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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

 

[Mark One]

 

 

x

Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2009.

 

OR

 

 

o

Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from                       to                       .

 

Commission file number 001-32922

 

AVENTINE RENEWABLE ENERGY HOLDINGS, INC.

(Exact name of registrant as specified in its charter)

 

Delaware

 

05-0569368

(State or other jurisdiction of

 

(IRS Employer Identification No.)

incorporation or organization)

 

 

 

 

 

120 North Parkway Drive

 

 

Pekin, Illinois

 

61554

(Address of principal executive offices)

 

(Zip Code)

 

(309) 347-9200

(Registrant’s Telephone Number, including Area Code)

 

Securities registered pursuant to Section 12(b) of the Act: None

 

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   YES  o NO  x

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.   YES  x NO  o

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   YES  o NO  x

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   YES  o NO  o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer,”  and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer o

 

Accelerated filer o

 

 

 

Non-accelerated filer o

 

Smaller reporting company x

(Do not check if a smaller reporting company)

 

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   YES  o NO  x

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2009 was approximately $7,303,737 based upon the closing price of the Common Stock reported for such date on the OTC Bulletin Board.

 

Indicate the number of shares outstanding of each class of Common Stock, as of the latest practicable date:

 

 

Class

 

Outstanding as of February 16, 2010

 

 

Common Stock, $0.001 par value

 

43,443,078 Shares

 

 

 

 



Table of Contents

 

FORM 10-K

YEAR ENDED DECEMBER 31, 2009

TABLE OF CONTENTS

 

 

 

Page No.

 

PART I

 

Item 1.

 

Business

1

Item 1A.

 

Risk Factors

18

Item 1B.

 

Unresolved Staff Comments

37

Item 2.

 

Properties

38

Item 3.

 

Legal Proceedings

39

Item 4.

 

Submission of Matters to a Vote of Security Holders

39

 

 

 

 

 

PART II

 

Item 5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

40

Item 6.

 

Selected Financial Data

41

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

43

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

70

Item 8.

 

Financial Statements and Supplementary Data

70

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

70

Item 9A.

 

Controls and Procedures

70

Item 9B.

 

Other Information

71

 

 

 

 

 

PART III

 

Item 10.

 

Directors and Executive Officers of the Registrant and Corporate Governance

72

Item 11.

 

Executive Compensation

75

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

86

Item 13.

 

Certain Relationships and Related Transactions and Director Independence

88

Item 14.

 

Principal Accounting Fees and Services

89

 

 

 

 

 

PART IV

 

Item 15.

 

Exhibits and Financial Statement Schedules

91

 



Table of Contents

 

PART I

 

Item 1.  Business

 

General

 

Aventine Renewable Energy Holdings, Inc. (the “Company,” “Aventine,” “we,” “our,” or “us”) is a producer and marketer of fuel-grade ethanol in the United States (“U.S.”).  We market and distribute ethanol to many of the leading energy and trading companies in the U.S.  We produced 197.5 million gallons and 188.8 million gallons of ethanol in 2009 and 2008, respectively.  Historically, we have also been a large marketer of ethanol, distributing ethanol purchased from other third-party producers in addition to our own ethanol production.  In 2009 and 2008, we distributed 65.7 million gallons and 754.3 million gallons, respectively, of ethanol produced by others.  The decrease in distributed gallons from 2008 to 2009 is attributable to the termination of our marketing alliance and substantial reduction in our purchase/resale supply operations in late 2008 and the first quarter of 2009.  In addition to producing ethanol, our facilities also produce several co-products, such as distillers grain, corn gluten meal and feed, corn germ and brewers’ yeast, which generate incremental revenue and allow us to help offset a significant portion of our corn costs.

 

We were acquired by the Morgan Stanley Capital Partners funds (“MSCP”) from a subsidiary of The Williams Companies, Inc. on May 30, 2003.  The acquisition was accounted for as a purchase business combination in accordance with Accounting Standards Codification 805, Business Combinations (“ASC 805”).  We are a Delaware corporation organized in 2003, and are the successor to businesses engaged in the production and marketing of ethanol since 1981.  Effective July 5, 2006, we completed an initial public offering of our common stock, $0.001 par value, pursuant to a Registration Statement on Form S-1, as amended (Reg. No. 333-132860), that was declared effective on June 28, 2006.

 

Chapter 11 Bankruptcy Proceedings

 

On April 7, 2009 (the “Petition Date”), Aventine Renewable Energy Holdings, Inc., and all of its direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions for relief (collectively, the “Bankruptcy Filing”) under Chapter 11 (“Chapter 11”) of Title 11 of the United States Code (the “Bankruptcy Code”) with the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”).  The Chapter 11 cases are being jointly administered by the Bankruptcy Court as Case No. 09-11214 (KG) (collectively, the “Bankruptcy Cases”).  The Debtors specifically are (i) Aventine Renewable Energy Holdings, Inc.; (ii) Aventine Renewable Energy, LLC, a Delaware limited liability company; (iii) Aventine Renewable Energy, Inc., a Delaware corporation; (iv) Aventine Renewable Energy — Mt. Vernon, LLC, a Delaware limited liability company; (v) Aventine Renewable Energy — Aurora West, LLC, a Delaware limited liability company; (vi) Aventine Power, LLC, a Delaware limited liability company, and (vii) Nebraska Energy, LLC, a Kansas limited liability company.

 

The Debtors are currently operating as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court, and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.  In general, as debtors-in-possession, the Debtors are authorized under the Bankruptcy Code to continue to operate as an ongoing business, but may not engage in transactions outside of the ordinary course of business without the approval of the Bankruptcy Court.

 

On April 7, 2009, certain of the Company’s bondholders entered into a term sheet (the “DIP Term Sheet”) for a $30 million Debtor-in-Possession Credit Facility with the Debtors.  The DIP Term Sheet provides, subject to certain conditions as described in the Debtor-in-Possession Credit Facility Term Sheet filed as Exhibit 10.1 to our Form 8-K filed on April 13, 2009 for a first priority debtor-in-possession

 

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financing comprised of a term loan facility made available to certain of Aventine’s subsidiaries in a maximum aggregate principal amount of up to $30 million (the “DIP Facility”).  On May 5, 2009, the Bankruptcy Court overruled objections from the Debtors’ pre-petition secured lenders and approved the DIP Facility on a final basis.  Proceeds of the DIP Facility are available to, among other things, (i) fund the working capital and general corporate needs of the Debtors and the costs of the Bankruptcy Cases in accordance with an approved budget, and (ii) provide adequate protection, in accordance with the terms of the DIP Facility, to the pre-petition agent and pre-petition lenders under the Company’s existing credit facilities.  The DIP Facility bears interest at 16.5% per annum.  The maturity date of the DIP Facility is April 6, 2010, or upon the occurrence of certain pre-defined events.  The DIP Facility is secured by a super-priority administrative claim on our assets.

 

On December 4, 2009, the Debtors filed the Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code Dated as of December 4, 2009 (the “Initial Chapter 11 Plan”) and the Disclosure Statement for the Debtors’ Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code Dated as of December 4, 2009.  The Debtors amended the Initial Chapter 11 Plan and on January 13, 2010, the Debtors filed the Debtors’ First Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code dated as of January 13, 2010 (as amended, modified an/or supplemented, the “Plan” or “Plan of Reorganization”) and the Disclosure Statement for Debtors’ First Amended Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code dated January 13, 2010 (as amended, modified and/or supplemented, the “Disclosure Statement”).  A hearing has been scheduled by the Bankruptcy Court for February 24, 2010 to consider confirmation of the Plan.

 

Although the Debtors filed a Chapter 11 plan that provides for emergence from Chapter 11 some time in the future, there can be no assurance that a Chapter 11 plan will be confirmed by the Bankruptcy Court, or that any such plan will be consummated.  In order to successfully emerge from bankruptcy, the Debtors will need to, among other things, obtain alternative financing to replace the DIP Facility.  The Company has obtained approval of the Disclosure Statement and is pursuing confirmation of the Plan, which includes a backstop lending agreement in connection with the issuance of senior secured notes in the face amount of $105 million.  For further discussion, see “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

Going Concern Matters

 

The ability of the Company to continue as a going concern is dependent upon, among other things, (i) the Company’s ability to comply with the terms and conditions of the DIP Facility; (ii) the ability of the Company to maintain adequate cash on hand; (iii) the ability of the Company to generate cash from operations; (iv) the ability of the Company to obtain confirmation of and to consummate a plan of reorganization under the Bankruptcy Code; (v) the cost and outcome of the reorganization process; (vi) the Company’s ability to obtain alternative financing; and (vii) the Company’s ability to achieve profitability.  Uncertainty as to the outcome of these factors raises substantial doubt about the Company’s ability to continue as a going concern.  The Company is currently evaluating various courses of action to address the issues the Company is facing.  There can be no assurance that any of these efforts will be successful.

 

The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of our Chapter 11 proceedings.  In particular, the financial statements do not purport to show (i) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (ii) as to pre-petition liabilities, the amounts that may be paid out for claims or contingencies, or the status and priority thereof; (iii) as to shareowners’ equity accounts, the effect of any changes that may be made in our capitalization; or (iv) as to operations, the effect of any changes that may be made to our business.

 

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We have prepared  the consolidated financial statements in accordance with Accounting Standards Codification 852, Reorganizations (“ASC 852”).  This guidance requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business.  Accordingly, certain expenses (including professional fees), realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings are recorded in reorganization items on the accompanying Consolidated Statements of Operations.  In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on the  Consolidated Balance Sheet at December 31, 2009 in “pre-petition liabilities subject to compromise.”  These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.  For information on the bankruptcy reorganization process, see Note 2 - Chapter 11 Bankruptcy Proceedings.

 

Available Information

 

Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports are available on our website, at no charge, at www.aventinerei.com, as soon as reasonably practicable after electronic filing or furnishing such information to the U.S. Securities and Exchange Commission (“SEC”).  Also available on our website, or in print upon written request at no charge, are our corporate governance guidelines, the charters of our audit, compensation and nominating and corporate governance committees, and a copy of our code of business conduct and ethics that applies to our directors, officers and employees, including our chief executive officer, principal financial officer, principal accounting officer, controller, or other persons performing similar functions.  Finally, there is a section on our website covering the status of the Company’s reorganization under Chapter 11 of the Bankruptcy Code.  Information on our website should not be considered to be part of this annual report on Form 10-K.

 

Industry Overview

 

Ethanol is marketed across the U.S. as a gasoline blend component that serves as a clean air additive, an octane enhancer and a renewable fuel resource.  It is blended with gasoline (i) as an oxygenate to help meet fuel emission standards, (ii) to improve gasoline performance by increasing octane levels and (iii) to extend fuel supplies.  A small but growing amount of ethanol is also used as E85, a renewable fuels-driven blend comprised of up to 85% ethanol.

 

Ethanol is generally sold through short-term contracts.  Although ethanol has in the past generally been priced as either a negotiated fixed price or a price based upon the price of wholesale gasoline plus or minus a fixed amount, the majority of ethanol sold in the U.S. today is based upon a spot index price at the time of shipment.  The price of ethanol has historically moved in relation to the price of wholesale gasoline and the value of the Volumetric Ethanol Excise Tax Credit (“VEETC”).  However, the price of ethanol over the last three years has been largely driven by supply/demand fundamentals and the price of corn.

 

According to recent industry reports, approximately 99.4% of domestic ethanol is produced from corn fermentation as of December 31, 2009 and, as such, is primarily produced in the Midwestern corn-growing states.  The principal factor affecting the cost to produce ethanol is the price of corn.

 

The U.S. fuel ethanol industry has experienced rapid growth, increasing from 1.4 billion gallons of production in 1998 to approximately 9.0 billion gallons produced in 2008, the latest year for which production information is available.  According to the Energy Information Administration, LEGC, LLC, the use of that 9.0 billion gallons of ethanol displaced the need for 321.4 million barrels of oil.  The Renewable Fuels Association (“RFA”) reports that  the U.S. fuel ethanol industry has approximately 11.9 billion gallons of operating annual production capacity as of December 2009.

 

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The demand for ethanol has been driven by recent trends as more fully described below:

 

·                  Mandated usage of renewable fuels.  The growth in ethanol usage has been supported by regulatory requirements dictating the use of renewable fuels, including ethanol.  The Energy Independence and Security Act of 2007 signed into law on December 19, 2007, requires mandated minimum usage of renewable fuels of 12.95 billion gallons in 2010 and 13.95 billion gallons in 2011. The mandated usage of renewable fuels increases to 36 billion gallons in 2022.  The mandate for corn-based ethanol is capped at 15 billion gallons for the years 2015 through 2022.

 

·                  Economics of ethanol blending.  As oil prices increased during the commodity bubble of 2007 and 2008, the price of gasoline also increased substantially.  The price per gallon of ethanol during this same time period, although increasing, did not keep pace with the increase in the price of gasoline.  This phenomenon created an opportunity for refiners and blenders to increase the profitability of the gasoline they sold by blending ethanol in amounts in excess of mandated levels (although not in excess of 10%).  This discretionary blending was a driving force behind the rapid growth in the consumption of ethanol in 2007 and the first half of 2008.  The profitability of blending ethanol was further enhanced by the VEETC, which was then $0.51 for each gallon of ethanol blended.

 

·                  Carryover of Renewable Identification Number credits (“RINS”).  Refiners, importers and blenders (other than oxygen blenders) of gasoline are obligated parties under the Renewable Fuels Standard.  The consumption of ethanol above mandated amounts creates an excess of RINS that  are available to satisfy an obligated party’s blending requirements in the following year.  The obligated parties are allowed to meet their requirement to consume renewable fuels through the accumulation or purchase of excess RINS, instead of from the actual physical purchase of renewable fuels.  From September 1, 2007 through mid 2008, obligated parties blended significantly more ethanol than was required by the mandate as the economics of blending ethanol were quite profitable.  As the blending economics of ethanol became less profitable with the rapid decline in oil prices beginning in the second half of 2008, obligated parties began to apply these excess RINS to meet their obligations which resulted in a significantly reduced demand for ethanol.  For 2009, obligated parties blended approximately the same amount of ethanol that was required by the mandate.  However, the carryover of 2008 RINS into 2009 created an excess of 2009 RINS that will be available to satisfy an obligated party’s blending requirements in 2010.  Our view is that there are approximately 1.50 billion RINS available to satisfy an obligated parties requirement for 2010.  With the 2010 mandate for renewable biofuels at 12 billion gallons, this means that the actual physical ethanol volume that has to be purchased can be as low as 10.50 billion gallons.

 

·                  Emission reduction.  Ethanol is an oxygenate which, when blended with gasoline, reduces vehicle emissions.  Ethanol’s high oxygen content burns more completely, emitting fewer pollutants into the air.  Ethanol demand increased substantially beginning in 1990 when federal law began requiring the use of oxygenates (such as ethanol or methyl tertiary butyl ether (“MTBE”)) in reformulated gasoline in cities with unhealthy levels of air pollution on a seasonal or year round basis.  Although the federal oxygenate requirement was eliminated in May 2006 as part of the Energy Policy Act of 2005, oxygenated gasoline continues to be used in order to help meet separate federal and state air emission standards.  The refining industry has all but abandoned the use of MTBE, making ethanol the primary clean air oxygenate currently used.

 

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·                  Octane enhancer.  Ethanol, with an octane rating of 113, is used to increase the octane value of gasoline with which it is blended, thereby improving engine performance.  It is used as an octane enhancer both for producing regular grade gasoline from lower octane blending stocks (including both reformulated gasoline blendstock for oxygenate blending and conventional gasoline blendstock for oxygenate blending), and for upgrading regular gasoline to premium grades.

 

·                  Fuel stock extender.  According to the Energy Information Administration, while domestic petroleum refinery output has increased by approximately 29% from 1980 to 2008, domestic gasoline consumption has increased 36% over the same period, which is the latest period for which information is available.  By blending ethanol with gasoline, refiners are able to expand the volume of the gasoline they are able to sell.

 

·                  Growth in E85 usage.  E85 is a blended motor fuel containing up to 85% ethanol.  The sale of E85 fuel has historically been less than 1% of the ethanol market (and less than 0.25% of the ethanol we produce).  Its growth has been limited by both the availability of E85 fuel to consumers and by the number of automobiles capable of using the fuel.  According to E85Prices.com., as of February 9, 2010, only 2,246 gasoline stations across the U.S. sold E85, and there are roughly 9 million flex fuel vehicles on the roads.  However, the same website states that the number of stations offering E85 is expected to double in a little over a year as service stations are being offered incentives from Government and Ethanol Industry grants up to $30,000 to install E85 fuel pumps.  They also state that General Motors, Ford, and Chrysler have pledged that at least 50% of their production will be flex fuel capable by 2011/2012.  These two factors point to a potential growth in the consumption of E85 in future years.

 

Ethanol Production Processes

 

The production of ethanol from corn can be accomplished through one of two distinct processes: wet milling and dry milling.  Though the number of dry mill facilities significantly exceeds the number of wet mill facilities, their size is typically smaller.  The principal difference between the two processes is the initial treatment of the grain and the resulting co-products.  The increased production of higher margin co-products in the wet mill process results in a lower ethanol yield.  At a denaturant blend level of 1.96%, a typical wet mill yields approximately 2.5 gallons of ethanol per bushel of corn while a typical dry mill yields approximately 2.7 gallons of fully denatured ethanol per bushel of corn.

 

Wet Milling

 

In the wet mill process, the corn is soaked or “steeped” in water and sulfurous acid for 24 to 48 hours to separate the grain into its many parts.  After steeping, the corn slurry is processed to separate the various components of the corn kernel, including the corn germ, which is then sold for processing into corn oil.  The starch and any remaining water from the slurry can then be fermented and distilled into ethanol.  The ethanol is then blended with a denaturant, such as gasoline, to render it unfit for consumption and thus not subject to the alcohol beverage tax.

 

The remaining parts of the grain in the wet mill process are processed into a number of different forms of protein used to feed livestock.  The multiple co-products from a wet mill facility generate a higher level of cost recovery from corn than the principal co-product (dried distillers grains with solubles (“DDGS”)) from the dry mill process.  In addition, a wet mill, if properly equipped, can produce a higher value brewers’ yeast in order to lower its net corn cost.  For the years ended December 31, 2009, 2008 and

 

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2007, we recovered 42.7%, 45.6% and 46.3%, respectively, of our total corn costs related to our wet mill process through our sale of co-products and bio-products.

