender.

e. Periodic delivery of financial information.f. Satisfaction of certain financial requirements, such as an

appropriate debt service coverage ratio, debt-to-equity ratio, tangible net worth ratio and others.

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B. Financing Fuel Ethanol Projects1. Investors ideally seek a 25%-30% ROI. However, (i) increasing CAPEX (due to

increasing steel, cement and similar costs – resulting in sometimes more than $2.75/gal. CAPEX versus approximately $1.00/gallon CAPEX 2 years ago),

2. Increasing feedstock costs (corn prices moving up and down in an approximate band of $5.50-$8.25/bushel versus $2.00 to $2.50/bushel 2 yrs. ago,

3. Decreased product prices (ethanol at $2.50-$3.10/gallon vs. $4.00-$4.50/gallon 2 yrs. ago),

4. Increasing construction time frames (18 mos. to 24 mos. versus 12 mos. to 18 mos. 2 years ago) and

5. Increasing financial closing time frames (12 mos. to 24 mos. plus versus less than 12 mos. 2 yrs. ago), along with increasing co-product prices (DDGs and Co-Products Prices are up significantly), and

6. Increasing petroleum prices (oil at nearly $125/BBL - $150/BBL versus approximately $60/BBL or less 2 years ago) are severely challenging the expected ROI. (Standard & Poors recently published that each 1 cent/gal. increase in the price of Fuel Ethanol will offset each 4 cents/bushel increase in the cost of corn. Thus, the price of Fuel Ethanol only must increase by 25% against the increase in the cost of corn to preserve the ethanol-corn crush spread).

7. Corn-to-Fuel Ethanol toll arrangements, which eliminate the commodity risks, are a must for the majority of bankers to consider project lending. Lenders can deal with construction and O&M risks which are typical of traditional project finance models.

8. Long term contracts with stable revenue streams are a must. Lenders will not fund merchant projects in the current economic downturn.

9. They also require that developers demonstrate that they can service debt for at least 7 years. Further, they require that the equity be committed before discussing debt arrangements.

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10. Developers should consider implementing a “fuel-for-food” strategy, in lieu of the specious and “trumped-up” “food-for-fuel” opposition (which primarily occurs because of artificially increased diesel prices, not biofuels production). They can implement this new approach through the new food-grade corn dry fractionation technology of ICM, Inc. (which produces nearly 5 new co-product streams of corn fiber meal, grits, food-grade germ protein, corn syrup, corn oil, etc., in addition to DDGS). Although this new technology requires an additional approximate $200 million in CAPEX for the ethanol project, it nearly triples the profits of an traditional grain-based ethanol facility at today’s exceptionally-increased grain prices and with the same amount of grain.

11. Example of a Financed Plant –a. Very few ethanol plants have been financed in 2008. One 110 Mill Gal/ethanol plant in

Pennsylvania was financed at $270 Mill TPC, on $60 mill in State bonds plus $2 mill in state grants.

b. The senior debt was dependent on a corn to ethanol toll agreement where Getty Oil/Lukoil held title to the grain and ethanol to remove the commodity risk from the facility being financed by a consortium of banks led by a major Wall Street investment bank.

12. New financing structures are materializing as typical bank financing becomes nearly non-existent. A few of the ones we are working with are as follows:

a. 5-year interest only (LIBOR + 200 to 300 basis points, plus 1% - 3% one-time closing fee) loans (useable for construction) for up to 100% of total project costs with full balloon payment due at the 5th anniversary. If full payment cannot be made, then the lender will consider thereafter an up-to-10-year fully - amortizable, permanent finance loan under different interest rates. The typical debt provider is a U.S. mortgage finance company with liquidity to fund in a virtually non-existent commercial building and residential housing construction market. Percentage amounts of equity can be provided (at up to an 8% one-time closing fee). The typical equity provider is U.S.-based.