 

Dry Milling

 

In a dry mill process, the entire corn kernel is first ground into flour, which is referred to in the industry as “meal”, and is processed without first separating the various component parts of the grain.  The meal is processed with enzymes, ammonia and water, and then placed in a high-temperature cooker to reduce bacteria levels ahead of fermentation.  It is then transferred to fermenters where yeast is added and the conversion of sugar to ethanol begins.  The fermentation process generally takes between 40 and 50 hours.  After fermentation, the resulting liquid is transferred to distillation columns where the ethanol is evaporated from the remaining “stillage” for fuel uses.  As with the wet milling process, the ethanol is then blended with a denaturant, such as gasoline, to render the ethanol unfit for consumption and thus not subject to the alcohol beverage tax.

 

With the starch elements of the corn kernel consumed in the above described process, the principal co-product produced by the dry mill process is DDGS.  DDGS is sold as a protein used in animal feed and recovers a portion of the total cost of the corn, although less than the co-products resulting from the wet mill process described above.  For the years ended December 31, 2009, 2008 and 2007, we recovered 25.7%, 26.2% and 26.6%, respectively, of our corn costs related to our dry mill process through the sale of DDGS and other co-products.

 

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The following graphic depicts the corn to ethanol conversion process:

 

 

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Business Overview

 

We derive our revenue primarily from the sale of ethanol.  We also derive revenue from the sale of co-products (corn gluten feed and meal, corn germ, condensed corn distillers with solubles (“CCDS”), carbon dioxide, DDGS and wet distillers grains with solubles (“WDGS”)) and bio-products (brewers’ yeast) which are produced as by-products during the production of ethanol at our plants.  Historically, we have sourced ethanol from the following three sources:

 

·                  Ethanol we manufactured at our own plants, which we refer to as equity production;

·                  Ethanol we were obligated to purchase from a third party producer under contract where we shared costs and collected commissions, which we refer to as marketing alliance production; and

·                  Ethanol we purchased either on the spot market or under contract, which we refer to as purchase/resale.

 

We market and sell ethanol without regard to the source of origination.  With our own equity production combined with ethanol sourced from third parties, we marketed and distributed 277.5 million, 936.0 million and 690.2 million gallons of ethanol for the years 2009, 2008 and 2007, respectively.  Because of the challenges facing the ethanol industry in general and us in particular, we sharply decreased the number of gallons of ethanol we sold that were produced by others in 2009 by terminating our marketing alliance and significantly reducing our purchase/resale operation.

 

Equity Ethanol Production

 

We own and operate one of the few coal-fired, corn wet mill plants in the U.S. in Pekin, Illinois, which we refer to as the “Illinois wet mill facility.”  In addition, we own and operate a natural gas-fired corn dry mill plant in Pekin, Illinois which we refer to as the “Illinois dry mill facility”, and a natural gas-fired corn dry mill plant in Aurora, Nebraska, which we refer to as the “Nebraska facility.”

 

The denaturant we use is typically a low-grade gasoline.  Beginning in 2009, IRS regulations reduced the maximum permitted amount of denaturant for which the VEETC can be taken to 1.96%.  In November 2008, our Illinois dry mill facility received a revised permit from the Illinois Environmental Protection Agency allowing production capacity at that facility to increase to 63.3 million gallons of undenatured ethanol.  We have not increased the stated capacity of our Pekin dry mill to reflect the revised permit.

 

Our Illinois dry mill facility was completed in early 2007.  The addition of this facility increased our total annual production capacity by approximately 57 million gallons.  For each of the years ended December 31, 2009, 2008, and 2007, our facilities had a combined total ethanol production capacity of approximately 200 million gallons annually with corn processing capacity of approximately 77 million bushels per year at capacity.  Our plants may operate at a capacity which is less than the stated capacity.  We occasionally experience plant outages (both planned and unplanned), as well as other related productivity issues.  Planned outages are typically for maintenance and average approximately one week per plant each year.  We may also occasionally experience unplanned outages at our facilities which may negatively impact production and related revenue.  Our plants ran at 98% of capacity for 2009 and at 94% of capacity for both 2008 and 2007 after adjusting for differences in denaturant blending levels.

 

For the years ended December 31, 2009, 2008 and 2007, we produced 197.5 million, 188.8 million, and 192.0 million gallons of ethanol, respectively, from our own facilities.  Our equity production operations generate the substantial majority of our operating income or loss.

 

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Marketing Alliance Production

 

Historically, our marketing business was an important component of our business.  Marketing alliance partners were third-party producers (including producers in which we may have had a non-controlling interest), who sold their ethanol production to us on an exclusive basis.  Ethanol produced by our marketing alliance partners enabled us to meet major ethanol consumer needs by providing us with a nationwide marketing presence without having to make capital investments and through leveraging our marketing expertise and our distribution systems.  Marketing alliance contracts required us to purchase all of the production from these facilities and sell it at contract or prevailing market prices.  We were entitled to commissions on the sale of marketing alliance gallons in accordance with the terms of the marketing alliance contracts.  The contribution to our operating income from the sale of marketing alliance gallons was relatively small as commission rates typically were 1% or less of the “netback” price.  The netback price was the selling price of ethanol less a “cost recovery component.”  The cost recovery component represented reimbursement to us for certain costs, including freight, storage, inventory carrying cost and indirect marketing costs.  The purchase price we paid our marketing alliance partners was based on an average price at which we sold ethanol less the cost recovery component and commission.  Revenue from marketing alliance gallons sold included the gross revenue from such sales and not merely the commissions earned because we (i) took title to the inventory, (ii) were the primary obligor in the sales arrangement with the customer, and (iii) assumed all the credit risk.

 

For the years ended December 31, 2008 and 2007, we purchased  505.3 million and 395.0 million gallons of ethanol, respectively, from our marketing alliance partners.  However, with severely declining margins and general liquidity stress due to frozen credit markets, this model no longer worked for our alliance partners or Aventine.  As such, beginning in the fourth quarter of 2008, we negotiated termination agreements with our marketing alliance partners and began to rationalize our distribution network to primarily focus on sales of our equity production.  For the year ended December 31, 2009, we purchased only 30.9 million gallons of ethanol from marketing alliance partners.  We also recognized $10.2 million of income from the termination of our marketing alliance agreements in 2009.

 

Purchase/Resale

 

Historically, we have also purchased ethanol from unaffiliated third-party producers and marketers on both a spot basis and under contract.  These transactions were driven by our ability to purchase ethanol and then, through our distribution network and customer relationships, resell the ethanol.  The margin from purchase/resale transactions could be volatile and we occasionally incurred losses on these transactions.

 

For the years ended December 31, 2008 and 2007, we purchased for resale  249.0 million and 111.5 million gallons of ethanol, respectively, from unaffiliated producers and marketers.  As discussed above under “Marketing Alliance Production” and further discussed under “Item 1 — Business — Marketing Alliances”, we began a program to rationalize our distribution network and reduce our sourcing of ethanol from third parties in late 2008.  Our purchase/resale program was part of this rationalization process.  Accordingly, we only purchased 35.5 million gallons of ethanol for resale from unaffiliated producers and marketers during 2009.

 

By-Products

 

We generate additional revenue through the sale of by-products (both co-products and bio-products) that result from the ethanol production process.  These by-products include brewers’ yeast, corn gluten feed and meal, corn germ, CCDS, carbon dioxide, DDGS and WDGS.  The volume of by-products we produce varies with the level of our equity production.  Scheduled maintenance, along with other non-scheduled operational difficulties, may affect the volume of by-products produced.  We may also shift the mix of these

 

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by-products, to increase our revenue.  By-product revenue is driven by both the quantity of by-products produced and the market price received for our by-products which have historically tracked the price of corn.

 

For the years ended December 31, 2009, 2008 and 2007, we generated approximately $97.9 million, $128.5 million and $99.3 million, respectively, of revenue from the sale of co-products and bio-products, allowing us to recapture approximately 34.1%, 35.9% and 36.7% of our corn costs, respectively, in each of these years.  Co-product returns, as a percentage of corn costs, decreased in 2009 as co-product pricing decreased more than corn costs.  Co-products produced by the dry mill process have less value historically than those produced by the wet mill process.  As a result of the addition of the Pekin dry mill, our overall product mix between wet and dry co-products produced changed from 67% higher value wet mill products and 33% lower value dry mill products prior to 2007, to roughly 50% higher value wet mill products and 50% lower value dry mill products beginning in 2007.

 

Due to recent and planned industry increases in U.S. dry mill ethanol production, the production of co-products from dry mills in the U.S. has increased dramatically, and this trend may continue.  This may cause co-product prices to fall in the U.S., unless demand increases or other market sources are found.  To date, demand for DDGS (the principal co-product produced by dry mills) in the U.S. has increased roughly in proportion to supply.  We believe this is because U.S. farmers use DDGS as a feedstock, and DDGS are slightly less expensive than corn, for which it is a substitute.  However, if prices for DDGS in the U.S. fall, it may have an adverse effect on our business, which might be material.

 

Products

 

Ethanol

 

Our principal product is fuel-grade ethanol, an alcohol which is derived in the U.S. principally from corn.  Ethanol is sold primarily for blending with gasoline to meet mandates for the required consumption and use of biofuels, as an octane enhancer, as an oxygenate additive for the purpose of meeting fuel emission standards and as a fuel extender.  See “Item 1 — Business — Industry Overview.” For the years ended December 31, 2009, 2008 and 2007, ethanol sales represented 81.5%, 92.5% and 91.3%, respectively, of our total revenue.  The reduction in the 2009 percentage of total revenue attributable to ethanol sales is the result of the elimination of the ethanol sales dollars attributable to our marketing alliance and substantial reduction in the ethanol sales dollars attributable to our purchase/resale supply operation from our total revenue numbers for 2009.

 

Co-Products

 

Our Illinois wet mill facility produces co-products such as corn gluten feed (both wet and dry), corn gluten meal, CCDS and corn germ.  In addition, the fermentation process yields carbon dioxide.  These co-products are sold for various consumer uses into large commodity markets.  Corn gluten feed, corn gluten meal and CCDS are used as animal feed ingredients, corn germ is sold for the extraction of corn oil for human consumption, and carbon dioxide is sold for food-grade use such as beverage carbonation and dry ice.  Our dry mill facilities in Pekin, Illinois and Aurora, Nebraska produce co-products such as DDGS, WDGS and carbon dioxide.  Distillers products are marketed as high protein animal feed and carbon dioxide is sold for beverage carbonation and dry ice.  For the years ended December 31, 2009, 2008 and 2007, co-products represented 14.4%, 5.2% and 5.7%, respectively, of our total revenue.  The increase in the 2009 percentage of total revenue attributable to co-product sales is the result of the elimination of the ethanol sales dollars attributable to our marketing alliance and substantial reduction in the ethanol sales dollars attributable to our purchase/resale supply operation from our total revenue numbers for 2009.

 

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Bio-Products

 

Our Illinois wet mill facility also produces bio-products, Kosher and Chametz free brewers’ yeast, which is processed into a growing variety of products for use in animal and human food and fermentation applications.  For the years ended December 31, 2009, 2008 and 2007, bio-products represented 2.1%, 0.5% and 0.6%, respectively, of our total revenue.

 

Competition

 

According to the RFA, there were 122 producers operating 185 ethanol plants in the U.S. as of December 31, 2009.  The top ten producers accounted for approximately 47.9%, 46.6%, and 54.3% of total industry capacity for the years 2009, 2008, and 2007, respectively.  Aventine was one of the top ten producers, who all have annual production capacity exceeding 200 million gallons per year.

 

A significant development during 2009 was Valero Energy’s acquisition of ten ethanol plants from VeraSun Energy and Renew Energy.  As a result of the acquisitions, the second largest U.S. oil refiner is now a top 10 producer with annual ethanol production capacity of approximately 1 billion gallons.

 

The remaining producers consist primarily of small capacity producers and farmer cooperatives.

 

The world’s ethanol producers have historically competed primarily on a regional basis.  Imports into the U.S. have generally been limited by an import tariff of $0.54 per gallon (other than from Caribbean basin countries which are exempt from this tariff up to specified limits).

 

Certain of our competitors have significantly larger market shares than we have, and tend to be price leaders in the industry.  If any of these competitors were to significantly reduce their prices, our business, operating results and financial condition could be adversely affected.

 

We could also be adversely affected if new products or technologies emerge that reduce or eliminate the need for ethanol.  Our ethanol production is corn based, and competes with ethanol made from alternative materials, such as sugar, wheat and sorghum.  Cellulosic sources of materials may also become a substitute feedstock for ethanol production, or other products may be devised which eliminate the need for ethanol entirely.  Periods of time with sustained high corn prices could decrease the relative attractiveness of corn-based ethanol where alternatives exist, thereby adversely affecting our business, operating results or financial condition.

 

Business Strategies

 

Our objective is to strengthen and reposition our Company by concentrating on improving our liquidity, competitiveness, operating performance and customer service, and to remain a leading supplier and distributor of ethanol in the U.S.  Towards this end, we are pursuing the following business strategies:

 

Liquidity Preservation and Balance Sheet Restructuring

 

As a result of our bankruptcy filing, we have been accelerating our efforts to preserve existing liquidity, and are attempting to raise additional sources of liquidity and capital in conjunction with our proposed Plan of Reorganization.  We have suspended construction of our expansion facilities at both Mt. Vernon, Indiana and Aurora, Nebraska.  We have taken steps to reduce our fixed cost structure by rationalizing and reducing the size and scope of our distribution network.  We have also reduced our workforce, primarily as a result of the termination of our marketing alliance.

 

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Although we are actively pursuing a number of liquidity alternatives in conjunction with our proposed Plan of Reorganization, there can be no assurance we will be successful or that the Plan, or any other Chapter 11 plan, will be confirmed by the Bankruptcy Court.  For more information see “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital.”

 

Optimizing Productivity and Infrastructure

 

We are improving the efficiency and effectiveness of our distribution and logistics assets, and are optimizing our resources to support innovation and future growth.

 

In light of rapid changes in customer demands that are occurring relative to the distribution and sale of ethanol in the marketplace, we undertook a rationalization of our terminal and distribution system.  As part of this rationalization process, we significantly reduced or eliminated our presence in numerous terminals, resulting in the reduction of fixed transportation commitments to barges and railcars.  These steps have significantly reduced the fixed costs of maintaining our distribution and logistics assets.

 

Sales and Marketing

 

We employ direct sales personnel to pursue sales opportunities.  In addition, customer service representatives are available to respond to customer questions and to undertake or resolve any required customer service issues.  Our sales structure forms an integral, critical link in communicating with our customers.  The sales function is coordinated through key senior executives responsible for our sales and marketing efforts.

 

Marketing Alliances

 

Prior to terminating the Marketing Alliance in late 2008 and early 2009, we sourced ethanol from marketing alliance partners which allowed us to increase sales and enhance our position as a leading player in the ethanol industry.  In exchange for allowing us to market their ethanol exclusively, marketing alliance partners gained the benefit of our customer relationships and our ability to distribute ethanol.  However, as described above, with severely declining margins and general liquidity stress due to frozen credit markets, this model no longer worked for our alliance partners or us.  As such, beginning in the fourth quarter of 2008, we negotiated termination agreements with our marketing alliance partners and began to rationalize our distribution network to primarily focus on sales of our equity production.  For the year ended December 31, 2009, we purchased only 30.9 million gallons of ethanol from marketing alliance partners.  We recognized $10.2 million of income from the termination of our marketing alliance agreements in 2009.  During the years ended December 31, 2008 and 2007, we purchased 505.3 million and 395.0 million gallons, respectively, of ethanol produced by our marketing alliance partners.

 

As part of our new marketing strategy geared toward our equity production, we significantly reduced our fixed costs associated with our distribution network.

 

Investments

 

Historically, we had made minority investments in other ethanol producers.  Investments made by the Company in other ethanol producers after May 31, 2003 were recorded at cost, including our investment in Indiana BioEnergy (“IBE”) prior to its acquisition by Green Plains Renewable Energy (“GPRE”).  Our investment in IBE was valued at December 31, 2007 at our initial investment cost of $5.0 million.  On October 15, 2008, IBE merged with GPRE, a publicly held company whose shares are traded on the NASDAQ national market, and our $5.0 million original investment was converted to 365,999 shares of

 

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GPRE stock.  On October 15, 2008, we recorded a loss of $2.8 million on the exchange and reduced the value of our investment from $5.0 million to $2.2 million, which was the market price of the GPRE shares at that date.  As our investment in GPRE shares is considered an available for sale investment in accordance with Accounting Standards Codification 320, Investments - Debt and Equity Securities (“ASC 320”), we recognized an other than temporary loss of $1.5 million on December 31, 2008.  We made our determination that the loss in GPRE stock was other than temporary, considering our lack of ability and intent to hold this security to recover its value given our liquidity situation at that time.  The GPRE stock has recovered significantly.  Our recorded investment in GPRE at December 31, 2009, based upon the closing price of GPRE stock on the last trading day of 2009, is now carried at $5.4 million.

 

During 2009, we sold our interests in Ace Ethanol, LLC and Granite Falls Energy LLC, recording gains totaling $1.0 million.

 

Distribution and Logistics

 

Due to severely declining margins and general liquidity stress due to frozen credit markets, we have significantly reduced the number of gallons we source from third parties.  As noted above, beginning in the fourth quarter of 2008 we began negotiating termination agreements with most of our marketing alliance partners and terminated all of them during 2009.  We recognized $10.2 million of income from the termination of our marketing alliance agreements during 2009.  Accordingly, we have also undertaken a strategy to rationalize our distribution and logistics system to focus primarily on our equity production.  At December 31, 2008, we had signed agreements for leased terminal capacity at 57 terminal locations.  During 2009, we subleased or assigned the majority of our railcar, barge and terminal leases.  We have aligned our distribution network in relation to production volumes from our equity-owned ethanol production facilities, and this distribution network has a cost structure that is comprised of minimal fixed cost commitments and is operated primarily on a variable cost basis.  At December 31, 2009, we had signed agreements for leased terminal capacity at only 3 terminal locations.

 

The costs associated with leasing these terminals were previously factored into the purchase price we paid our marketing alliance partners for the ethanol that we purchased from them and, therefore, a portion of these leasing costs were effectively paid for by our marketing alliance partners.

 

Legislative Drivers and Governmental Regulations

 

The U.S. ethanol industry is highly dependent upon federal and state legislation, in particular:

 

·                  The Energy Independence and Security Act of 2007;

·                  The federal ethanol tax incentive program;

·                  Federal tariff on imported ethanol;

·                  The use of fuel oxygenates; and

·                  Various state mandates.

 

The Energy Independence and Security Act of 2007

 

Enacted into law on December 19, 2007, the Energy Independence and Security Act of 2007 significantly increases the mandated usage of renewable fuels (ethanol, bio-diesel or any other liquid fuel produced from biomass or biogas).  The law increases the renewable fuels standard originally established under the Energy Policy Act of 2005 to 36 billion gallons by 2022, of which the mandate for corn-based ethanol is limited to 15 billion gallons annually from 2015 through 2022.

 

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The federal ethanol tax incentive program

 

First passed in 1979, the VEETC program allows gasoline distributors who blend ethanol with gasoline to receive a federal excise tax credit for each gallon of ethanol they blend.  The federal Transportation Efficiency Act of the 21st Century, or TEA-21, extended the ethanol tax credit first passed in 1979 through 2007.  The American Jobs Creation Act of 2004 extended the subsidy again to 2010 by allowing distributors to take a $0.51 excise tax credit for each gallon of ethanol they blend.  Under the Food, Conservation and Energy Act of 2008, the tax credit was reduced to $0.45 per gallon for 2009 and thereafter.  We cannot give assurance that the tax incentives will be renewed in 2010 or, if renewed, on what terms they will be renewed.  See “Item 1A — Risk Factors — The use and demand for ethanol and its supply are highly dependent on various federal and state legislation and regulation, and any changes in legislation or regulation could cause the demand for ethanol to decline or its supply to increase, which could have a material adverse effect on our business, results of operation and financial condition.”

 

Federal tariff on imported ethanol

 

In 1980, Congress imposed a tariff on foreign produced ethanol to offset the value of Federal tax subsidies.  This tariff was designed to protect the benefits of the federal tax subsidies for U.S. farmers.  The tariff was originally $0.60 per gallon in addition to a 3.0% ad valorem duty.  The tariff was subsequently lowered to $0.54 per gallon with a 2.5% ad valorem duty and was not adjusted completely in direct relative proportion with change in the VEETC.  The 2008 Farm Bill extended the $0.54 per gallon tariff on foreign produced ethanol until January 1, 2011.

 

Ethanol imports from 24 countries in Central America and the Caribbean Islands are exempt from this tariff under the Caribbean Basin Initiative (“CBI”) in order to spur economic development in that region.  Under the terms of the CBI, member nations may export ethanol into the U.S. up to a total limit of 7% of U.S. production per year (with additional exemptions for ethanol produced from feedstock in the Caribbean region over the 7% limit).  In the past, significant imports of ethanol into the U.S. have had a negative effect on ethanol prices.  See “Item 1A — Risk Factors — The use and demand for ethanol and its supply are highly dependent on various federal and state legislation and regulation, and any changes in legislation or regulation could cause the demand for ethanol to decline or its supply to increase, which could have a material adverse effect on our business, results of operation and financial condition.”

 

Use of fuel oxygenates

 

Ethanol is used by the refining industry as a fuel oxygenate which, when blended with gasoline, allows engines to burn fuel more completely and reduce emissions from motor vehicles.  The use of ethanol as an oxygenate had been driven by regulatory factors, specifically two programs in the federal Clean Air Act Amendments of 1990, that required the use of oxygenated gasoline in areas with unhealthy levels of air pollution.  Although the federal oxygenate requirements for reformulated gasoline included in the Clean Air Act were completely eliminated on May 5, 2006 by the Energy Policy Act of 2005, refiners continue to use oxygenated gasoline in order to meet continued federal and state fuel emission standards.

 

State Mandates

 

Several states, including Florida, Missouri, Montana and Oregon, have enacted mandates that currently, or will in the future, require ethanol blends of 10% in motor fuel sold within the state.  Another state, Minnesota, has a 20% renewable fuel mandate that goes into effect in 2013.  These mandates help increase demand for ethanol.  As more states consider mandates, or if existing mandates are relaxed or eliminated, the demand for ethanol can be affected.

 

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Customers

 

The substantial majority of our customer base has purchased ethanol from us for over five years (including our predecessor companies).  In 2009, 2008 and 2007, our 10 largest customers accounted for approximately 66%, 50% and 67%, respectively, of our consolidated ethanol sales volume.

 

In 2009, Biourja Trading accounted for 10.5% and Exxon Mobil accounted for 11.1% of our net sales.  No other customers in 2009 represented more than 10% of our consolidated net sales volume.  No customers in 2008 or 2007 represented more than 10% of our consolidated net sales volume.

 

Pricing and Backlog

 

Historically, ethanol delivered to customers was priced in accordance with one of the following methods:  (i) a negotiated fixed contract price per gallon, (ii) a price per gallon based on an average spot value of ethanol at the time of shipment plus or minus a fixed amount, or (iii) a price per gallon based on the market value of wholesale unleaded gasoline plus or minus a fixed amount.  The Company believed these pricing strategies, in conjunction with the rapid turnover of its inventory, provided a natural hedge against changes in the market price of ethanol.  Currently the majority of ethanol sold to customers is based upon a spot index price.

 

As of December 31, 2009, we had contracts for delivery of ethanol totaling 57.3 million gallons through September 30, 2010, all at spot prices (using various Platt, OPIS and AXXIS indices).

 

Raw Materials and Suppliers

 

Our principal raw material is #2 yellow corn.  In 2009, 2008 and 2007, we purchased approximately 74.2 million, 71.4 million and 71.9 million bushels of corn, respectively.

 

We contract for our corn requirements through a variety of sources, including farmers, grain elevators, and cooperatives.  Due to our plants being located in or near the Midwestern portion of the U.S., we believe that we have ample access to various corn markets and suppliers.  Although corn can be obtained from multiple sources, and while historically we have not suffered any significant limitations on our ability to procure corn, any delay or disruption in our suppliers’ ability to provide us with the necessary corn requirements may significantly affect our business operations and have a negative effect on our operating results or financial condition.  At any given time, we may have up to 1.0 million bushels (or a 4 to 5 day supply) of corn stored on-site at our production facilities.

 

The key elements of our corn procurement strategies are the assurance of a stable supply and the avoidance, where possible, of significant exposures to corn price fluctuations.  Corn prices fluctuate daily, typically using the Chicago Board of Trade price as a benchmark.  Corn is delivered to our facilities via truck through local distribution networks and by rail.

 

Patents and Trademarks

 

We own several patents, patent rights and trademarks within the U.S.  We do not consider the success of our business, as a whole, to be dependent on these patents, patent rights or trademarks.

 

Environmental and Regulatory Matters

 

We are subject to extensive federal, state and local environmental laws, regulations and permit conditions (and interpretations thereof), including those relating to the discharge of materials into the air,

 

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water and ground, the generation, storage, handling, use, transportation and disposal of hazardous materials, and the health and safety of our employees.  These laws, regulations, and permits require us to incur significant capital and other costs, including costs to obtain and maintain expensive pollution control equipment.  These regulations may also require us to make operational changes to limit actual or potential impacts to the environment.  A violation of these laws, regulations or permit conditions can result in substantial fines, natural resource damages, criminal sanctions, permit revocations and/or facility shutdowns.  In addition, environmental laws and regulations (and interpretations thereof) change over time, and any such changes, more vigorous enforcement policies or the discovery of currently unknown conditions may require substantial additional environmental expenditures.

 

We are also subject to potential liability for the investigation and cleanup of environmental contamination at each of the properties that we own or operate and at off-site locations where we arranged for the disposal of hazardous wastes.  For instance, soil and groundwater contamination has been identified in the past at our Illinois campus.  If any of these sites are subject to investigation and/or remediation requirements, we may be responsible under the Comprehensive Environmental Response, Compensation and Liability Act or other environmental laws for all or part of the costs of such investigation and/or remediation, and for damages to natural resources.  We may also be subject to related claims by private parties alleging property damage or personal injury due to exposure to hazardous or other materials at or from such properties.  While costs to address contamination or related third-party claims could be significant, based upon currently available information, we are not aware of any material liability relating to contamination or such third party claims.  We have not accrued any amounts for environmental matters as of December 31, 2009.  The ultimate costs of any liabilities that may be identified or the discovery of additional contaminants could adversely impact our results of operation or financial condition.

 

In addition, the hazards and risks associated with producing and transporting our products (such as fires, natural disasters, explosions, abnormal pressures and spills) may result in releases of hazardous substances, and may result in claims from governmental authorities or third parties relating to actual or alleged personal injury, property damage, or damages to natural resources.  We maintain insurance coverage against some, but not all, potential losses caused by our operations. Our coverage includes, but is not limited to, physical damage to assets, employer’s liability, comprehensive general liability, automobile liability and workers’ compensation.  We do not carry environmental insurance.  We believe that our insurance is adequate for our industry, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage.  The occurrence of events which result in significant personal injury or damage to our property, natural resources or third parties that is not covered by insurance could have a material adverse impact on our results of operations and financial condition.

 

Our air emissions are subject to the federal Clean Air Act, as amended, and similar state laws which generally require us to obtain and maintain air emission permits for our ongoing operations as well as for any expansion of existing facilities or any new facilities.  Obtaining and maintaining those permits requires us to incur costs, and any future more stringent standards may result in increased costs and may limit or interfere with our operating flexibility.  In addition, the permits ultimately issued may impose conditions which are more costly to implement than we had anticipated.  These costs could have a material adverse effect on our financial condition and results of operations.  Because other ethanol manufacturers in the U.S. are and will continue to be subject to similar laws and restrictions, we do not currently believe that our costs to comply with current or future environmental laws and regulations will adversely affect our competitive position among domestic producers.  However, because ethanol is produced and traded internationally, these costs could adversely affect us in our efforts to compete with foreign producers not subject to such stringent requirements.

 

Federal and state environmental authorities have been investigating alleged excess volatile organic compounds (“VOCS”) emissions and other air emissions from many U.S. ethanol plants, including our

 

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Illinois facilities.  The investigation relating to our Illinois wet mill facility is still pending, and we could be required to install additional air pollution control equipment or take other measures to control air pollutant emissions at that facility.  If authorities require us to install controls, we would anticipate that costs would be higher than the approximately $3.4 million we incurred in connection with a similar investigation at our Nebraska facility due to the larger size of the Illinois wet mill facility.  In addition, if the authorities determine our emissions were in violation of applicable law, we would likely be required to pay fines that could be material.

 

We have made, and expect to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits, including compliance with the U.S. Environmental Protection Agency’s (“EPA”) National Emissions Standard for Hazardous Air Pollutants, or NESHAP, for industrial, commercial and institutional boilers and process heaters, which was issued but subsequently vacated.  The vacated version of the rule required us to implement maximum achievable control technology at our Illinois wet mill facility to reduce hazardous air pollutant emissions from our boilers.  We expect the EPA will revise the rule to impose more stringent requirements than were contained in the vacated version.  In the absence of a final EPA NESHAP for industrial, commercial and institutional boilers and process heaters, we are waiting for state authorities to determine what technology will be required at our Illinois wet mill facility and when such technology must be installed.  We currently cannot estimate the amount that will be needed to comply with any future federal or state technology requirement regarding air emissions from our boilers.

 

We currently generate revenue from the sale of carbon dioxide, which is a co-product of the ethanol production process at each of our Illinois and Nebraska facilities.  New laws or regulations relating to the production, disposal or emissions of carbon dioxide may require us to incur significant additional costs and may also adversely affect our ability to continue generating revenue from carbon dioxide sales.

 

For more information about our environmental compliance and actual and potential environmental liabilities, see “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Uses of Liquidity — Capital Expenditures,” “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental Matters” and “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Subsequent Events.”

 

Employees

 

At December 31, 2009, we had a total of 302 full-time equivalent employees, compared to 346 as of December 31, 2008.  On March 13, 2009, we instituted a reduction in force of 26 employees, primarily as a result of the termination of our marketing alliance.  Approximately 55% of our current full-time employees (comprised of the hourly employees at our Illinois facilities) are represented by a union.  The unionized employees are covered by a collective bargaining agreement between our subsidiary, Aventine Renewable Energy, Inc. and the United Steelworkers International Union, Local 7-662 (the “Union”).  Our contract with the Union was scheduled to expire in October 2009.  Prior to the expiration of the collective bargaining agreement, the Company and the Union agreed to extend the term of the current collective bargaining agreement by one year through and including October 31, 2010 on the same terms and conditions, subject to an option to reopen negotiations upon mutual consent after the effective date of a confirmed Chapter 11 plan of reorganization.  There can be no assurances that we will be able to timely and successfully negotiate a new labor contract whose terms allow us to operate our business in today’s difficult operating environment.  If we are unable to timely and successfully negotiate a new labor contract, our business may be disrupted and our results of operations and financial condition may be negatively affected.

 

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Item 1A.  Risk Factors

 

The Company filed for reorganization under Chapter 11 on April 7, 2009 and is subject to the risks and uncertainties associated with the Bankruptcy Cases.

 

For the duration of the Bankruptcy Cases, our operations and our ability to execute our business strategy will be subject to the risks and uncertainties associated with bankruptcy. These risks include:

 

·                  our ability to continue as a going concern;

·                  our ability to operate within the restrictions and the liquidity limitations of our DIP Facility approved by the Bankruptcy Court in connection with the Bankruptcy Cases;

·                  our ability to obtain Bankruptcy Court approval with respect to motions filed in the Bankruptcy Cases from time to time;

·                  our ability to develop, confirm and consummate a plan of reorganization with respect to the Chapter 11 proceedings;

·                  the ability of third parties to seek and obtain court approval to terminate or shorten the exclusivity period for us to propose and confirm a plan of reorganization or to convert the Bankruptcy Cases to Chapter 7 cases;

·                  our ability to maintain contracts that are critical to our operations;

·                  our ability to obtain and maintain normal payment and other terms with customers, vendors and service providers;

·                  our ability to attract, motivate and retain key employees;

·                  our ability to attract and retain customers; and

·                  our ability to fund and execute our Plan of Reorganization.

 

We may not be able to obtain confirmation of our Chapter 11  plan of reorganization, and our emergence from Chapter 11 proceedings is not assured.

 

The Plan was filed with the Bankruptcy Court on January 13, 2010.  In order to successfully emerge from Chapter 11 bankruptcy protection, we must obtain requisite court and creditor approval of, the Plan.  This process required us to meet statutory requirements with respect to adequacy of the Disclosure Statement, which was approved by the Bankruptcy Court on January 13, 2010, soliciting and obtaining creditor acceptance of a plan, and fulfilling other statutory conditions for plan confirmation.  We may not receive the requisite acceptances to confirm a plan.  Even if the requisite acceptances of a plan are received, the Bankruptcy Court may not confirm it.  For more information regarding the impact of the Plan on existing equity and issuance of new equity see “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations — Proposed Plan of Reorganization.”

 

If a plan of reorganization is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if any, distributions holders of claims against us would ultimately receive with respect to their claims.

 

If a reorganization cannot be agreed upon, it is possible that we would have to liquidate our assets, in which case it is likely that holders of claims would receive substantially less favorable treatment than they would receive if we were to emerge as a viable, reorganized entity.  While we expect to emerge from Chapter 11 proceedings in the future, there can be no assurance as to whether we will successfully reorganize and emerge from Chapter 11 proceedings or, if we do successfully reorganize, as to when we would emerge from Chapter 11 proceedings.

 

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We will also be subject to risks and uncertainties with respect to the actions and decisions of our creditors and other third parties who have interests in the Bankruptcy Cases that may be inconsistent with our plans.

 

These risks and uncertainties could affect our business and operations in various ways.  For example, negative events or publicity associated with the Bankruptcy Cases could adversely affect our relationships with our vendors and employees, as well as with customers, which in turn could adversely affect our operations and financial condition.  Also, pursuant to the Bankruptcy Code, we need Bankruptcy Court approval for transactions outside the ordinary course of business, which may limit our ability to respond timely to events or take advantage of opportunities.  Because of the risks and uncertainties associated with the Bankruptcy Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 reorganization process may have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern.

 

As a result of the Bankruptcy Cases, realization of assets and liquidation of liabilities are subject to uncertainty.

 

While operating under the protection of the Bankruptcy Code, and subject to Bankruptcy Court approval or otherwise as permitted in the normal course of business, we may sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in our consolidated financial statements.  Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

 

A long period of operating under Chapter 11 could harm our business.

 

A long period of operating under Chapter 11 could adversely affect our business and operations.  So long as the Bankruptcy Cases continue, our senior management will be required to spend a significant amount of time and effort dealing with the Bankruptcy Cases instead of focusing exclusively on business operations.  A prolonged period of operating under Chapter 11 may also make it more difficult to attract and retain management and other key personnel necessary to the success and growth of our business.  In addition, the longer the Bankruptcy Cases continue, the more likely it is that our vendors will lose confidence in our ability to successfully reorganize our business, and they may seek to establish alternative arrangements for providing us with goods and services, including alternative payment arrangements, which in turn could have an adverse effect on our liquidity and/or results of operations.

 

Our having sought bankruptcy protection may also adversely affect our ability to negotiate favorable terms from suppliers, landlords, contract or trading counterparties and others and to attract and retain customers and counterparties.  The failure to obtain such favorable terms and to attract and retain customers and other contract or trading counterparties could adversely affect our financial performance.

 

We have substantial liquidity needs and may be required to seek additional financing.

 

Our principal sources of liquidity are cash and cash equivalents on hand, cash provided by operations, and cash provided by our DIP Facility.  Our liquidity position is significantly influenced by our operating results, which in turn are substantially dependent on commodity prices, especially prices for corn,

 

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ethanol, natural gas and unleaded gasoline.  As a result, adverse commodity price movements adversely impact our liquidity.

 

We face uncertainty regarding the adequacy of our liquidity and capital resources and have limited access to additional financing.  In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with the Bankruptcy Cases and expect that we will continue to incur significant professional fees and costs.  We cannot assure you that the amounts of cash available from operations, together with our DIP Facility, will be sufficient to fund our operations, including operations during the period until such time as a plan of reorganization receives the requisite acceptance by creditors and is confirmed by the Bankruptcy Court.