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b. Funding is 100% of total project costs. It is a no-interest “loan” funding transaction (5% closing fees included in funding), where the developer is provided up to 65% project equity and the funder retains at least 35% project equity. 10% of total project costs (but no less than $300,000) is placed in escrow for 90 days secured by an irrevocable standby letter of credit. Closing is within 90 days of completed underwriting. If financial closing occurs, then the amount in escrow is released in full. If no financial closing occurs, then the escrow is returned minus the funder’s out-of-pocket costs. At a designated time after the commercial operation date (“COD”) (as early as 90 days after COD), the funder will issue a “put” to the developer for the payout/payback of its full equity at its full equity percentage of (35%-plus) against the then - independently appraised value of the completed facility. The funder, however, retains a fixed or percentage royalty against some or all revenue streams for the life of the project. Moreover, the loan is fully forgiven. The typical funder is from Europe.

c. Funding is similar to VI.B.4.b. However, the funding is a long-term debt amortizable at a negotiated rate (plus a set closing percentage fee). The loan is not forgiven and must be paid in full. The project equity model is 25% to the developer and 75% to the debt funder. The developer can purchase the funder’s equity in whole or in part on an incremental basis, once the project is producing profits and the loan has been fully repaid. There is no “put” provision or escrow payment required as part of this funding model.

d. Andrews Kurth is in the process of closing a 140 Million gal./yr. corn dry fractionation, Fuel Ethanol facility in the Baltimore Harbor on ICM’s new technology and on one of these new financing models. This project is the only deep water ethanol facility in the U.S. with nearby ocean access. It can be scaled in 6 phases to over 840 Million gals. It qualifies for the higher 2.5 RFS credits/gal. (in lieu of the normal 1.0 RFS credit/gal.) for typical grain-based facilities. (2008 RFS credits are approximately 3.75 cents/gal. The Governors of Texas and Virginia have filed requests to EPA to waive the RFS requirements. Texas Senators in Congress have introduced federal legislation to freeze RFS requirements. To date, nothing has been decided on these regulatory and legislative initiatives.) It also has hundreds of thousands of monetizeable carbon credits, as Maryland is one of the approximate 15 industrial carbon legislation states. Maryland’s new carbon law is mandatory beginning January 1, 2009.

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C. Financing Biodiesel Project

1. Debt/Equity Ratio – Traditionally, a biodiesel project has maintained an approximate 50:50 debt/equity ratio. Today, however, more equity may be required.

2. CAPEX – is moving from more than $1.00/Gallon (generally inside the U.S. and EU) to $0.25 to $0.50/Gallon (at the lower rates outside of the U.S. and EU – such as in Asia) owing to (i) increasingly better technologies, lower production and labor costs (as industry moves away from steel to composites and uses other technology advancements) and (ii) growing numbers of Top-Tier Process Engineering Companies. (Top-Tier Engineering Performers are only now appearing for Biodiesel versus Fuel Ethanol plants. In the past, such Top-Tier Engineering Companies were not as important for Biodiesel projects, whereas they were required for Fuel Ethanol projects).

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3. Operating Costs – Are Approximately $5.20-$5.30 today versus $2.80 – $3.00/Gallon only 12 months ago (at least $4.85/Gallon constitutes feedstock costs – soy oil is currently at 64 cents/pound, as of July 9, 2008), reduced to $4.20 - $4.30/Gallon by $1.00/Gallon AgriBiodiesel Tax Credit for Biodiesel produced firm Virgin (plants and animal fats) Feedstocks or to $4.70 - $4.80/Gallon by $0.50/Gallon Biodiesel Tax Credit produced from Non-Virgin (biomass - based greases and other recycled biomass- based) Feedstocks. More than 80% of operating costs constitute feedstock costs. Integrated oilseed agriculture and processing are key considerations.

4. ROI – 7% to 18%, with the higher returns, if the developer owns the oilseeds and extraction process. These ROIs were higher than 50% just over one year ago. U.S. exports of Biodiesel to the EU are currently saving the U.S. industry.

5. Andrews Kurth recently closed a 50 Million Annual Gallon Biodiesel project in India at a total cost of $21 Million initially on an all-equity basis (subsequently seek to project finance the project with debt including an additional 50 Million Gallon/year expansion thereof). The project has nearly 400,000 monetizable carbon credits at up to $14 per credit per year or nearly $5.6 Million in additional annual revenues currently unavailable in the U.S. for projects, as the U.S. has not signed or ratified the Kyoto Protocol. We also recently closed a second 30 million annual gallon Biodiesel project in India and several in the U.S..