 

Our liquidity and our ability to continue as a going concern, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to comply with the terms and conditions of our DIP Facility; (ii) our ability to maintain adequate cash on hand; (iii) our ability to generate cash from operations; (iv) our ability to obtain confirmation of and to consummate a plan of reorganization under the Bankruptcy Code; (v) the cost and outcome of the reorganization process; and (vi) our ability to achieve profitability.  Our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control.  Accordingly, there can be no assurance as to the success of our efforts.  In the event that cash flows and borrowings under our DIP Facility are not sufficient to meet our cash requirements, we may be required to seek additional financing.  We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms.  Our access to additional financing is, and for the foreseeable future will likely continue to be, very limited.  Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time and ultimately cannot be determined until a plan of reorganization has been confirmed by the Bankruptcy Court.

 

The proposed Plan of Reorganization contemplates that, on the Effective Date, we will complete a $105 million offering of 13% senior secured notes due 2015 (the “Senior Secured Notes Offering”) the proceeds of which will, in part, be used to repay the DIP Facility in full.  In addition, the proposed Plan of Reorganization provides that, on or as soon as practicable after the Effective Date, we will close on a new credit facility with availability of up to $20 million (the “ABL Credit Facility”).  We cannot assure you that we will be able to obtain confirmation of the proposed Plan of Reorganization or effect the transactions contemplated thereby.  Even if we are able to obtain confirmation of the proposed Plan of Reorganization and effect the transactions contemplated thereby, we cannot assure you that the amounts of cash available from operations, together with the proceeds of the Senior Secured Notes Offering and/or the ABL Credit Facility will be sufficient to fund our operations.

 

We may be unable to secure additional financing.

 

Our ability to arrange, in addition to our DIP Facility, financing (including any extension or refinancing) and the cost of additional financing are dependent upon numerous factors.  Access to capital (including any extension or refinancing) for participants in the biofuels industry, including us, has been significantly restricted for the last several months and may, as a result of the Bankruptcy Filing, be further restricted in the future. Other factors affecting our access to financing include:

 

·                  general economic and capital market conditions;

·                  conditions in biofuels markets;

·                  regulatory developments;

 

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·                  credit availability from banks or other lenders for us and our industry peers, as well as the economy in general;

·                  investor confidence in the biofuels industry and in us;

·                  the continued reliable operation of our ethanol production facilities; and

·                  provisions of tax and securities laws that are conducive to raising capital.

 

Although certain lenders have agreed to backstop/assure complete subscription to the Senior Secured Notes Offering in accordance with the terms of the backstop commitment agreement filed with the Plan (the “Backstop Commitment Agreement”), there can be no assurance that we will be able to satisfy the conditions set forth in the Backstop Commitment Agreement and effect the transactions contemplated thereby.

 

We may not have sufficient cash to service our indebtedness and other liquidity requirements.

 

Our ability to service our DIP Facility indebtedness and successfully consummate a plan of reorganization will depend, in part, on our ability to generate cash.  We cannot be certain that cash on hand together with cash from operations will by itself be sufficient to meet our cash and liquidity needs.  If we are unable to generate enough cash to meet our liquidity needs, we could be forced to discontinue some or all of our operations.

 

Our DIP Facility imposes operating and financial restrictions on us, compliance or non-compliance with which could have a material adverse effect on our liquidity and operations.

 

Restrictions imposed by the terms of our DIP Facility could adversely affect us by limiting our ability to plan for or react to market conditions or to meet our capital needs and could result in an event of default under the DIP Facility.  These restrictions limit our ability, subject to certain exceptions, to, among other things:

 

·                  incur additional indebtedness and issue stock;

·                  make prepayments on or purchase indebtedness in whole or in part;

·                  pay dividends and other distributions with respect to our capital stock or repurchase our capital stock or make other restricted payments;

·                  make investments;

·                  enter into transactions with affiliates on other than arm’s-length terms;

·                  create or incur liens to secure debt;

·                  consolidate or merge with another entity, or allow one of our subsidiaries to do so;

·                  lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;

·                  incur dividend or other payment restrictions affecting subsidiaries;

·                  make capital expenditures beyond specified limits;

·                  engage in specified business activities; and

·                  acquire facilities or other businesses.

 

These limitations could have a material adverse effect on our liquidity and operations.  If we fail to comply with the restrictions under our DIP Facility and are unable to obtain a waiver or amendment or a default exists and is continuing under the DIP Facility, the lenders could declare outstanding borrowings and other obligations under the DIP Facility immediately due and payable.  Our ability to comply with these restrictions may be affected by events beyond our control, and any material deviations from our forecasts could require us to seek waivers or amendments of covenants or alternative sources of financing or to

 

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reduce expenditures.  We cannot assure you that such waivers, amendments or alternative financing could be obtained, or if obtained, would be on terms acceptable to us.  If we are unable to comply with the terms of the DIP Facility, or if we fail to generate sufficient cash flow from operations, or, if it became necessary, to obtain such waivers, amendments or alternative financing, it could adversely impact the timing of, and our ultimate ability to successfully implement, a plan of reorganization.

 

The prices of our debt and equity securities are volatile, and, in connection with our reorganization, holders of our securities may receive no payment or payment that is less than the face value or purchase price of such securities.

 

Prior to the Bankruptcy Filing, the market price for our common stock was volatile and, following our Bankruptcy Filing, the price of our common stock has generally been less than $0.50 per share.  In addition, our common stock was delisted from the New York Stock Exchange prior to the Bankruptcy Filing and currently trades on the over-the-counter market.  Accordingly, trading in our common stock may be limited, and holders of such securities may not be able to resell their securities for their purchase price or at all.  We can make no assurance that the price of our common stock will not fluctuate substantially in the future.

 

It is possible that, in connection with our reorganization, all of the outstanding shares of common stock could be cancelled, and holders of our common stock may not be entitled to any payment in respect of their shares.  In addition, new shares of our common stock may be issued.  It is also possible that our obligations to holders of debt may be satisfied by payments to such holders that are less than both the par value of such securities and the price at which holders purchased such securities, or that shares of our common stock may be issued to certain of such holders in satisfaction of their claims.  The value of any common stock so issued may be less than the par value or purchase price of such holders’ securities, and the price of any such common shares may be volatile.

 

Accordingly, trading in our securities during the pendency of the Bankruptcy Cases is highly speculative and poses substantial risks to purchasers of such securities, as holders may not be able to resell such securities or, in connection with our reorganization, may receive no payment, or a payment or other consideration that is less than the par value or the purchase price of such securities.

 

For information regarding the treatment of holders of our securities under the proposed Plan of Reorganization see “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Proposed Plan of Reorganization.”

 

We may be subject to claims that will not be discharged in the Bankruptcy Cases, which could have a material adverse effect on our results of operations and profitability.

 

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation and specified debts arising afterwards.  With few exceptions, all claims that arose prior to the Petition Date and before confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization or (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization.  Any claims not ultimately discharged by the Bankruptcy Court could have an adverse effect on our results of operations and profitability.

 

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Bankruptcy laws may limit our secured creditors’ ability to realize value from their collateral.

 

Upon the commencement of a case for relief under Chapter 11, a secured creditor is prohibited from repossessing its security from a debtor in a Chapter 11 case, or from disposing of security repossessed from such debtor, without bankruptcy court approval.  Moreover, the Bankruptcy Code generally permits the debtor to continue to retain and use collateral even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given “adequate protection.”  The meaning of the term “adequate protection” may vary according to circumstance, but it is intended in general to protect the value of the secured creditor’s interest in the collateral and may include cash payments or the granting of additional security if and at such times as the Bankruptcy Court in its discretion determines that the value of the secured creditor’s interest in the collateral is declining during the pendency of the Chapter 11 proceedings.  The Bankruptcy Court may determine that a secured creditor may not require compensation for a diminution in the value of its collateral if the value of the collateral exceeds the debt it secures.

 

In view of the lack of a precise definition of the term “adequate protection” and the broad discretionary power of the Bankruptcy Court, we cannot reliably predict:

 

·                  how long payments under our secured debt could be delayed as a result of the Chapter 11 proceedings;

·                  whether or when secured creditors (or their applicable agents) could repossess or dispose of collateral;

·                  the value of the collateral; or

·                  whether or to what extent secured creditors would be compensated for any delay in payment or loss of value of the collateral through the requirement of “adequate protection.”

 

Furthermore, if the Bankruptcy Court determines that the value of the collateral is not sufficient to repay all amounts due on applicable secured indebtedness, the holders of such indebtedness would hold a secured claim only to the extent of the value of their collateral and would otherwise hold unsecured claims with respect to any shortfall.  The Bankruptcy Code generally permits the payment and accrual of post-petition interest, costs and attorneys’ fees to a secured creditor during a debtor’s Chapter 11 proceedings only to the extent the value of its collateral is determined by the Bankruptcy Court to exceed the aggregate outstanding principal amount of the obligations secured by the collateral.

 

Our financial results may be volatile and may not reflect historical trends.

 

While in bankruptcy, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities, contract terminations and rejections, and claims assessments may significantly impact our consolidated financial statements.  As a result, our historical financial performance is likely not indicative of our financial performance after the date of the Bankruptcy Filing.  In addition, if we emerge from bankruptcy, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization.  In addition, if we emerge from bankruptcy, we may be required to adopt fresh start accounting.  If fresh start accounting is applicable, our assets and liabilities will be recorded at fair value as of the fresh start reporting date.  The fair value of our assets and liabilities may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets.  In addition, if fresh start accounting is required, our financial results after the application of fresh start accounting may be different from historical trends.

 

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Conducting a successful Chapter 11 reorganization will depend significantly on our ability to retain and motivate management and key employees.

 

Our success depends significantly on the skills, experience and efforts of our personnel.  We do not maintain “key person” life insurance for any of our officers.  The loss of any of our officers could have a material adverse effect upon our results of operations and our financial position and could delay or prevent the achievement of our business objectives.  Our ability to develop and successfully consummate a plan of reorganization will be highly dependent upon the skills, experience and effort of our senior leadership and other personnel.  Our ability to attract, motivate and retain key employees is restricted, however, by provisions of the Bankruptcy Code, which limit or prevent our ability to implement a retention program or take other measures intended to motivate key employees to remain with the Company during the pendency of the Chapter 11 proceedings.  In addition, we may be required to obtain Bankruptcy Court approval of employment contracts and other employee compensation programs.  The loss of the services of one or more members of our senior leadership or certain employees with critical skills, or a diminution in our ability to attract talented, committed individuals to fill vacant positions when needs arise, could have a material adverse effect on our ability to successfully reorganize and emerge from bankruptcy.

 

To help insure that certain members of the senior leadership and management team are and remain properly motivated to undertake the substantial efforts that will be required of them to complete the necessary negotiations with various creditor constituencies in order to emerge from Chapter 11, the Debtors have adopted the Aventine Renewable Energy, Inc. and Affiliates Key Executive Incentive Plan (the “KEIP”), which was approved by the Bankruptcy Court through an order dated December 15, 2009.

 

The KEIP is designed to provide certain senior executives and managers of the Debtors (collectively, the “Eligible Employees”) with appropriate incentives in order to maximize their efforts to aid in the negotiation, formulation, and consummation of the Chapter 11 plan, and to motivate the Eligible Employees to continue effectively managing the Debtors’ operations and minimize expenditures during the Chapter 11 plan process.

 

The KEIP is limited to eight employees.  Pursuant to the KEIP, each of the eligible employees may be entitled to an incentive bonus payment if the Debtors meet or exceed certain specified targets, comprised of cash position, production level, and emergence date.  However, we can provide no assurance that the amounts of the bonuses provided in the KEIP will be adequate to assure the retention of key employees.

 

Transfers of our equity, or issuances of equity in connection with our restructuring or otherwise, may impair our ability to utilize our federal income tax net operating loss carryforwards in the future.

 

Section 382 of the Internal Revenue Code limits the ability of a company that undergoes an ownership change, which is generally any change in ownership of more than 50% of its stock over a three-year period, to utilize its net operating loss carryforwards and certain built-in losses (generally, the excess of the tax basis in an asset over its fair market value) following the ownership change. These rules generally operate by focusing on ownership changes among stockholders owning directly or indirectly 5% or more of the stock of a company and any change in ownership arising from a new issuance of stock by the company.  While we do not believe that we have to date experienced an ownership change under Section 382, we believe we will experience an ownership change in the future as a result of changes in the ownership of our stock or future issuances of our stock, coincident with the confirmation of the Plan of Reorganization in our current Chapter 11 bankruptcy proceedings.

 

We have net operating loss carryforwards of approximately $1.5 million as of December 31, 2009.  If we undergo an ownership change for purposes of Section 382, our ability to recognize our built-in losses

 

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(including in the form of depreciation deductions on our assets) during the five-year period after the date of any ownership change would be subject to the limitations of Section 382.  Depending on the resulting limitation, our ability to use a significant portion of our future depreciation deductions could be limited, which could have the effect of creating or increasing our tax liabilities in years after such an ownership change, and have a negative impact on our financial position and results of operations.  During the pendency of the bankruptcy proceedings, the Bankruptcy Court has entered an interim order that places limitations on trading in our common stock, including options to acquire common stock, as further specified in the order.  However, we can provide no assurances that these limitations will prevent an “ownership change” or that our ability to utilize our net operating loss carryforwards may not be significantly limited as a result of our reorganization.

 

We are contractually obligated to complete certain capacity expansions in Aurora, Nebraska and Mount Vernon, Indiana.  If we fail to complete them in a timely manner, we may be subject to material penalties.

 

We are contractually obligated to develop both a 110 million gallon plant adjacent to our Nebraska facility and a two-phase 220 million gallon facility in Mount Vernon, Indiana and may incur significant penalties because of our failure to complete one or more of these facilities as previously scheduled, absent amendment of those obligations.

 

We may be subject to material penalties if we do not timely complete the Aurora West facility or the initial “Phase I” plant of the Mt. Vernon expansion.  The failure to complete the Aurora West plant by July 1, 2009 subjected the Company to contractual liquidated damages of $138,889 per month (up to a maximum of $5 million) until the plant is operational.  We suspended construction at Aurora West and did not complete it by July 1, 2009.  Accordingly, we may be required to pay some portion of the stipulated liquidated damages.  If we are unable to or otherwise do not pay these damages, the counterparty may have the right to repurchase the property at cost (subject to adjustment for any expenses which we have paid with respect to the infrastructure construction).  We recently amended our lease with the Indiana Ports Commission to provide additional flexibility as to the timing of Phase I and the Phase II expansion at Mt. Vernon.  This lease, as amended, requires our Mt. Vernon subsidiary to substantially complete Phase I (an initial 110 million gallons of capacity) by December 31, 2010 and to construct Phase II (an additional 110 million gallons of capacity) before constructing a new facility elsewhere.  If we are in default of these obligations, the Ports may, subject to specified cure rights, take over construction and complete the facility at our expense (among other remedies).  We suspended construction of Phase I at Mt. Vernon and have not commenced construction of Phase II.  The Plan contemplates the construction of Phase I at Mt. Vernon in 2010 and the assumption of the lease with the Ports, as amended, as well as assumption of the Master Development Agreement for the Aurora West facility, as amended, and the cure of amounts owing under that arrangement.

 

On March 9, 2009, we received a notice from our Engineering, Procurement and Construction (“EPC”) contractor, Kiewit Energy, cancelling the EPC contracts for Aurora West and Mt. Vernon, referencing our failure to make a required  payment.  Accordingly, we no longer have EPC contracts for the completion of Aurora West or Mt. Vernon.  Nevertheless, we are in the process of negotiating a new EPC contract with Kiewit to resume construction and, as referenced above, have made plans for the completion of one or more of the above plants.  However, there can be no certainty that such construction will be completed when or as planned, or at all.

 

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Restrictive covenants in the indenture governing the secured notes and the exit credit facility contemplated by the proposed Plan of Reorganization may adversely affect our business activities and operations.

 

The indenture governing the secured notes and the exit credit facility contemplated by the proposed Plan of Reorganization will contain various covenants that may adversely affect our ability to, among other things, incur additional indebtedness, incur liens, pay dividends or make certain restricted payments, consummate certain asset sales, merge, consolidate and/or sell or dispose of all or substantially all of our assets. In addition, the indenture governing the secured notes and the exit credit facility may require us and certain of our subsidiaries to maintain certain financial ratios and meet certain tests, including leverage and interest coverage ratios. Such covenants will also require us to use a portion of our cash flow and the proceeds we receive from certain asset sales and specified debt or equity issuances and upon the occurrence of other events to repay outstanding principal of the notes or borrowings under the exit credit facility.  These covenants may have important consequences on our operations, including, without limitation, restricting their ability to obtain additional financing and potentially limiting their ability to adjust to rapidly changing market conditions.

 

If the expected increase in ethanol demand does not occur, or if the demand for ethanol otherwise decreases, the excess capacity in our industry may increase further.

 

Domestic ethanol capacity has increased significantly from 1.3 billion gallons per year in 1997 to 12.5 billion gallons per year at the end of 2008.  According to the RFA, as of January 25, 2010, approximately 1.4 billion gallons per year of production capacity is currently under construction.  Through November 2009, U.S. ethanol demand exceeded U.S. ethanol production by 139 million gallons.  Demand for ethanol increased by 12% over 2008 through increased penetration into new markets, and a government mandate but, the production capacity of U.S. ethanol producers continues to exceed demand.  At the end of 2009, there was approximately 1.2 billion gallons of production capacity shut-in.  If additional demand for ethanol is not created, either through discretionary blending or an increase in the blending percentage allowed by the EPA, the excess supply may cause additional plants to shutter production or cause ethanol prices to decrease further, perhaps substantially.

 

We operate in a highly competitive industry with low barriers to entry.

 

In the U.S., we compete with other corn processors and refiners, including Archer-Daniels-Midland Company, Green Plains Renewable Energy, Valero, Biofuels Energy Corporation, Hawkeye Holdings, Inc., Pacific Ethanol, Cargill, Inc. and A.E. Staley Manufacturing Company, a subsidiary of Tate & Lyle, PLC.  Some of our competitors are divisions of larger enterprises and have greater financial resources than we do.  Although many of our competitors are larger than we are, we also have smaller competitors.  Farm cooperatives comprised of groups of individual farmers have been able to compete successfully.  As of December 2009, the top ten domestic producers accounted for approximately 47.9% of all production.  If our competitors consolidate or otherwise grow and/or we are unable to similarly increase our size and scope, our business and prospects may be significantly and adversely affected.

 

We also face increasing competition from international suppliers.  Although there is a tariff on foreign produced ethanol that is slightly larger than the federal ethanol tax incentive, ethanol imports equivalent to up to 7% of total domestic production from certain countries were exempted from this tariff under the CBI (The Caribbean Basin Initiative) to spur economic development in Central America and the Caribbean.

 

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Our competitors also include plants owned by farmers who earn their livelihood through the sale of corn, and hence may not be as focused on obtaining optimal value for their produced ethanol as we are.

 

Our business is dependent upon the availability and price of corn.  Significant disruptions in the supply of corn will materially affect our operating results.  In addition, since we generally cannot pass on increases in corn prices to our customers, continued periods of historically high corn prices will also materially adversely affect our operating results.

 

The principal raw material we use to produce ethanol and ethanol by-products is corn.  In 2009, we purchased approximately 74.2 million bushels of corn at a cost of $287.1 million, which comprised about 72% of our total cost of production.  In 2009, our average corn cost ranged from a low of $3.31 per bushel in September 2009 to a high of $4.48 per bushel in January 2009.  Corn prices began to rise significantly beginning in September 2006.  We believe a systemic shift has occurred in the marketplace for corn, and the price of corn will remain significantly higher than the historical averages.  The increase in U.S. ethanol capacity under construction could outpace increases in corn production, which may further increase corn prices and impact our profitability.

 

Changes in the price of corn have had an impact on our business.  In general, higher corn prices produce lower profit margins and, therefore, represent unfavorable market conditions.  This is especially true when market conditions do not allow us to pass along increased corn costs to our customers.  At certain levels, corn prices may make ethanol uneconomical to use in markets and volumes above the requirements set forth in the renewable fuels standard or for which ethanol is used as an oxygenate in order to meet federal and state fuel emission standards.

 

The price of corn is influenced by general economic, market and regulatory factors.  These factors include weather conditions, farmer planting decisions, government policies and subsidies with respect to agriculture and international trade and global demand and supply.  The significance and relative impact of these factors on the price of corn is difficult to predict.  Factors such as severe weather or crop disease could have an adverse impact on our business because we may be unable to pass on higher corn costs to our customers.  Any event that tends to negatively impact the supply of corn will tend to increase prices and potentially harm our business.  The increasing ethanol capacity could boost demand for corn and result in increased prices for corn.  We expect the price of corn to continue to remain at levels that would be considered as high when compared to historical periods.

 

In an attempt to partially offset the effects of fluctuations in corn costs on operating income, we have taken hedging positions in the corn futures markets in the past.  However, these hedging transactions also involve risk to our business.  See “Item 1A —Risk Factors — We may engage in hedging or derivative transactions which involve risks that can harm our business.”

 

Growth in the sale and distribution of ethanol is dependent on the changes in and expansion of related infrastructure, which may not occur on a timely basis, if at all, and our operations could be adversely affected by infrastructure disruptions.

 

Substantial development of infrastructure by persons and entities outside our control are required for our operations and the ethanol industry generally, to grow.  Areas requiring expansion include, but are not limited to, additional rail capacity, additional storage facilities for ethanol, increases in truck fleets capable of transporting ethanol within localized markets, expansion of refining and blending facilities to handle ethanol, growth in service stations equipped to handle ethanol fuels, and growth in the fleet of flexible fuel vehicles capable of using E85 fuel.  Substantial investments required for these infrastructure

 

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changes and expansions may not be made or they may not be made on a timely basis.  Any delay or failure in making the changes in or expansion of infrastructure could hurt the demand or prices for our products, impede our delivery of products, impose additional costs on us or otherwise have a material adverse effect on our business, results of operations or financial condition.  Our business is dependent on the continuing availability of infrastructure and any infrastructure disruptions could have a material adverse effect on our business, results of operations and financial condition.

 

Fluctuations in the demand for gasoline may reduce demand for ethanol.

 

Ethanol is marketed as an oxygenate to reduce vehicle emissions from gasoline, as an octane enhancer to improve the octane rating of gasoline with which it is blended and as a fuel extender.  As a result, ethanol demand has historically been influenced by the supply of and demand for gasoline.  If gasoline demand decreases, our ability to sell our product and our results of operations and financial condition may be materially adversely affected.

 

The use and demand for ethanol and its supply are highly dependent on various federal and state legislation and regulation, and any changes in legislation or regulation could cause the demand for ethanol to decline or its supply to increase, which could have a material adverse effect on our business, results of operations and financial condition.

 

Various federal and state laws, regulations and programs have led to increased use of ethanol in fuel.  For example, certain laws, regulations and programs provide economic incentives to ethanol producers and users.  Among these regulations are (1) the renewable fuels standard, which requires an increasing amount of renewable fuels to be used in the U.S. each year, (2) the VEETC, which provided a tax credit of $0.51 per gallon (prior to January 1, 2009 when it was reduced to $0.45 per gallon) on 10% ethanol blends that is set to expire in 2010, (3) the small ethanol producer tax credit, for which we do not qualify because of the size of our ethanol plants, and (4) the federal “farm bill,” which establishes federal subsidies for agricultural commodities including corn, our primary feedstock.  These laws, regulations and programs are constantly changing.  Federal and state legislators and environmental regulators could adopt or modify laws, regulations or programs that could adversely affect the use of ethanol.  Barring a change in current regulation, requirements for the state of California will make it difficult for ethanol produced from corn in many Midwestern states to be used as a fuel in California beginning in 2011.  In addition, certain state legislatures oppose the use of ethanol because they must ship ethanol in from other corn-producing states, which could significantly increase gasoline prices in the state.

 

If we cannot increase the amount of non-corn based ethanol, cellulosic biofuels or bio-mass based diesel we produce, our business, results of operations and financial condition will be adversely affected.

 

The Energy Independence and Security Act of 2007 established a revised renewable fuels standard, or RFS, for the years 2006 through 2022.  The RFS sets forth the minimum amount of renewable fuels that must be present in U.S. transportation fuels.  The law starts at 9 billion gallons in 2008 and rises to 36 billion gallons by 2022.  For 2015 and all subsequent years, the amount of the renewable fuels mandate that can be satisfied by corn-based ethanol is currently capped at 15 billion gallons.  The remainder of the mandate is required to be obtained from cellulosic ethanol and other advanced biofuels.  If our and our competitors’ facilities cannot accept feedstocks, other than corn, or if we do not begin producing non-corn based ethanol in the future, our business, results of operations and financial condition may be adversely affected.

 

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The Renewable Fuel Standard 2 recently released by the Environmental Protection Agency (EPA) may require us to include alternative technologies in our plants under construction, which may increase the cost to complete the facilities.

 

The EPA’s recently released Renewable Fuel Standard 2 includes the requirements that the lifecycle greenhouse gas (GHG) emissions of a qualifying renewable fuel must be less than the lifecycle GHG emissions of the 2005 baseline average gasoline or diesel fuel that it replaces.  The lifecycle GHG threshold for ethanol is 20%.  Fuels from existing capacity of current facilities and of facilities that commenced construction prior to December 19, 2007 are exempt or grandfathered from the 20% lifecycle requirement.  Plants whose construction commenced prior to December 19, 2007 must be completed within three years in order to be exempt or grandfathered from the 20% lifecycle requirement.  Plants not exempt or grandfathered must include advanced efficient technologies as defined by the regulations in order to meet the Renewable Fuel Standard 2 requirements.  If our Mt. Vernon plant and the Aurora West plant are not completed within the required three years, the plants may not be exempt or grandfathered from the 20% lifecycle requirement and could require additional advanced efficient technologies to be included in the construction, which is likely to require additional capital which may be substantial.

 

Certain countries can import ethanol into the U.S. duty free, which may undermine the ethanol industry in the U.S.

 

Imported ethanol is generally subject to a $0.54 per gallon tariff and a 2.5% ad valorem tax that was designed to offset the $0.45 per gallon ethanol subsidy currently available under the federal excise tax incentive program for refineries and blenders that mix ethanol with their gasoline.  At a certain price level, imported ethanol may become profitable for sale in the U.S. despite the tariff.  This occurred in 2006, due to a spike in the ethanol prices and insufficient supply.  As a result, there may effectively be a ceiling on U.S. ethanol prices.  This, combined with uncertainties surrounding U.S. producers’ ability to meet domestic demand, resulted in significant imports of ethanol, especially from Brazil.  Furthermore, East Coast facilities are better suited to bringing in product by water rather than rail (the preferred path for ethanol from the Midwest).  The combination made it more economic for some buyers to import ethanol with the full import duty than to bring supplies from the Midwest.  Given the increase in ethanol demand as a result of the new RFS and potential transportation bottlenecks delivering material from the Midwest, imports of ethanol could rise.

 

There is a special exemption from the tariff for ethanol imported from 24 countries in Central America and the Caribbean islands which is limited to a total of 7% of U.S. production per year (with additional exemptions for ethanol produced from feedstock in the Caribbean region over the 7% limit).  In addition the NAFTA (The North America Free Trade Agreement which was signed into law January 1, 1994) countries, Canada and Mexico, are exempt from duty. See “Item 1 — Business — Legislative Drivers and Governmental Regulations — The federal ethanol tax incentive program.”  Imports from the exempted countries have increased in recent years and are expected to increase further as a result of new plants under development.

 

We may be adversely affected by environmental, health and safety laws, regulations and liabilities.

 

We are subject to extensive federal, state and local environmental laws, regulations and permit conditions (and interpretations thereof), including those relating to the discharge of materials into the air, water and ground, the generation, storage, handling, use, transportation and disposal of hazardous materials, and the health and safety of our employees.  These laws, regulations, and permits require us to incur

 

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significant capital and other costs, including costs to obtain and maintain expensive pollution control equipment.  They may also require us to make operational changes to limit actual or potential impacts to the environment.  A violation of these laws, regulations or permit conditions can result in substantial fines, natural resource damages, criminal sanctions, permit revocations and/or facility shutdowns.  In addition, environmental laws and regulations (and interpretations thereof) change over time, and any such changes, more vigorous enforcement policies or the discovery of currently unknown conditions may require substantial additional environmental expenditures.

 

We are also subject to potential liability for the investigation and cleanup of environmental contamination at each of the properties that we own or operate and at off-site locations where we arranged for the disposal of hazardous wastes.  For instance, soil and groundwater contamination has been identified in the past at our Illinois campus.  If any of these sites are subject to investigation and/or remediation requirements, we may be responsible under the Comprehensive Environmental Response, Compensation and Liability Act or other environmental laws for all or part of the costs of such investigation and/or remediation, and for damages to natural resources.  We may also be subject to related claims by private parties alleging property damage or personal injury due to exposure to hazardous or other materials at or from such properties.  We have not accrued any amounts for environmental matters as of December 31, 2009.  The ultimate costs of any liabilities that may be identified or the discovery of additional contaminants could adversely impact our results of operation or financial condition.

 

In addition, the hazards and risks associated with producing and transporting our products (such as fires, natural disasters, explosions, abnormal pressures and spills) may result in releases of hazardous substances, and may result in claims from governmental authorities or third parties relating to actual or alleged personal injury, property damage, or damages to natural resources.  We maintain insurance coverage against some, but not all, potential losses caused by our operations. Our coverage includes, but is not limited to, physical damage to assets, employer’s liability, comprehensive general liability, automobile liability and workers’ compensation.  We do not carry environmental insurance.  We believe that our insurance is adequate for our industry, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage.  The occurrence of events which result in significant personal injury or damage to our property, natural resources or third parties that is not covered by insurance could have a material adverse impact on our results of operations and financial condition.

 

Our air emissions are subject to the federal Clean Air Act, as amended, and similar state laws which generally require us to obtain and maintain air emission permits for our ongoing operations as well as for any expansion of existing facilities or any new facilities.  Obtaining and maintaining those permits requires us to incur costs, and any future more stringent standards may result in increased costs and may limit or interfere with our operating flexibility.  In addition, the permits ultimately issued may impose conditions which are more costly to implement than we had anticipated.  These costs could have a material adverse effect on our financial condition and results of operations, and could adversely affect us in our efforts to compete with foreign producers not subject to such stringent requirements.

 

Federal and state environmental authorities have been investigating alleged excess VOCS emissions and other air emissions from many U.S. ethanol plants, including our Illinois facilities.  The investigation relating to our Illinois wet mill facility is still pending, and we could be required to install additional air pollution control equipment or take other measures to control air pollutant emissions at that facility.  If authorities require us to install controls, we would anticipate that costs would be higher than the approximately $3.4 million we incurred in connection with a similar matter at our Nebraska facility due to the larger size of the Illinois wet mill facility.  In addition, if the authorities determine our emissions were in violation of applicable law, we would likely be required to pay fines that could be material.

 

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We have made, and expect to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits, including compliance with the EPA National Emissions Standard for Hazardous Air Pollutants, or NESHAP, for industrial, commercial and institutional boilers and process heaters.  This NESHAP was issued but subsequently vacated.  The vacated version of the rule required us to implement maximum achievable control technology at our Illinois wet mill facility to reduce hazardous air pollutant emissions from our boilers.  We expect the EPA will revise the rule to impose more stringent requirements than were contained in the vacated version.  In the absence of a final EPA NESHAP for industrial, commercial and institutional boilers and process heaters, we are working with state authorities to determine what technology will be required at our Illinois wet mill facility and when such technology must be installed.  We currently cannot estimate the amount that will be needed to comply with any future federal or state technology requirement regarding air emissions from our boilers.

 

We currently generate revenue from the sale of carbon dioxide, which is a co-product of the ethanol production process at each of our Illinois and Nebraska facilities.  New laws or regulations relating to the production, disposal or emissions of carbon dioxide may require us to incur significant additional costs and may also adversely affect our ability to continue generating revenue from carbon dioxide sales.

 

We are substantially dependent on our three facilities and any operational disruption could result in a reduction of our sales volumes and could cause us to incur substantial expenditures.

 

The substantial majority of our net income is derived from the sale of ethanol and the related bio-products and co-products that we produce at our Illinois facilities and our Nebraska facility.  Our operations may be subject to significant interruption if either of the Illinois facilities or Nebraska facility experiences a major accident or is damaged by severe weather or other natural disaster.  In addition, our operations may be subject to labor disruptions and unscheduled downtime, or other hazards inherent in our industry.  Some of those hazards may cause personal injury and loss of life, severe damage to or destruction of property and equipment and environmental damage, and may result in suspension or termination of operations and the imposition of civil or criminal penalties.  As protection against these hazards, we maintain property, business interruption and casualty insurance which we believe is in accordance with customary industry practices, but we cannot provide any assurance that this insurance will be adequate to fully cover the potential hazards described above or that we will be able to renew this insurance on commercially reasonable terms or at all.

 

The market for natural gas is subject to market conditions that create uncertainty in the price and availability of the natural gas that we utilize in our manufacturing process.

 

We rely upon third parties for our supply of natural gas which is consumed in the production of ethanol.  The prices for and availability of natural gas are subject to volatile market conditions.  These market conditions often are affected by factors beyond our control such as weather conditions, overall economic conditions and foreign and domestic governmental regulation and relations.  Significant disruptions in the supply of natural gas could temporarily impair our ability to produce ethanol for our customers.  Further, increases in natural gas prices or changes in our natural gas costs relative to natural gas costs paid by competitors may adversely affect our results of operations and financial condition.  The price fluctuation in natural gas prices over the ten year period from 2000 through December 31, 2009, based on the New York Mercantile Exchange, or NYMEX, daily futures data, has ranged from a low of $1.83 per MMBtu in September 2001 to a high of $15.38 per MMBtu in December 2005.  We currently use approximately 3.4 million MMBtu’s of natural gas annually, depending upon business conditions, in the

 

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manufacture of our products.  Our usage of natural gas will increase with the planned expansion of our production facilities.

 

In an attempt to minimize the effects of fluctuations in natural gas costs on operating income, we have taken hedging positions in the natural gas forward or futures markets in the past; however, these hedging transactions also involve risk to our operations.  Since natural gas prices are volatile and we are not currently taking hedging positions, our results could be adversely affected by an increase in natural gas prices. See “We may engage in hedging or derivative transactions which involve risks that can harm our business.”

 

Changes in ethanol prices can affect the value of our inventory which may significantly affect our profitability.

 

Our distribution system allows us to carry an inventory of ethanol to better serve our customers and to take advantage of opportunities in the marketplace.  Our inventory is valued based upon a weighted average price we pay for ethanol that we purchase from our purchase/resale transactions, along with our own cost to produce ethanol.  In the past, we occasionally increased our inventory, in order to profit when we believed market prices would rise.  Changes, either upward or downward, in our purchased cost of ethanol or our own production costs, will cause the inventory value to fluctuate from period to period, perhaps significantly.  These changes in value flow through our statement of operations as the inventory is sold or its value is deemed to be impaired and can significantly increase or decrease our profitability.

 

We will recognize income from cancellation of indebtedness if our proposed Plan of Reorganization is approved.

 

If the Plan is confirmed, we will recognize income from cancellation of indebtedness (“COD”) when we emerge from bankruptcy to the extent that debt is discharged for consideration to a creditor for an amount that is less than the amount of such debt.  For these purposes consideration includes the amount of cash and the fair market value of property, including stock of the debtor, transferred to the creditor.  The amount of COD income, in general, is the excess of (a) the adjusted issue price of the indebtedness satisfied, over (b) the sum of the amount of cash paid and the fair market value of any new consideration (including the new stock of the Company following emergence from bankruptcy) given in satisfaction of the cancelled debt.  Although the precise amount of COD income that we will realize cannot be determined until the effective date of the Plan, we currently estimate that the amount of COD income we could realize will be approximately $135 million to $175 million for U.S. federal income tax purposes.

 

To the extent of COD income, we will be required to reduce certain of our tax attributes (principally, the tax basis in our assets) in the year following emergence.  Among other things, this would have the effect of reducing our future depreciation deductions.  The American Recovery and Reinvestment Act of 2009 (“ARRA”) provided an exception to the immediate realization of COD income, which would permit us to elect to defer the current recognition of any COD income, and instead recognize any such income ratably over a five-year period beginning in 2014.  We do not currently anticipate that we will make the deferral election for COD income, as described above.

 

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We depend on rail, truck and barge transportation for delivery of corn to us and the distribution of ethanol to our customers.

 

We depend on rail, truck and barge to deliver corn to us and to distribute ethanol to the terminals currently in our network.  Ethanol is not currently distributed by pipeline.  Disruption to the timely supply of these transportation services or increases in the cost of these services for any reason, including the availability or cost of fuel, regulations affecting the industry, or labor stoppages in the transportation industry, could have an adverse effect on our ability to supply corn to our production facilities or to distribute ethanol to our terminals, and could have a material adverse effect on our financial performance.

 

Consumer resistance to the use of ethanol may affect the demand for ethanol, which could affect our ability to market our product.