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D. Financing Renewable Diesel Projects

1. Co-Processing (i.e., when you put oils/greases/animal fats into refinery hydrotreaters) CAPEX - near US$0, unless required to segregate diesel from other products with existing hydrotreaters. Whether to use existing facilities or construct new stand-alone units is the major question.

2. Stand-Alone Unit CAPEX - If the latter case, the CAPEX for new hydrotreaters is approximately up to twice the cost of the similar capacity produced in a Biodiesel manufacturing facility.

3. Operating Costs – Approximately $5.15/Gallon versus 2.50/Gallon only 12 months ago. When reduced by the $1.00/Gallon Renewable Diesel Tax Credit regardless of whether using the same Virgin or Non-Virgin (used restaurant oils) feedstocks, the current operating costs would be approximately $4.15/ Gallon. These are the same feedstocks used for Biodiesel production.

4. ROI – 20% to 30%, with the higher returns if integrated into, instead of outside of, the petroleum refinery. These returns represent a very good deal for refiners and chemical processors (e.g., Eastman) to enter what the EPA and DOE call the “non-ester” diesel marketplace.

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E. Critical Contract Issues1. Strong Feedstock Supply Contract with terms of 3-5 years – attracts

financing.2. Delays - Force Majeure clause; liquidated damages; limitations on

liabilities.3. Well-negotiated Offtake Agreement with terms up to 5 years – including a

determination of whether the buyer or seller arranges the rail transportation.

4. Commodity Risk Management –a. Ability to intelligently manage commodity risk is invaluable for preserving

margins and surviving market swings.b. Hedging risks through tolling arrangements, over-the-counter options, futures

etc..5. Purchasing Insurance

a. Insurance to cover property, testing, builders risk, a delay in start-up, general liability, automobiles, business interruption, crime, or workers compensation, pollution coverage among others.

b. IMA Financial Group Inc., an insurance brokerage company recently has begun to offer a Biodiesel insurance program providing a complete package of necessary insurance to projects.

c. In foreign projects, one must obtain political risk insurance and insurance to pay winners of arbitration awards where enforcement of such awards is difficult or impossible – the U.S. Overseas Private Insurance Corporation provides such insurance policies and products.

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6. Construction Related Agreements

a. Design & Engineering – Once “full-wrap” agreements (ensuring a fully integrated plant would be constructed on time, according to specifications, and would produce the desired functionality) including “balance of plant” provisions (providing for all facilities from feedstock receiving to fuel storage, etc.) were regularly provided. However, industry expansion has strained the capacity of processing engineers to provide full wraps. As such, owners have had to be creative to bridge the gaps between design and construction. Thus, the scope of work must be fully specified in the design and construction agreements, with identical consolidated mediation/arbitration provisions designed to draw the engineers, constructors and owners into a single action to resolve disputes quickly.

b. Equipment Procurement.c. Performance guarantees – in the form of bonds or payment guarantees.d. Warranty –

i. Usually heavily negotiated - term of warranty and limitations on warranty. ii. Producers should insist on three (3) fundamental warranties - yield, throughput and

specifications (quality). e. Insurance Arrangements and Indemnities – personal injury, general

commercial liability, automobile; use risk management specialist to determine amounts.

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7. Feedstock Agreements a. Need to align with a recognized, credit-rated, oils and energy

commodities entity that will sell domestic and internationally sourced feedstock.

b. Pricing based on a published commodity price index to enable hedging of forward price risk exposure against established exchange-traded and OTC financial products.

8. Off-take Agreementsa. Need to align with a recognized, credit-rated, oils and energy

commodities entity that will purchase refined Biodiesel.b. Sell at prices based on a published commodity price index to enable

hedging of forward price risk exposure against established exchange-traded and OTC financial products.

9. Transportation Agreementsa. Renewable Diesel – is entirely pipeline fungible, as it is indistinguishable

from petroleum diesel. The major petroleum companies control/own the transportation source.

b. Biodiesel – B2 and B5 blends are pipeline fungible in Europe. The “perception” in the U.S. is that Biodiesel cannot be pipelined. As such, trucks, barges and trains are the principal modes of transportation.

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F. Construction Of A Biodiesel Versus Renewable Diesel Plants1. Generally a Greenfield Plant takes approximately 12 months for Biodiesel

and much longer for stand-alone Renewable Diesel plants from project capitalization to commercial operation, although this timeframe is increasing.

2. Conducting a Feasibility Analysisa. In depth feedstock market analysis including availability and suitability of

feedstock – feedstock is the single largest cost component of Biodiesel production at 80% of total production costs.

b. analyze the local/state policy supporting incentives for Biodiesel and Renewable Diesel.

c. analyze the diesel fuel market segment and potential customers for Biodiesel and Renewable Diesel.

d. select the most appropriate process technology for Biodiesel and Renewable Diesel.

3. Plant Considerationsa. Size - Biodiesel -- recommended minimum size is 80,000 MT - 100,000 MT of

Biodiesel/year (approximately 30 Million Gallons/year) when using virgin oils and not less than 40,000 MT of Biodiesel/year (approximately 13 Million Gallons/year) when using recycled oils. We are seeing Biodiesel plant sizes increasing to 50 Million Gallons/year to 100 Million Gallons/year in the U.S. and abroad. Fuel Ethanol – Sizes have increased to the current industry standard of 110 Million gal./yr. rated capacity. Renewable Diesel – Sizes vary substantially on a barrel per-day basis.

b. It is preferable to have multi-feedstock producing capability and deep-water access (to move feedstock/products into and out of the manufacturing facility easily and to reduce rail congestion risks.)

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G. Additional Deal Structure Issues1. Location of Feedstock –

a. proximity of feedstock to plant.b. transportation costs.

2. Location of Customers – such as proximity to diesel producers and blenders.

3. Transportationa. railroad, highway and deep navigable water access for Ethanol and

Biodiesel and pipeline access for Renewable Diesel.b. analysis of these transportation alternatives.c. loading and unloading infrastructure providing access to facility by

rail, road, vessel and barge to facilitate efficient feedstock sourcing and Biodiesel distribution.

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4. Permits and Local Land Usea. Permitting can commence up to one (1) year before construction

and continue throughout the construction cycle.b. Ease in obtaining permits impacts time schedules. There is no

generic list of permits for a typical biofuels project. Such list is specific to the project design, site and host state/municipality. Often, these projects will require more than 40 permits and/or governmental approvals. Also the ease of obtaining permits/governmental approvals varies widely. It may prove more difficult in one state to obtain one approval/permit than to obtain multiple ones in another state. For example, Minnesota requires one area permit for several kinds of air discharges, but another state might require individual permits to cover each type of discharge.

c. Local rules may prohibit certain uses. d. Environmental, air, water and other issues -- some permits include

approvals for air emissions, water discharge, stormwater, erosion control, wetlands, endangered species, cultural resources, local site development, zoning, rail etc. Fuel Ethanol production also requires approval from the U.S. Alcohol and Tobacco Tax and Trade Bureau prior to selling denatured Fuel Ethanol.

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e. Occupational Health and Safety Administration (OSHA) requires Process Safety Management (PSM) – employees of the facility know about the use of hazardous chemicals in the workplace.

f. EPA uses PSM in a different context to inform public about the presence and use of highly hazardous chemicals in their vicinity.

5. Water Supply a. environmental issues as to any effluent discharge.

6. Form of Ownership of Land a. Flexibility in lease with landlord, i.e. minimum prior approval

requirements (for example, terms of 20 years with multiple 10 year extensions); and

b. Obtain necessary easements.

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7. Proven Management a. Strong track record and experience of management team (Board of

Directors, Board of Advisors, Officers/Managers) is a must.b. The management team must be able to create new revenue streams

(e.g. monetize emissions, RFS, RECs, carbon credits, tax and other revenue generating/debt securitizing credits) and reduce front-end project costs – in other words, seek the greatest possible reward for the least amount of risk.

8. Proven Operational Experiencea. Expertise in all areas of plant management including logistics, client

relationships, quality control, marketing and administration.

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H. Biofuels Finance Challenges

1. High energy costs for powering facilities, increased feedstock costs, lower product prices.

2. Decreasing co-product prices.3. Oversupply always an issue.4. Environmental issues.5. Financing – need larger pool of lenders, long term contracts, tolling arrangements, and

new revenue streams (as provided in corn dry fractionation for Fuel Ethanol production).