 

Media reports in the mainstream press indicate that some consumers believe the use of ethanol will have a negative impact on retail gasoline prices or is the reason for increases in food prices.  Many also believe that ethanol adds to air pollution and harms car and truck engines.  Still other consumers believe that the process of producing ethanol actually uses more fossil energy, such as oil and natural gas, than the amount of energy produced by ethanol.  These consumer beliefs could be wide-spread in the future.  If consumers choose not to buy ethanol blended fuels, it would affect the demand for the ethanol we produce which could lower demand for our product and negatively affect our profitability.

 

Various studies have criticized the efficiency of ethanol, which could lead to the reduction or repeal of incentives and tariffs that promote the use and domestic production of ethanol.

 

Although many trade groups, academics and governmental agencies have supported ethanol as a fuel additive that promotes a cleaner environment, others have criticized ethanol production as consuming considerably more energy and emitting more greenhouse gases than other biofuels.  In particular, two February 2008 studies concluded the current production of corn-based ethanol results in more greenhouse gas emissions than conventional fuels if both direct and indirect greenhouse gas emissions, including those resulting from land use changes resulting from planting crops for ethanol feedstocks, are taken into account.  Other studies have suggested that corn-based ethanol is less efficient than ethanol produced from switch grass or wheat grain.  If these views gain acceptance, support for existing measures promoting use and domestic production of corn-based ethanol could decline, leading to reduction or repeal of these measures.

 

We sell ethanol primarily to the major oil companies and traders and therefore we can from time to time be subject to a high degree of concentration of our sales and accounts receivable.

 

We sell ethanol to most of the major integrated oil companies and a significant number of large, independent refiners and petroleum wholesalers.  Our trade receivables result primarily from our ethanol marketing operations.  As a general policy, collateral is not required for receivables, but customers’ financial condition and creditworthiness are evaluated regularly.  Credit risk concentration related to our accounts receivable results from our top 10 customers having generated 54.7% and 47% of our consolidated net sales for the years ended December 31, 2009 and 2008, respectively.

 

In 2009, Biourja Trading accounted for 10.5% and Exxon Mobil accounted for 11.1% of our net sales.  No other customers in 2009 represented more than 10% of our consolidated net sales volume.  No customers in 2008 or 2007 represented more than 10% of our consolidated net sales volume.

 

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If we would suddenly lose a major customer and not be able to replace the demand for our product very quickly it could have a material impact on our sales and profitability.

 

Research is currently underway to develop production of biobutanol, a product that could directly compete with ethanol and may have potential advantages over ethanol.

 

Biobutanol, an advanced biofuel produced from agricultural feedstock, is currently being developed by various parties, including a partnership between BP and DuPont.  According to the partnership, biobutanol has many advantages over ethanol.  The advantages include: low vapor pressure, making it more easily added to gasoline; energy content closer to that of gasoline, such that the decrease in fuel economy caused by the blending of biobutanol with gasoline is less than that of other biofuels when blended with gasoline; it can be blended at higher concentration than other biofuels for use in standard vehicles; it is less susceptible to separation when water is present than in pure ethanol-gasoline blends; and it is expected to be potentially suitable for transportation in gas pipelines, resulting in a possible cost advantage over ethanol producers relying on rail transportation.  Although BP and DuPont have not announced a timeline for producing biobutanol on a large scale, if biobutanol production comes online in the United States, biobutanol could have a competitive advantage over ethanol and could make it more difficult to market our ethanol, which could reduce our ability to generate revenue and profits.

 

We, and some of our major customers, have unionized employees and could be adversely affected by labor disputes.

 

Some of our employees and some employees of our major customers are unionized.  At December 31, 2009, approximately 55% of our employees were unionized.  Our unionized employees are hourly workers located at our Illinois facilities.  The unionized employees are covered by a collective bargaining agreement between our subsidiary, Aventine Renewable Energy, Inc. and the United Steelworkers International Union, Local 7-662.

 

The collective bargaining agreement with the Union was scheduled to expire in October 2009.  Prior to the expiration of the collective bargaining agreement, the Company and the Union agreed to extend the term of the current collective bargaining agreement by one year through and including October 31, 2010 on the same terms and conditions, subject to an option to reopen negotiations upon mutual consent after the effective date of a confirmed Chapter 11 plan of reorganization.  There can be no assurances that we will be able to timely and successfully negotiate a new labor contract with terms that allow us to operate our business in today’s difficult operating environment.  If we are unable to timely and successfully negotiate a new labor contract, our business may be disrupted and our results of operations and financial condition may be negatively affected.

 

We have a significant stockholder whose interests may differ from your interests and who may be able to exert significant influence over corporate decisions of the Company.

 

Through their ownership of Aventine Renewable Energy Holdings LLC, the MSCP funds beneficially own approximately 27.5% of our outstanding common stock.  Metalmark Subadvisor LLC, an affiliate of Metalmark, an independent private equity firm established by former principals of Morgan Stanley Capital Partners, manages certain MSCP funds on a sub-advisory basis.  In January 2008 substantially all of the employees of Metalmark became employees of Citi Alternative Investments Inc., although Metalmark remains an independent entity owned by those individuals and continues to manage

 

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the applicable MSCP funds on a sub-advisory basis. Two of our directors, Messrs. Abramson and Hoffman, are currently employees of both Metalmark and Citigroup.

 

As a result, Metalmark may be deemed to control our management and policies. Metalmark may have an interest in pursuing transactions that, in their judgment, enhance the value of the applicable funds’ equity investment in our Company, even though those transactions may involve risks to you as a stockholder.  In addition, circumstances could arise under which the interests of Metalmark could be in conflict with the interests of our other stockholders.  If we are able to obtain confirmation of the proposed Plan of Reorganization and effect the transactions contemplated thereby, we may have a new significant stockholder or group of significant stockholders.

 

The relationship between the sales price of our co-products and the price we pay for corn can fluctuate significantly which may affect our results of operations and profitability.

 

We sell co-products and bio-products that are remnants of the ethanol production process in order to reduce our costs and increase profitability.  Historically, sales prices for these co-products have tracked along with the price of corn.  However, there have been occasions when the value of these co-products and bio-products has lagged behind increases in corn prices.  As a result, we may occasionally generate less revenue from the sale of these co-products and bio-products relative to the price of corn.  In addition, several of our co-products compete with similar products made from other plant feedstock.  The cost of these other feedstocks may not have risen as corn prices have risen.  Consequently, the price we may receive for these products may not rise as corn prices rise, thereby lowering our cost recovery percentage relative to corn.

 

Our results of operations may be adversely affected by technological advances.

 

The development and implementation of new technologies may result in a significant reduction in the costs of ethanol production.  We cannot predict when new technologies may become available, the rate of acceptance of new technologies by our competitors or the costs associated with such new technologies.  In addition, advances in the development of alternatives to ethanol, or corn ethanol in particular, could significantly reduce demand for or eliminate the need for ethanol, or corn ethanol in particular, as a fuel oxygenate or octane enhancer.

 

Any advances in technology which require significant capital expenditures for us to remain competitive or which otherwise reduce demand for ethanol will have a material adverse effect on our results of operations and financial condition.

 

Risks associated with the operation of our production facilities may have a material adverse effect on our business.

 

Our revenue is dependent on the continued operation of our various production facilities.  The operation of production plants involves many risks including:

 

·                  the breakdown, failure or substandard performance of equipment or processes;

·                  inclement weather and natural disasters;

·                  the need to comply with directives of, and maintain all necessary permits from, governmental agencies;

 

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·                  raw material supply disruptions;

·                  labor force shortages, work stoppages, or other labor difficulties; and

·                  transportation disruptions.

 

The occurrence of material operational problems, including but not limited to the above events, may have an adverse effect on the productivity and profitability of a particular facility, or to us as a whole.

 

If we are unable to attract and retain key personnel, our ability to operate effectively may be impaired.

 

Our ability to operate our business and implement strategies depends, in part, on the efforts of our executive officers and other key employees.  Our management philosophy of cost-control means that we operate with a limited number of corporate personnel, and our commitment to a less centralized organization also places greater emphasis on the strength of local management.  Our future success will depend on, among other factors, our ability to attract and retain qualified personnel, particularly executive management.  The loss of the services of any of our key employees or the failure to attract or retain other qualified personnel, domestically or abroad, could have a material adverse effect on our business or business prospects.

 

We may engage in hedging or derivative transactions which involve risks that can harm our business.

 

In an attempt to minimize the effects of the volatility of the price of corn, natural gas, electricity and ethanol (“commodities”), we may take economic hedging positions in the commodities.  Economic hedging arrangements also expose us to the risk of financial loss in situations where the other party to the hedging contract defaults on its contract or there is a change in the expected differential between the underlying price in the hedging agreement and the actual price of the commodities.  Although we attempt to link our economic hedging activities to sales plans and pricing activities, occasionally such hedging activities can themselves result in losses.  We have not been involved in hedging activities since February 2009.  As a result, our results of operations may be adversely affected during periods in which corn and/or natural gas prices increase.

 

Fixed price and gasoline related contracts for ethanol may be at a price level lower than the prevailing price.

 

At any given time, contract prices for ethanol may be at a price level different from the current prevailing price, and such a difference could materially adversely affect our results of operations and financial condition.  As of December 31, 2009, we had no fixed price or gasoline related sales contracts for ethanol.

 

If our internal computer network and applications suffer disruptions or fail to operate as designed, our operations will be disrupted and our business may be harmed.

 

We rely on network infrastructure and enterprise applications, and internal technology systems for our operational, marketing support and sales, and product development activities.  The hardware and software systems related to such activities are subject to damage from earthquakes, floods, lightning, tornadoes, fire, power loss, telecommunication failures and other similar events.  They are also subject to acts such as computer viruses, physical or electronic vandalism or other similar disruptions that could cause system interruptions and loss of critical data, and could prevent us from fulfilling our customers’ orders.

 

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We have developed disaster recovery plans and backup systems to reduce the potentially adverse effects of such events, but there are no assurances such plans and systems would be sufficient.  Any event that causes failures or interruption in our hardware or software systems could result in disruption of our business operations, have a negative impact on our operating results, and damage our reputation.

 

Item 1B.  Unresolved Staff Comments

 

There are no unresolved comments.

 

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Item 2.  Properties

 

Our corporate headquarters are located in Pekin, Illinois.  Listed below are our production facilities and land acquired for planned expansions/future developments:

 

Current Production Facilities:

 

Location

 

Owned/
Leased

 

Property Size
(acres)

 

Mill
Type

 

Year
Opened

 

Number of
Production
Related
Employees at
Dec. 31, 2009

 

Description

Pekin, IL

 

Owned

 

83

 

Wet

 

1981

 

204

 

Produces fuel-grade ethanol, as well as co-products and bio-products consisting of corn gluten feed, corn gluten meal, condensed corn distillers with solubles (both wet and dry), corn germ, carbon dioxide and Kosher and Chametz free brewers’ yeast.

Pekin, IL

 

Owned

 

11

 

Dry

 

2007

 

17

 

Produces fuel-grade ethanol, as well as co-products consisting of dried distillers grains, wet distillers grains and carbon dioxide.

Aurora, NE

 

Owned

 

30

 

Dry

 

1995

 

32

 

Produces fuel-grade ethanol, as well as co-products consisting of dried distillers grains, wet distillers grains and carbon dioxide.

 

Facilities Where Construction Has Begun But Is Currently Suspended:

 

Location

 

Owned/
Leased

 

Mill Type

 

Property Size
(acres)

 

Description

Aurora, NE

 

Owned

 

Dry

 

86

 

The Company purchased this property for the construction of ethanol production facilities. Construction began but has been suspended.

Mount Vernon, IN

 

Leased (1)

 

Dry

 

116

 

The Company leases the land underlying this property from the State of Indiana.Construction began but has been suspended.

 

Land for Future Expansion:

 

Location

 

Owned/
Leased

 

Property Size (acres)

 

Description

Pekin, IL

 

Owned

 

26

 

The Company holds this property for future development.

 


(1)          The Mount Vernon lease has an initial expiration date of October 31, 2026, with six five-year extension options.

 

We believe that our existing facilities are adequate for our current and reasonably anticipated future needs, except in respect to our planned increases in production.

 

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Item 3.  Legal Proceedings

 

On April 7, 2009, the Company and all of its direct and indirect subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code with the United States Bankruptcy Court for the District of Delaware.  The Company’s subsidiaries that are part of the Bankruptcy Filing include Aventine Renewable Energy, LLC, a Delaware limited liability company; Aventine Renewable Energy, Inc., a Delaware corporation; Aventine Renewable Energy — Mt. Vernon, LLC, a Delaware limited liability company; Aventine Renewable Energy — Aurora West, LLC, a Delaware limited liability company; and Nebraska Energy, LLC, a Kansas limited liability company.  The Bankruptcy Cases are being jointly administered by the Bankruptcy Court under Case Number 09-11214 (KG).  We have operated and intend to continue operating our business as debtor-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.  As a result of the filing, attempts to collect, secure, or enforce remedies with respect to pre-petition claims against Aventine are subject to the automatic stay provisions of Section 362 of the Bankruptcy Code.  The Bankruptcy Cases are discussed in greater detail in Note 2 to the accompanying condensed consolidated financial statements.

 

On November 6, 2008, Aventine Renewable Energy, Inc. filed a Complaint against JPMorgan Securities, Inc. and JPMorgan Chase Bank, N.A. in the Circuit Court for the Tenth Judicial Circuit of Tazewell County, Illinois.  We are seeking to recover $31.6 million lost in the investment of funds in student loan backed auction rate securities.  We have alleged that JPMorgan Chase Bank through its investment arm, JPMorgan Securities, gave false assurances of the liquidity of this type of investment.  The $31.6 million figure represents funds lost because we were forced to sell the investment at a loss after they became illiquid; the investment monies were earmarked to fund our expansion activities.  There can be no assurance either that we will be successful in recovering any of these amounts or as to the timing of any such recovery pursuant to this litigation.

 

We are from time to time involved in various legal proceedings, including legal proceedings relating to the extensive environmental laws and regulations that apply to our facilities and operations, including those described under “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental Matters,” which is incorporated herein by reference.  We are not involved in any legal proceedings that we believe will have a material adverse effect upon our business, operating results or financial condition.

 

Item 4.  Submission of Matters to a Vote of Security Holders

 

No matters were submitted to a vote of security holders during the fourth quarter of 2009.

 

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PART II

 

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

Market for our Common Stock and Holders of Record

 

Our common stock is currently traded on the over-the-counter market (“OTC”) under the symbol “AVRNQ.”  We were previously traded on the New York Stock Exchange through March 29, 2009 under the symbol “AVR.”  Our common stock was delisted from the NYSE in March 2009 as a result of Aventine’s market capitalization falling below the NYSE’s $15 million required level for 30 consecutive days.  As of February 16, 2010, there were 43,443,078 shares of common stock outstanding held by 19 holders of record, based on the records of our transfer agent.

 

The following table sets forth, for the periods indicated, the range of high and low reported sale prices for our common stock on the New York Stock Exchange or OTC Bulletin Board, as applicable.

 

 

 

2009

 

2008

 

Period

 

High

 

Low

 

High

 

Low

 

First Quarter

 

$

0.70

 

$

0.09

 

$

13.08

 

$

4.71

 

Second Quarter

 

$

0.19

 

$

0.05

 

$

6.05

 

$

3.75

 

Third Quarter

 

$

0.35

 

$

0.15

 

$

7.42

 

$

3.10

 

Fourth Quarter

 

$

0.54

 

$

0.25

 

$

3.42

 

$

0.34

 

 

Dividends

 

We did not declare or pay cash dividends on our common stock during the years ended December 31, 2009 or 2008.  While in bankruptcy, we are effectively restricted from making dividend payments.

 

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Item 6.  Selected Financial Data

 

The historical consolidated financial data presented below should be read in conjunction with the information set forth under “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our Consolidated Financial Statements beginning on page F-1.

 

The balance sheet data presented below as of December 31, 2009 and 2008 and the statement of operations data presented below for each of the years in the three-year period ended December 31, 2009, are derived from our audited Consolidated Financial Statements beginning on page F-1.  The other balance sheet data and statement of operations data is derived from our previously audited consolidated financial statements included in our prior Form 10-K filings.