6. Equity – VC/Private Equity, Capital Markets – U.S. versus AIM (London Stock Exchange), Dubai Stock Exchange, Deutsche Borsche.

7. Maintaining small versus large plants.8. Maintaining/Extending current tax incentives. – Ethanol incentives are in place through

Dec. 31, 2010; while Biodiesel are Renewable Diesel incentives expire on December 21, 2008, unless the current tax bill passes and extends them for 1 year through December 31, 2009.

9. Destabilizing tax rulings (e.g., IRS Notice 2007-37 (March 2, 2007)).10. Imports ((i) duties - 54¢/gallon for ethanol, 0¢/gallon for biodiesel and renewable diesel

versus (ii) lack of duties).11. Low demand for by-products such as Glycerin in Biodiesel production.12. Funding for new technologies.13. Limitations of construction, fabrication, services.

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I. International Biofuels Considerations For Developing Countries1. Large Fuel Ethanol, Biodiesel and Renewable Diesel projects are

difficult to finance in developing countries principally owing to the need for international finance and equity.

2. However, Larger Biofuels (Biodiesel/Fuel Ethanol) Projects Are Beginning To Be Financed At Sizes of 30 Million Annual Gallons to 110 Million Annual Gallons. In this regard, we have closed or are working on the following renewable energy projects in India:

a. Closed 2 Biodiesel projects in Kakinada, Andhra Pradesh, India for i. a large U.S. venture capital company at 50 million gallons per year and

which will be increased to 100 million gallons per year (with 2 x 100 million gallons per year in additional projects to be constructed) and

ii. a medium Indian Biodiesel developer at 30 million gallons per year – through the UTI Ascent Fund.

iii. The U.S. VC Company project approximately has 400,000 carbon credits per year under the Kyoto Protocol monetizable at approximately $5.6 million per year. These credits can be used as security for project loans and/or as project revenues.

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3. These Projects have been Financed on Various Models –a. All equity finance (through private equity, venture capital, strategic

partners, etc.) with debt finance brought in after the Commercial Operations Date, which permits better loan terms – lower interest rates, longer tenures, etc. – due to risk mitigation.

b. Project Finance Models ranging from 80:20 to 60:40 to 50:50.c. Private – Public Partnerships (“PPPs”) with combinations of Indian

Government, private sector, multi-lateral and bi-lateral, etc., debt and equity providers.

d. Funds also will be raised through the Indian and foreign capital markets.

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4.Problem Areas a. Lack of contract sanctity is potentially a significant problem.

i. For example, in the Indian Power Sector, high, but agreed to, tariffs for the Dabhol Power Project and power projects in the State of Tamil Nadu, India ultimately were used by the particular State government as an excuse to cancel and/or disregard otherwise legally- binding agreements.

b. Failure of States or Provinces to uniformly apply Federal or Central government statutes. For example, in the Indian power sector, certain States have not uniformly applied the 2003 Indian Electricity Act with respect to third-party sales.

c. Long term tax incentives / low customs duties on capital equipment are required, although not consistently adopted. For example, in India, substantially high duties exist on raw materials and imported goods. India continues to have the highest customs duty rates in Asia, if not the world. The 2007 Budget did lower the peak rate of basic duties for non-agricultural products from 12.5% to 10%, and the effective overall duty rates from 36.74% to 34.13%. However, these rates remain substantially too high.

d. Need to stabilize developing countries’ tax environment – Tax statutes and regulations change frequently, with tax incentives regularly added and dropped.

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e. Excessive numbers of permits, clearances and other Governmental Authorizations at the Central/Federal, State/Provincial and Local Government levels – single window clearance/pre-vetted projects are a must.

f. Heavy regulation of labor – difficult to scale down jobs during economically–depressed times.

g. Poor infrastructure acts as deterrent to foreign investment in the manufacturing sector.

h. Disputes resulting in arbitration or litigation substantially may slow down and adversely affect project economics. For example, in India, the court system (a Unitary Court System) is plagued by intractable delays. If no new cases were filed, it would take approximately 350 years to clear the current court case backlog (not including administrative judicial and quasi-judicial case backlogs).

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i. Corruption is rampant in developing countries – not so much top-level corruption (e.g. receipt of project permits as permit requirements are reduced), but “frictional corruption” across the lower levels – inspectors, meter readers, etc. Encourage a corporate culture of saying “no” to corruption. Strict U.S. Foreign Corrupt Practice Act (“FCPA”) compliance adherence is an absolute necessity. Do not avail yourself of the FCPA “facilitating payments” exemption/exception, as it is a gray area that can lead to FCPA violations and host country anti-bribery law violations. Once a company is recognized as clean, attempts to collect payoffs/bribes will drop.

j. Choose your states and provinces wisely. Each has different levels of development and different levels of market–friendliness.

k. State and Provincial, or even Federal and Central, government elections can be problematic for incumbent politicians. Expect political instability, particularly in parliamentary government systems.

l. Lack of credit-worthiness of product purchasers.

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m. Substantial cross-subsidies and politicized tariff-setting -- for example, in the Indian power sector, farmers receive free power / industry pays more than its share.

n. Inadequate offtake and payment guarantee mechanisms adversely may affect project economics.

o. Inadequate fuel supply and transportation agreements with developing country governments and/or government-owned companies may require the renewable fuels’ manufacture to accept significant risks which must be abated by insurance and other protective mechanisms.

p. Foreign investors and financiers require:i. sanctity of contracts (including the purchase of, and full

payment for, contracted products), ii. strictly honored-payouts for purchased products under binding

guarantees (i.e., payment (i.e., counter guarantees) and debt (i.e., sovereign guarantees) security mechanisms), and

iii. the knowledge and practice that invoices will be paid in full and regularly without requiring litigation to ensure each payment.

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q. Protecting Your Investmenti. Engage qualified counsel, accountants and consultants at the

outset.ii. Need for Upfront & Well-Considered Tax and Corporate

Structuring, using limited liability vehicles and Double Taxation Avoidance Treaties.

iii. Use Special Economic Zones where possible, as they often have up to a 100% tax holiday.

iv. Project and Partner Due Diligence Are Key Exercises.1) Ensure that your partner is trustworthy and has the financial ability to

implement the investment.2) Enshrine IP protection in all contracts.

v. Contracts Require Certain Protective Clauses:1) Neutral-country arbitration is a must

(a) e.g., London venue with ICC, UNCITRAL, London Court of International Arbitration Procedural Rules.(b) if pressed into arbitration in India, bifurcate the arbitration clause so that smaller disputes are arbitrated in India and larger ones are arbitrated in a neutral country.

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2) Need for strong indemnification clauses3) Force Majeure – this provision permits suspension of

contractual obligations under certain circumstances.4) Compliance with U.S. Foreign Corrupt Practices Act

(FCPA) and foreign country anti-bribery laws – accusations particularly can adversely affect public company stock.

5) Need for insurance requirements to protect transactions, such as political risk insurance against expropriation, arbitration award enforcement insurance, etc..

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r. Key policy areas to address:i. Provide long-term, stable government policy support through updated

new energy legislation and regulations.ii. Reduce technology, commodity and financing risks, respectively,

through intellectual property filings (e.g., marks, copyrights, patents, etc.), hedging (e.g., futures contracts, swaps, pollution credits trading, etc.), and security (e.g., guarantees, LCs, escrows, insurance, long-term feedstock/fuel and off-take agreements, pollution credit pledges, etc.) protection mechanisms.

iii. Consider the use of domestic and international venture capital and private equity, capital markets (AIM / London Stock Exchange, Bombay Stock Exchange/Indian National Stock Exchange (if project is in India), Deutsche Borsche Exchange, Dubai Stock Exchange), and other funding mechanisms.

iv.Establish a federal carbon credit market with national trading exchanges for the monetization of carbon credit offsets to create new project revenue/income streams.

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VII. Establishment Of The Renewable Fuels Standard (2005 Energy Act Section 1501)

A. Tax incentives, although critical to project finance/project closings, never built out the biofuels markets as did assured market demand from a statutorily-enacted/required RFS through the 2005 Energy Act.