 

 

 

Year Ended December 31,

 

 

 

2009

 

2008

 

2007

 

2006

 

2005

 

 

 

 

 

 

 

 

 

 

 

 

 

Statement of Operations Data:
(in thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

Net sales

 

$

594,623

 

$

2,248,301

 

$

1,571,607

 

$

1,592,420

 

$

935,468

 

Cost of goods sold

 

585,904

 

2,239,340

 

1,497,807

 

1,460,806

 

848,053

 

Gross profit

 

8,719

 

8,961

 

73,800

 

131,614

 

87,415

 

 

 

 

 

 

 

 

 

 

 

 

 

Selling, general and administrative expenses

 

26,694

 

35,410

 

36,367

 

28,328

 

22,500

 

Demobilization costs associated with expansion projects

 

 

9,874

 

 

 

 

Impairment of plant development costs

 

 

1,557

 

 

 

 

Other income (expense)

 

(1,510

)

2,936

 

1,113

 

3,389

 

989

 

Operating income (loss)

 

(19,485

)

(34,944

)

38,546

 

106,675

 

65,904

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

Income from termination of marketing agreements

 

10,176

 

 

 

 

 

Loss on the sale of auction rate securities

 

 

(31,601

)

 

 

 

Interest income

 

11

 

3,040

 

12,432

 

4,771

 

2,218

 

Interest expense (contractual interest expense was $36.6 million for the year ended December 31, 2009)

 

(14,697

)

(5,077

)

(16,240

)

(9,348

)

(16,510

)

Loss on marketing alliance investment

 

 

(4,326

)

 

 

 

Loss on early extinguishment of debt

 

 

 

 

(14,598

)

 

Gain (loss) on derivative transactions

 

1,219

 

17,110

 

(78

)

3,654

 

1,781

 

Income (loss) before reorganization items and income taxes

 

(22,776

)

(55,798

)

34,660

 

91,154

 

53,393

 

Reorganization items

 

(32,440

)

 

 

 

 

Income (loss) before income taxes

 

(55,216

)

(55,798

)

34,660

 

91,154

 

53,393

 

Income tax expense (benefit)

 

(8,956

)

(7,472

)

(477

)

31,685

 

18,807

 

Net income (loss)

 

(46,260

)

$

(48,326

)

$

35,137

 

$

59,469

 

$

34,586

 

Net income (loss) attributable to non-controlling interest

 

 

(1,230

)

1,338

 

4,568

 

2,404

 

Net income (loss) attributable to controlling interest

 

$

(46,260

)

$

(47,096

)

$

33,799

 

$

54,901

 

$

32,182

 

 

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Year Ended December 31,

 

 

 

2009

 

2008

 

2007

 

2006

 

2005

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) per common share-basic

 

$

(1.08

)

$

(1.12

)

$

0.81

 

$

1.43

 

$

0.93

 

Basic weighted-average common shares

 

42,968

 

42,136

 

41,886

 

38,411

 

34,686

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) per common share-diluted

 

$

(1.08

)

$

(1.12

)

$

0.80

 

$

1.39

 

$

0.89

 

Diluted weighted-average common and common equivalent shares

 

42,968

 

42,136

 

42,351

 

39,639

 

36,052

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Data (unaudited):

 

 

 

 

 

 

 

 

 

 

 

(In thousands, except per bushel and per gallon amounts)

 

 

 

 

 

 

 

 

 

 

 

Gallons sold

 

277,471

 

935,986

 

690,171

 

695,784

 

529,836

 

Capital expenditures

 

$

2,279

 

$

265,878

 

$

235,211

 

$

76,499

 

$

20,675

 

Average price per gallon of ethanol sold

 

$

1.75

 

$

2.22

 

$

2.08

 

$

2.18

 

$

1.63

 

Average price of corn per bushel

 

$

3.87

 

$

5.02

 

$

3.76

 

$

2.41

 

$

2.08

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

(in thousands, at period end)

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

713,675

 

$

799,459

 

$

762,185

 

$

408,136

 

$

221,977

 

Total debt (1)

 

$

42,765

 

$

352,200

 

$

300,000

 

 

$

161,514

 

Stockholders’ equity (deficit)

 

$

267,532

 

$

308,796

 

$

343,871

 

$

304,163

 

$

(20,654

)

 


(1)          Total debt includes amounts outstanding under:  1) our revolving credit agreement;  2) our senior unsecured notes in 2007 and 2008;  3) our debtor-in-possession debt facility; and  4) our previously outstanding senior, secured floating rate notes.  The senior unsecured notes are reflected in pre-petition liabilities subject to compromise at December 31, 2009.

 

The following table reconciles net income (loss) to our EBITDA and Adjusted EBITDA for each period presented above.  We have included EBITDA and Adjusted EBITDA primarily as performance measures because management uses them as key measures of our performance and ability to generate cash necessary to meet our future requirements for debt service, capital expenditures, working capital and taxes.

 

 

 

(Unaudited)
For the Years Ended December 31,

 

(In thousands)

 

2009

 

2008

 

2007

 

2006

 

2005

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(46,260

)

$

(47,096

)

$

33,799

 

$

54,901

 

$

32,182

 

Interest income

 

(11

)

(3,040

)

(12,432

)

(4,771

)

(2,218

)

Interest expense (contractual interest expense was $36.6 million for the year ended December 31, 2009)

 

14,697

 

5,077

 

16,240

 

9,348

 

16,510

 

Income tax expense/(benefit)

 

(8,956

)

(7,472

)

(477

)

31,685

 

18,807

 

Depreciation

 

14,366

 

14,522

 

12,578

 

3,714

 

2,274

 

EBITDA (1)

 

$

(26,164

)

$

(38,009

)

$

49,708

 

$

94,877

 

$

67,555

 

Loss on early extinguishment of debt

 

 

 

 

14,598

 

 

Loss related to auction rate securities

 

 

31,601

 

 

 

 

Impairment of plant development costs

 

 

1,557

 

 

 

 

Reorganization items

 

32,440

 

 

 

 

 

Adjusted EBITDA (2)

 

$

6,276

 

$

(4,851

)

$

49,708

 

$

109,475

 

$

67,555

 

 


(1)          EBITDA is defined as earnings before interest expense, interest income, income tax expense, and  depreciation.  EBITDA is not a measure of financial performance under accounting principles generally accepted in the United States and should not be considered an alternative to net earnings or any other measure of performance under accounting principles generally accepted in the U.S. or to cash flows from operating, investing or financing activities as an indicator of cash flows or as a measure of liquidity.

 

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EBITDA has its limitations as an analytical tool, and you should not consider it in isolation or as a substitute for analysis of our results as reported under generally accepted accounting principles.  Some of the limitations of EBITDA are:

 

·                  EBITDA does not reflect our cash used for capital expenditures;

·                  Although depreciation and amortization are non-cash charges, the assets being depreciated or amortized often will have to be replaced and EBITDA does not reflect the cash requirements for such replacements;

·                  EBITDA does not reflect changes in, or cash requirements for, our working capital requirements;

·                  EBITDA does not reflect the cash necessary to make payments of interest or principal on our indebtedness; and

·                  EBITDA includes non recurring loss items  which are reflected in other income (expense).

 

(2)          In order to emphasize the effects of non-recurring loss items in our financial statements, we have occasionally reported a second computation referred to as Adjusted EBITDA which adjusts EBITDA for those non-recurring loss items.

 

Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

This Management’s Discussion and Analysis and certain other sections of this Form 10-K contain forward-looking statements that involve a number of risks and uncertainties. Words such as “expects,” “anticipates,” “believes,” “estimates,” and other similar expressions or future or conditional verbs such as “will,” “should,” “would” and “could” are intended to identify such forward-looking statements. Forward-looking statements are made pursuant to the safe harbor provisions of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are based on our beliefs as well as assumptions made by and information currently available to us.

 

Accordingly, our actual results may differ materially from those expressed or implied in such forward-looking statements due to known or unknown risks and uncertainties that exist in our operations and business environment, including but not limited to: changes in or elimination of laws, tariffs, trade or other controls or enforcement practices, environmental laws and regulations applicable to our operations and the enforcement thereof; changes in weather and general economic conditions; overcapacity within the ethanol, biodiesel and petroleum refining industries; total United States consumption of gasoline; availability and costs of products and raw materials; labor relations; fluctuations in petroleum prices; the impact on margins from a change in the relationship between prices received from the sale of co-products and the price paid for corn; our ability to generate free cash flow to invest in its business and service any indebtedness; limitations and restrictions contained in the instruments and agreements governing our indebtedness; our ability to raise additional capital and secure additional financing, and our ability to service such debt, if obtained; our ability to retain key employees; liability resulting from actual or potential future litigation; competition; plant shutdowns or disruptions at our plant or plants whose products we market; availability of rail cars and barges; our ability to complete our ethanol plant expansion projects in a timely manner and at the expected cost; our ability to receive and/or renew permits to construct and/or commence operations of our proposed capacity additions in a timely manner, or at all; and fluctuations in earnings resulting from increases or decreases in the value of ethanol or biodiesel inventory.

 

The following discussion of our consolidated operating results and financial condition for the three years ended December 31, 2009 should be read in conjunction with the Consolidated Financial Statements, and related notes beginning on page F-1.

 

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Chapter 11 Bankruptcy Proceedings

 

On April 7, 2009 (the “Petition Date”), Aventine Renewable Energy Holdings, Inc. and all of its direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions for relief (collectively, the “Bankruptcy Filing”) under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”) with the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”).  The Chapter 11 cases are being jointly administered by the Bankruptcy Court as Case No. 09-11214 (KG) (collectively, the “Bankruptcy Cases”).  The Debtors specifically are (i) Aventine Renewable Energy Holdings, Inc.; (ii) Aventine Renewable Energy, LLC, a Delaware limited liability company; (iii) Aventine Renewable Energy, Inc., a Delaware corporation; (iv) Aventine Renewable Energy — Mt. Vernon, LLC, a Delaware limited liability company; (v) Aventine Renewable Energy — Aurora West, LLC, a Delaware limited liability company; (vi) Aventine Power, LLC, a Delaware limited liability company, and (vii) Nebraska Energy, LLC, a Kansas limited liability company.

 

Subject to certain specific exceptions under the Bankruptcy Code, the Bankruptcy Filing automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against the Debtors or their property to recover on, collect or secure a claim arising prior to the Petition Date.  Thus, for example, most creditor actions to obtain possession of property from the Debtors, or to create, perfect or enforce any lien against the property of the Debtors, or to collect on or otherwise exercise rights or remedies with respect to a pre-petition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.

 

The Bankruptcy Filing constituted an event of default under both the Company’s secured revolving credit facility and its 10% senior unsecured notes due 2017 (“the Notes”) (see Note 7), and those debt obligations became automatically and immediately due and payable, subject to an automatic stay of any action to collect, assert, or recover a claim against the Company and the application of applicable bankruptcy law.  As a result, the accompanying Consolidated Balance Sheet as of December 31, 2009 includes reclassifications of $309.7 million to reflect as “pre-petition liabilities subject to compromise” amounts owed to holders of the Notes, including pre-petition accrued interest, net of the unamortized debt issuance costs on the Notes.  The Company classifies “pre-petition liabilities subject to compromise” as a long-term liability because management does not believe the Company will use existing current assets or create additional current liabilities to fund these obligations.  Amounts owed under the Company’s pre-petition secured revolving credit facility and certain other collateralized obligations have not been included in “pre-petition liabilities subject to compromise” as they are  adequately collateralized.

 

Chapter 11 Process

 

The Debtors are currently operating as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court, and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.  In general, as debtors-in-possession, the Debtors are authorized under the Bankruptcy Code to continue to operate as an ongoing business, but may not engage in transactions outside of the ordinary course of business without the approval of the Bankruptcy Court.

 

On April 7, 2009, certain of the Company’s bondholders entered into a term sheet (the “DIP Term Sheet”) for a $30 million Debtor-in-Possession Credit Facility with the Debtors.  The DIP Term Sheet provides, subject to certain conditions as described in the Debtor-in-Possession Credit Facility Term Sheet filed as Exhibit 10.1 to our Form 8-K filed on April 13, 2009 for a first priority debtor-in-possession financing comprised of a term loan facility made available to certain of Aventine’s subsidiaries in a maximum aggregate principal amount of up to $30 million (the “DIP Facility”).  On May 5, 2009, the Bankruptcy Court overruled objections from the Debtors’ pre-petition secured lenders and approved the DIP Facility on a final basis.  Proceeds of the DIP Facility are available to, among other things, (i) fund the

 

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working capital and general corporate needs of the Debtors and the costs of the Bankruptcy Cases in accordance with an approved budget, and (ii) provide adequate protection, in accordance with the terms of the DIP Facility, to the pre-petition agent and pre-petition lenders under the Company’s existing credit facilities.  The DIP Facility bears interest at 16.5% per annum.  The maturity date of the DIP Facility is April 6, 2010, or upon the occurrence of certain pre-defined events.  The DIP Facility is secured by a super-priority administrative claim on our assets.

 

At a hearing held on April 9, 2009, the Bankruptcy Court granted the Debtors’ “First Day Motions.”  The relief granted by the Bankruptcy Court through the First Day Motions was designed to stabilize the Company’s operations and business relationships with vendors, lenders, employees and others, minimize the effects of the commencement of the Bankruptcy Cases and preserve the value of the Debtors’ assets.  The First Day Motions allowed, among other things, the payment of vendors and other providers in the ordinary course for goods and services ordered pre-petition but received on or after the Petition Date and other business-related payments necessary to maintain the operation of our businesses.  The First Day Motions also included the payment of pre-petition employee wages, salaries and benefits.  The Debtors have retained, with Bankruptcy Court approval, legal and financial professionals to advise the Debtors on the bankruptcy proceedings and certain other “ordinary course” professionals.  From time to time, the Debtors may seek Bankruptcy Court approval for the retention of additional professionals.

 

On or about April 29, 2009, the Debtors caused notice of the commencement of the Bankruptcy Cases to be served on all known or potential creditors and other parties in interest.  Vendors are being paid for goods furnished and services provided after the Petition Date in the ordinary course of business.

 

As required by the Bankruptcy Code, the United States Trustee for Delaware appointed an official committee of unsecured creditors (the “Creditors’ Committee”). The Creditors’ Committee and its legal representatives have a right to be heard on all matters that come before the Bankruptcy Court with respect to the Debtors.  There can be no assurance that the Creditors’ Committee will support the Debtors’ positions on matters to be presented to the Bankruptcy Court in the future or on any plan of reorganization.  Disagreements between the Debtors and the Creditors’ Committee could protract the Bankruptcy Cases, negatively impact the Debtors’ ability to operate, and delay the Debtors’ emergence from the Chapter 11 proceedings.

 

Under Section 365 of the Bankruptcy Code, the Debtors may assume, assume and assign, or reject executory contracts and unexpired leases, including real property, railcars and equipment leases, subject to the approval of the Bankruptcy Court and certain other conditions.  Rejection constitutes a court-authorized breach of the lease or contract in question and, subject to certain exceptions, relieves the Debtors of future obligations under such lease or contract, but creates a pre-petition claim for damages caused by such breach or rejection, subject to the Debtors’ right to review and contest such claim.  Parties whose contracts or leases are rejected may file claims against the Debtors for damages.  Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure all prior defaults under such executory contract or unexpired lease, including all pre-petition arrearages, and to provide adequate assurance of future performance.  In this regard, the Debtors’ financial statements include amounts classified as “pre-petition liabilities subject to compromise” that the Debtors believe that the Bankruptcy Court will allow as claim amounts as a result of the Debtors’ rejection of various executory contracts and unexpired leases.  Additional amounts may be included in “pre-petition liabilities subject to compromise” in future periods if additional executory contracts and unexpired leases are rejected.  Conversely, the Debtors would expect that the assumption of certain executory contracts and unexpired leases may convert certain liabilities shown in future financial statements as subject to compromise to post-petition liabilities.  Due to the uncertain nature of many of the potential claims, the Debtors are unable to project the magnitude of such claims with any degree of certainty.

 

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The Bankruptcy Court established September 8, 2009 at 4:00 p.m. eastern time as the deadline for the filing of proofs of claim, thereby requiring the Debtors’ creditors to submit claims for alleged liabilities not paid and/or damages incurred arising from or related to periods prior to the Petition Date.  In certain cases, differences exist between the amounts at which the Company has recorded liabilities for rejected contracts and other pre-petition liabilities in the Company’s financial statements and the amount claimed by Aventine’s creditors based on the Company’s estimate of the magnitude of claim to be allowed by the Bankruptcy Court.  Significant litigation may be required to resolve any such disputes or discrepancies.

 

In order to successfully exit Chapter 11, the Debtors will need to obtain confirmation by the Bankruptcy Court of a plan of reorganization that satisfies the requirements of the Bankruptcy Code.  A plan of reorganization could, among other things, resolve the Debtors’ pre-petition obligations, set forth the revised capital structure of the newly reorganized entity and provide for corporate governance subsequent to exit from bankruptcy.  As provided in the Bankruptcy Code, the Debtors have the exclusive right for 120 days after the Petition Date to file a plan of reorganization and 60 additional days to solicit and obtain necessary acceptances.  Such periods may be extended by the Bankruptcy Court for cause to up to 18 months and 20 months, respectively, after the Petition Date.  If the Debtors’ exclusivity period lapses, any party in interest may file a plan of reorganization for Aventine.  The Debtors have filed three motions with the Bankruptcy Court requesting extension of the exclusive filing and solicitation deadlines under Section 1121 of the Bankruptcy Code.  The first motion, approved by the Bankruptcy Court by order dated August 18, 2009, extended the exclusive deadline to file a plan of reorganization to October 5, 2009 and the solicitation of the necessary acceptances to December 3, 2009.  The second motion, approved by the Bankruptcy Court by order dated October 27, 2009 further extended the exclusive deadline to file a plan of reorganization through and including December 4, 2009 and the exclusive solicitation period through and including February 1, 2010.  The third motion, approved by the Bankruptcy Court by order dated January 7, 2010 further extended the exclusive deadline to file a plan of reorganization through and including March 4, 2010 and the exclusive solicitation period through and including May 3, 2010.

 

On December 4, 2009, the Debtors filed the Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code Dated as of December 4, 2009 (as amended, “the Plan”) and the Disclosure Statement for the Debtors’ Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code Dated as of December 4, 2009 (as amended, “the Disclosure Statement”).

 

On January 13, 2010, the Bankruptcy Court approved an order allowing the Debtors’ entry into the Backstop Commitment Agreement related to the offering of new senior secured notes and equity through the Plan.  The Bankruptcy Court, also on January 13, 2010, approved the Disclosure Statement as containing adequate information as required by section 1125 of the Bankruptcy Code and thus entered the Order (I) Approving the Disclosure Statement; (II) Establishing Procedures for Solicitation and Tabulation of Votes to Accept or Reject the Plan, Including (A) Approving Form and Manner of Solicitation Procedures, (B) Approving the Form and Notice of the Confirmation Hearing, (C) Establishing Record Date and Approving Procedures for Distribution of Solicitation Packages, (D) Approving Forms of Ballots, (E) Establishing Deadline for Receipt of Ballots, and (F) Approving Procedures for Vote Tabulations; (III) Establishing Deadline and Procedures for Filing Objections to (A) Confirmation of the Plan, and (B) the Debtors’ Proposed Cure Amounts for Unexpired Leases and Executory Contracts Assumed Pursuant to the Plan; (IV) Approving the Secured Notes Offering Procedures; and (V) Granting Related Relief.  The Bankruptcy Court established January 13, 2010 as the record date for purposes of determining which creditors and interest holders are entitled to vote on the Plan and receive materials in connection with the solicitation of votes to accept or reject the Plan, including notices of non-voting status.  The voting deadline for the holders of claims and interest holders entitled to vote under the Plan was established by the Bankruptcy Court as February 17, 2010.