B. Legislation establishes the RFS for biofuels (including Fuel Ethanol, Biodiesel and Renewable Diesel) at the following levels:

2006 - 4.0 Billion Gallons2007 - 4.7 Billion Gallons2008 - 5.4 Billion Gallons - 700 mill gal/yr increase for years 1-5

2009 - 6.1 Billion Gallons2010 - 6.8 Billion Gallons2011 - 7.4 Billion Gallons - 600 mill gal/yr increase in year 62012 - 7.5 Billion Gallons - 100 mill gal/yr increase in year 7

C. Originally, the required amount in 2013 was to be determined, but it would not have been less than that used in 2012. The U.S. Secretary of Energy makes this determination in consultation with the U.S. Secretary of Agriculture and the U.S. EPA Administrator. Experts predict that, at the current growth levels, potentially, (i) Biodiesel will grow to over 4 billion gallons/year and Fuel Ethanol will grow to over 16 billion gallons/year by 2015 and (ii) Renewable Diesel will grow to over 2 Billion gallons by 2012.

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D. The regulations for the RFS under the 2005 Energy Act were issued on April 10, 2007, (effective September 1, 2007) and the program is to be governed by the EPA.

E. Subsequent years’ refiner requirements are determined by the amount of produced gasoline ÷ amount of produced Fuel Ethanol or Biodiesel. For example, a refiner producing 100 Million Gallons of gasoline must buy approximately 3 Million Gallons of Fuel Ethanol or purchase credits.

F. Use of the above base amount results in the accumulation of credits – a gallon of (B-100) Biodiesel = 1.5 RFS credit. (One gallon of grain-derived Fuel Ethanol = 1 RFS credit; One gallon of Renewable Diesel = 1.7 RFS credit; One gallon of Cellulosic Fuel Ethanol = 2.5 RFS credit; One gallon of either grain-derived Fuel Ethanol, Biodiesel or Renewable Diesel produced in a plant powered on 90% or more non-hydrocarbon-based fuel may receive 2.5 RFS credits.)

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G. Credits are transferable/saleable. Generally, at least for Fuel Ethanol, 1 credit is attached to the physical gallon sold, while the balance of any amount of the total per gallon credit, if any, can be stripped off and monetized by the blender-owner, as opposed to producer/manufacturer, unless the producers manufacture Cellulosic Ethanol. So long as the RFS mandate is set higher than the available physical biofuels gallons in a particular year, then these RFS credits will command potentially a significant trading price. As of July 14, 2008, and as mentioned earlier, the 2008 RFS credit is worth approximately 3.75 cents/gal..

H. Initially, these credits are designed to ease refiner compliance with the RFS purchase requirements:

1. Refiners could conceivably meet the RFS purchase obligationswithout purchasing any “wet” gallons of Biodiesel.

2. This “flexibility” for the refiner to effect compliance with the RFS mandate is exactly the reason for the enactment of the RFS into law.

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VIII. The 2007 Energy Act – The New RFS

A. President Bush’s State of the Union address in January 2007 called for the creation of an “Alternative Fuel Standard” (“AFS”) as opposed to the RFS, thus expanding the scope of such mandate which could include a host of other fuels including gas-to-liquids and coal-to-liquids. The Bush plan called for 35 billion gallons/year to be met by these alternative fuels (including Biodiesel and Fuel Ethanol) by 2017, or extending the current 7.5 billion gallons/year by 2012 RFS, by nearly 27.5 billion gallons/year of the additional capacity in a 5-year time frame.

B. Congress, in the Energy Independence and Security Act of 2007 (the “2007 Energy Act”) revised the RFS by (i) increasing the 7.5 billion gallon/year (by 2012) limit to 36 billion gallons/year (by 2022) and (ii) creating new categories for “Fuel Ethanol-from-Corn,” “Advanced Biofuels”, “Cellulosic Biofuels” and “Biomass Diesel”. As CTL, BTL and GTL through Fischer-Tropsch and other advanced processes, which process biomass products into CTL, GTL, BTL and other products, can participate in the New RFS, the revised standard has become more of the AFS contemplated in the Bush 2007 State of the Union Address.

C. Senator Binghaman’s S.987 RFS-Expansion, moreover, has been included in the 2007 Energy Act. Thus, a further expansion of the RFS also would qualify renewable fuels used as boiler fuels, jet fuel and home-heating fuel for these valuable RFS credits, in addition to the previous motor-fuel-use-only standard.

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Energy Independence and Security Act of 2007 New RFS Mandate

Year Total Volume of Renewable

Fuels(Billions of

Gallons)

Advanced Biofuel

Requirement(Billions of

Gallons)

Cellulosic Requirement(Billions of

Gallons)

BioMass Diesel

Requirement(Billions of

Gallons)

Resulting Cap on Corn Ethanol

(Billions of Gallons)

2008 9.000

2009 11.100 .600 .50 10.5

2010 12.950 .950 .100 0.65 12.0

2011 13.950 1.350 .250 0.80 12.6

2012 15.200 2.000 .500 1.0 13.2

2013 16.550 2.750 1.000 1.0 13.8

2014 18.150 3.750 1.750 1.0 14.4

2015 20.500 5.500 3.000 1.0 15.0

2016 22.250 7.500 4.250 1.0 15.0

2017 24.000 9.000 5.500 1.0 15.0

2018 26.000 11.000 7.000 1.0 15.0

2019 28.000 13.000 8.500 1.0 15.0

2020 30.000 15.000 10.500 1.0 15.0

2021 33.000 18.000 13.500 1.0 15.0

2022 36.000 21.000 16.000 1.0 15.0

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The Renewable Fuel Standard (RFS)(36 Billion Gallons 2008-2022)

Advanced Biofuels(21 Billion Gal 2009-2022)

15 Billion Gallons – Corn-to-Ethanol Only+ 21 Billion Gallons – Advanced Biofuels 36 Billion Gallons – RFS

Cellulosic Biofuels(16 Billion Gallons 2010-2022)

-- Potentially including Renewable Diesel (i) from Co-Processing Cellulosic Biomass with Petro Feedstock in Existing Refinery/Chemical and Petrochemical Hydrotreaters and Isomerization Units and/or (ii) produced in stand-alone units with Cellulosic Biomass

Biomass Diesel(2009-2012, 1 Billion Gallons from 2012-2022)

-- Biodiesel -- Renewable Diesel Produced from stand-alone units

-Including Renewable Diesel (i) from Co-Processing Biomass with Petro Feedstock in Existing Refinery/Chemical-and Petrochemical Hydrotreaters and Isomerization Units and/or (ii) produced in stand-alone units – 4 Billion Gallons

New Renewable Fuel Standard Law

Source: Michael McAdams,Advanced Biofuels Coalitionand Mark Riedy, Andrews Kurth

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IX. Conclusion

A. Biodiesel and Renewable Diesel will play important roles in the rise from 1 billion gallons annual RFS as of 2012 and continuing for 10 years thereafter, until they collectively reach at least a 5 billion annual gallons RFS in 2022. There is room in the vast diesel market for both fuels to exist side-by-side. Fuel Ethanol based on grain also will play a major role.

B. Other technologies, like biomass (cellulose) converted by gasification to syngas, whereupon the syngas is oligomerized to diesel fuels, will begin to enter the market during the years 2015 to 2022.

C. The diesel fuel market for North America will be fully integrated by 2022, with annual diesel volumes potentially surpassing 100 billion gallons per year. In such a setting, Biodiesel, Renewable Diesel and any new biomass-based diesels could only achieve a penetration rate of 5% or 5 billion using all available 2008 biomass resources (e.g., soybean oil, other oils and fats, biomass and algae).

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D. Only algae seemingly can provide a substantial feedstock supply beyond 2022, where EPA regulations could expand the volumes. Gasoline growth could go negative and diesel could attain 3% or more growth rates, as we saw in the EU circa 1990s to present.

E. The biggest current threat to Biodiesel and Renewable Diesel may be the conversion of coal-to-liquids (“CTL”) through Fischer-Tropsch technology with or without the use of similar biomass-based feedstocks. In such case, the low cost of coal, with new and effective CO2 sequestration technologies, could make coal the preferred source of feedstock in North America.

F. Cellulose-based Fuel Ethanol, along with pipeline-fungible Biobutanol, are the future of the Fuel Ethanol industries.