 

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Pursuant to section 1128 of the Bankruptcy Code, the Bankruptcy Court has scheduled a hearing to consider confirmation of the Plan for February 24, 2010 at 3:00 p.m. prevailing eastern time before the Honorable Kevin Gross, United States Bankruptcy Court, 824 North Market Street, 6th Floor, Wilmington, Delaware 19801 (the “Confirmation Hearing”).  The Bankruptcy Court has directed that objections, if any, to confirmation of the Plan be served and filed so that they are received on or before February 17, 2010 at 4:00 p.m., prevailing eastern time.  The Confirmation Hearing may be adjourned from time to time by the Bankruptcy Court without further notice except for the announcement of the adjournment date made at the Confirmation Hearing or at any subsequent adjourned Confirmation Hearing. Chapter 11 of the Bankruptcy Code provides that unless the terms of section 1129(b) of the Bankruptcy Code are satisfied, for a bankruptcy court to confirm a Chapter 11 plan as a consensual plan, the holders of impaired claims against a debtor in each class of impaired claims must accept such plan by the requisite majorities set forth in the Bankruptcy Code.  An impaired class of claims shall have accepted a Chapter 11 plan if (a) the holders of at least two-thirds in amount of the claims in such class actually voting on a plan have voted to accept it, and (b) more than one-half in number of the holders in such class actually voting on the plan have voted to accept it.  Pursuant to the provisions of the Bankruptcy Code, only holders of allowed claims or equity interests in classes of claims or equity interests that are impaired and that are not deemed to have rejected a Chapter 11 plan are entitled to vote to accept or reject such proposed plan.  Generally, a claim or interest is impaired under a plan if the holder’s legal, equitable or contractual rights are altered under such plan.  Classes of claims or equity interests under a Chapter 11 plan in which the holders of claims or equity interests are unimpaired are deemed to have accepted such plan and are not entitled to vote to accept or reject the proposed plan.  In addition, classes of claims or equity interests in which the holders of claims or equity interests will not receive or retain any property on account of their claims or equity interests are deemed to have rejected the plan and are not entitled to vote to accept or reject the plan.  Under circumstances specified in the so-called “cramdown” provisions of Section 1129(b) of the Bankruptcy Code, the Bankruptcy Court may confirm a plan even if such plan has not been accepted by all impaired classes.  The precise requirements and evidentiary showing for confirming a Chapter 11 plan notwithstanding its rejection by one or more impaired classes of claims or equity interests depends upon a number of factors, including the status and seniority of the claims or equity interests, in the rejecting class — i.e., secured claims or unsecured claims, subordinated or senior claims, or common stock.

 

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, post-petition liabilities and pre-petition liabilities must be satisfied in full before stockholders of the Debtors are entitled to receive any distribution or retain any property under a plan of reorganization.  The ultimate recovery, if any, to creditors and stockholders of the Debtors will not be determined until confirmation and consummation of a plan of reorganization.  No assurance can be given as to what values, if any, will be ascribed in the Bankruptcy Cases to each of these constituencies or what types or amounts of distributions, if any, they would receive.  Accordingly, the Debtors urge that appropriate caution be exercised with respect to existing and future investments in any of the Company’s common stock or any of the Company’s liabilities.

 

Although the Debtors filed the Plan, which provides for emergence from Chapter 11 some time in the future, there can be no assurance that the Plan, or any other Chapter 11 plan, will be confirmed by the Bankruptcy Court, or that any such chapter 11 plan will be consummated.  In order to successfully emerge from chapter 11, the Debtors will need to, among other things, obtain alternative financing to replace the DIP Facility.  The Company has filed the Disclosure Statement, which was approved by the Bankruptcy Court as containing adequate information under section 1125 of the Bankruptcy Code, and the Plan, that includes a backstop lending agreement, which may be confirmed at a hearing on February 24, 2010.  For further discussion, see “Item 7 — Management Discussion and Analysis of Financial Condition and Results of Operations.”

 

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The Debtors have incurred and will continue to incur significant costs associated with the reorganization.  The amount of these costs, which are being expensed as incurred, are expected to significantly affect the Debtors’ results of operations.

 

Notice and Sell-Down Procedures for Trading Equity Securities

 

The Bankruptcy Court entered a final order (the “Final Trading Restriction Order”) on May 4, 2009 granting a motion of the Debtors to require beneficial owners of substantial amounts of the Company’s common stock to provide notice of their holdings and restrict, in specified circumstances and subject to specified terms and conditions, acquisitions or dispositions of the Company’s common stock by Substantial Equityholders (as defined below) (the “Common Stock Notice and Transfer Requirements”).

 

Under the Common Stock Notice and Transfer Requirements, all “Substantial Equityholders” must provide the Debtors, the Debtors’ counsel and the Bankruptcy Court advance notice of their intent to buy or sell the Company’s common stock (including options to acquire common stock, as further specified in the Final Trading Restriction Order) prior to effectuating any such purchase or sale.  A “Substantial Equityholder” under the Final Trading Restriction Order is a person or entity that beneficially owns or, as a result of a transaction, would beneficially own, at least 2.04 million shares (including options to acquire shares, as further specified in the Final Trading Restriction Order) of the Company’s common stock, representing approximately 4.75% of all issued and outstanding shares of the Company’s common stock.  The Common Stock Notice and Transfer Requirements were requested by the Debtors to identify and, where necessary, restrict potential trades of the Company’s common stock that could negatively impact the Debtors’ ability to preserve maximum availability of their accrued net operating losses and other tax attributes under Section 382 of the Code.  Pursuant to the Final Trading Restriction Order, the Debtors have 15 calendar days after notification of a transfer by a Substantial Equityholder to file any objections with the Bankruptcy Court and serve notice on such Substantial Equityholder.  If the Debtors file any objections, the transfer would not become effective unless approved by a final and non-appealable order of the Bankruptcy Court.  In addition, a person or entity that is or becomes a Substantial Equityholder must file with the Bankruptcy Court, and provide the Debtors and their counsel with, notification of such status on or before the later of (a) 15 days after the effective date of the notice of entry of the Final Trading Restriction Order or (b) ten days after becoming a Substantial Equityholder.

 

Proposed Plan Of Reorganization

 

On December 4, 2009 the Debtors filed the Initial Chapter 11 Plan and accompanying Disclosure Statement.  The Company subsequently filed the Plan and Disclosure Statement on January 13, 2010.  A hearing has been scheduled by the Bankruptcy Court for February 24, 2010 to consider confirmation of the Plan.  Under that Plan, the Company has classified the Claims and Equity Interests (as defined in the Plan).  All Claims and Equity Interests, except Administrative Claims, DIP Financing Claims, Fee Claims, and Priority Tax Claims, are placed in Classes set forth below.  In accordance with section 1123(a)(1) of the Bankruptcy Code, Administrative Claims, DIP Financing Claims, Fee Claims and Priority Tax Claims have not been classified.

 

1.               Unclassified Claims (not entitled to vote on the Plan)

a.               Administrative Claims

b.              DIP Financing Claims

c.               Fee Claims

d.              Priority Tax Claims

 

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2.               Unimpaired Classes of Claims (deemed to have accepted the Plan and therefore not entitled to vote on the Plan)

a.               Classes 1(a) — (f): Other Priority Claims

b.              Classes 3(a) — (f): Other Secured Claims

c.               Class 4(a): Kiewit Mt. Vernon Secured Claim

d.              Classes 8(a) — (f):  Intercompany Claims.

 

3.               Impaired Classes of Claims

a.               Classes 2(a) — (f): Prepetition Secured Credit Facility Claims

b.              Class 4(b): Kiewit Aurora West Secured Claim

c.               Classes 5(a) — (f):  Prepetition Unsecured Notes Claim

d.              Classes 6(a) — (f):  General Unsecured Claims

e.               Classes 7(a) — (f):  Convenience Claims

f.                 Class 9(a):  Equity Interests

 

Holders of Equity Interests in Classes 9(b) — (f) are deemed to reject the Plan since they are not receiving distributions or retaining any property under the Plan and therefore are not entitled to vote on the Plan.

 

If the Plan is approved by the Bankruptcy Court, upon the occurrence of the Effective Date (as defined in the Plan), holders of Allowed Claims and Equity Interests in Class 9(a) will be entitled to receive the distribution provided in the Plan, which, depending on the nature of the Allowed Claim, could be either a specified cash payment, cash and debt, equity or warrants in the new company’s (“Reorganized Aventine”) common stock.  The existing outstanding common stock of Aventine Renewable Energy Holdings, Inc. will be terminated and 8,550,000 shares of new common stock will be issued.  Approximately 6,840,000 shares of new common stock, or 80% of the issued and outstanding shares on the Effective Date will be reserved as the Unsecured Claims Stock Pool to be allocated pro rata to the Allowed Prepetition Unsecured Notes Claims (Class 5) and the Allowed General Unsecured Notes Claims (Class 6), subject to dilution by warrants and stock awards issued under the Management Incentive Plan.  As described further below, 1,710,000 shares of new common stock (“Noteholder New Equity”) will be reserved for the pro rata allocation to purchasers of a $105 million offering of 13% Senior Secured Notes due in 2015 provided for in the Plan to provide funds to support he Company through emergence, subject to dilution by warrants and stock awards issued under the Management Incentive Plan.  Warrants for purchase of an aggregate 5.0% of the common stock on a fully-diluted basis priced ate $40.94 per share will be distributed pro rata to holders of the Company’s existing outstanding common stock.

 

Pursuant to the Plan, the failure of Reorganized Aventine to meet any of the obligations described above with respect to the Exchange Registration or Resale Registration shall result in additional interest becoming payable with respect to the Senior Secured Notes (including notes issued in the Exchange Registration) in the amount of 2.0%.

 

Under the Plan, holders of the Allowed Prepetition Unsecured Notes Claims (Class 5) shall be entitled to subscribe and acquire their pro rata share of (i) $105 million in aggregate principal amount of the Senior Secured Notes and (ii) the shares of Noteholder New Equity.  1,710,000 shares of new common stock will be distributed pro rata with subscriptions to the Senior Secured Notes.  The proceeds of the issuance of the Senior Secured Notes shall be used to (i) make payments required to be made on or after the Effective Date under the Plan, including, without limitation, repayment of all amounts owing under the DIP Facility and payments required to be made to holders of Prepetition Secured Credit Facility Claims (Class 2), and (ii) fund working capital and general corporate needs of Reorganized Aventine.

 

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Certain lenders (Backstop Purchasers) have agreed to backstop/assure complete subscription to the Senior Secured Notes Offering in accordance with the terms of the Backstop Commitment agreement filed with the Plan.  In addition, the Plan provides that on or as soon as practicable after the Effective Date, Reorganized Aventine shall close on the ABL Credit Facility.  The amounts borrowed under the ABL Credit Facility will be used to fund Reorganized Aventine’s working capital needs after the Effective Date.

 

Going Concern Matters

 

The ability of the Company to continue as a going concern is dependent upon, among other things, (i) the Company’s ability to comply with the terms and conditions of the DIP Facility; (ii) the ability of the Company to maintain adequate cash on hand; (iii) the ability of the Company to generate cash from operations; (iv) the ability of the Company to obtain confirmation of and to consummate a plan of reorganization under the Bankruptcy Code; (v) the cost and outcome of the reorganization process; (vi) the Company’s ability to obtain alternative financing; and (vii) the Company’s ability to achieve profitability.  Uncertainty as to the outcome of these factors raises substantial doubt about the Company’s ability to continue as a going concern.  The Company is currently evaluating various courses of action to address the issues the Company is facing.  There can be no assurance that any of these efforts will be successful.

 

The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of our Chapter 11 proceedings.  In particular, the financial statements do not purport to show (i) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (ii) as to pre-petition liabilities, the amounts that may be allowed for claims or contingencies, or the status and priority thereof; (iii) as to shareowners’ equity accounts, the effect of any changes that may be made in our capitalization; or (iv) as to operations, the effect of any changes that may be made to our business.

 

We have prepared  the consolidated financial statements in accordance with ASC 852.  This guidance requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business.  Accordingly, certain expenses (including professional fees), realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings are recorded in reorganization items on the accompanying Consolidated Statements of Operations.  In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on the  Consolidated Balance Sheet at December 31, 2009 in “pre-petition liabilities subject to compromise.”  These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.  For information on the bankruptcy reorganization process, see Note 2 - Chapter 11 Bankruptcy Proceedings.

 

Company Overview

 

Aventine is a producer of ethanol.  Through our production facilities, we market and distribute ethanol to many of the leading energy companies in the U.S.  In addition to producing ethanol, our facilities also produce several co-products including: corn gluten feed and meal, corn germ, condensed corn distillers solubles, dried distillers grain with solubles (“DDGS”), wet distillers grain with solubles (“WDGS”), carbon dioxide and brewers’ yeast.

 

Executive Summary — Results of Operations

 

We generated a net loss of $46.3 million, or $1.08 per diluted share in 2009, as compared to a net loss of $47.1 million, or $1.12 per diluted share, in 2008.  The 2009 net loss was significantly increased by $32.4 million in reorganization items resulting from the Company’s Chapter 11 bankruptcy filing. Revenue in 2009 decreased to $594.6 million as compared to $2.2 billion in 2008.

 

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Gallons of ethanol sold in 2009 decreased to 277.5 million from 936.0 million in 2008.  With severely declining gross profit margins and general liquidity stress due to frozen credit markets, we negotiated termination agreements with our marketing alliance partners and began to rationalize our distribution network to primarily focus on sales of our equity production  beginning in the fourth quarter of 2008.  We completed the termination of our marketing alliance and scaled back our purchase/resale program during the first quarter of 2009.  The average gross selling price of ethanol in 2009 decreased to $1.75 per gallon, from the $2.22 received in 2008.  Ethanol production for 2009 totaled 197.5 million gallons, a slight increase from 188.8 million gallons in 2008.  Gross profit for 2009 decreased slightly to $8.7 million from $9.0 million in  2008.  Negative gross margin through the third quarter of 2009 was offset by a positive gross margin of $22.2 million in the fourth quarter.

 

In 2009, the Company recognized income from the termination of marketing agreements with alliance partners totaling $10.2 million.  The 2008 net loss was increased as a result of $33.2 million in nonrecurring losses comprised of $31.6 million related to the sale of its portfolio of auction rate securities and a $1.6 million impairment loss pertaining to the development costs of a second dry mill ethanol plant on the Pekin site.

 

General

 

The following general factors should be considered in analyzing our results of operations:

 

Variability of Gross Profit

 

Our gross profit has fluctuated and may continue to fluctuate substantially from period to period.  Gross profit from ethanol sales is mainly affected by changes in selling prices for ethanol, the cost to us of purchasing ethanol from marketing alliance partners and unaffiliated producers, along with the cost of corn, freight and the cost to convert corn to ethanol.  The rise and fall of ethanol and corn prices affects the levels of our costs of goods, gross profit and inventory values, even in the absence of any increases or decreases in business activity.  Selling prices for ethanol are affected principally by industry oversupply concerns, the price and availability of competing and complementary fuels and the price of corn.  All of these factors are beyond our control.

 

Our most volatile manufacturing costs are natural gas and corn.  See “Item 1A — Risk Factors — Our business is dependent upon the availability and price of corn.  Significant disruptions in the supply of corn will materially affect our operating results.  In addition, since we generally cannot pass on increases in corn prices to our customers, continued periods of historically high corn prices will also materially adversely affect our operating results,” and “Item 1A — Risk Factors — The market for natural gas is subject to market conditions that create uncertainty in the price and availability of the natural gas that we utilize in our manufacturing process.”  Since both natural gas and ethanol are energy-related products, there has been significant, although not perfect, correlation between their market prices.  As a result, at times when natural gas prices had increased, thereby increasing our costs, ethanol prices have typically increased, thereby increasing our revenues and offsetting some of the impact on our results of operations.

 

Conversion Costs

 

Conversion costs per gallon are an important metric in determining our profitability.  Conversion costs represent the cost of converting corn into ethanol, and include production salaries, wages and stock compensation costs, fringe benefits, utilities (including coal and natural gas), maintenance, denaturant, insurance, materials and supplies and other miscellaneous production costs.  It does not include depreciation and amortization expense.

 

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Summary of Critical Accounting Policies

 

We base this discussion and analysis of results of operations, cash flow and financial condition on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”).

 

The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of our Chapter 11 proceedings.  In particular, the financial statements do not purport to show (i) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (ii) as to pre-petition liabilities, the amounts that may be paid out for claims or contingencies, or the status and priority thereof; (iii) as to shareowners’ equity accounts, the effect of any changes that may be made in our capitalization; or (iv) as to operations, the effect of any changes that may be made to our business.

 

In accordance with GAAP, we have applied authoritative guidance of ASC 852, in preparing the consolidated financial statements.  This guidance requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business.  Accordingly, certain expenses (including professional fees), realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings are recorded in reorganization items on the accompanying Condensed Consolidated Statements of Operations.  In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on the Consolidated Balance Sheet at December 31, 2009 in “pre-petition liabilities subject to compromise.”  These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.  For information on the bankruptcy reorganization process, see Note 2 - Chapter 11 Bankruptcy Proceedings.

 

As a result of the Bankruptcy Filing, realization of assets and liquidation of liabilities are subject to uncertainty.  While operating as a debtor-in-possession under the protection of Chapter 11, and subject to Bankruptcy Court approval or otherwise as permitted in the normal course of business, the Debtors may sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in the condensed consolidated financial statements.  Further, a plan of reorganization could materially change the amounts and classifications reported in our consolidated financial statements.  Our historical consolidated financial statements do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.

 

Share-based Compensation Expense

 

Effective January 1, 2006, we adopted, on a modified prospective transition method, Accounting Standards Codification 718, Compensation — Stock Compensation (“ASC 718”), which requires measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including stock options, based on fair values.  Share-based compensation expense recognized is based on the value of the portion of share-based payment awards that is ultimately expected to vest.  Share-based compensation expense recognized in our Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and 2007 include compensation expense for unvested share-based payment awards granted prior to December 31, 2005, based on the grant date fair value estimated in accordance with the minimum value method as outlined in ASC 718, and compensation expense for the share-based payment awards granted subsequent to December 31, 2005 based on the grant date fair value estimated in accordance with the provisions of ASC 718.  In conjunction with the adoption of ASC 718, we elected to attribute the value of share-based compensation to expense over the periods of requisite service using the straight-line method.

 

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Upon adoption of ASC 718, we elected to value our share-based payment awards granted beginning in fiscal year 2006 using a form of the Black-Scholes option-pricing model (the “Option-Pricing Model”), which was previously used to calculate stock-based compensation expense using the minimum value method as outlined in ASC 718.  The determination of fair value of share-based payment awards on the date of grant using the Option Pricing Model is affected by our stock price as well as the input of other subjective assumptions, of which the most significant are expected stock price volatility, the expected pre-vesting forfeiture rate and the expected option term (the amount of time from the grant date until the options are exercised or expire).  Expected volatility is normally calculated based upon actual historical stock price movements over the expected option term.  Since we have no considerable history of stock price volatility as a public company at the time of the grants, we calculated volatility by considering, among other things, the expected volatilities of public companies engaged in similar industries.  Pre-vesting forfeitures prior to June 30, 2008 were estimated using a 3% forfeiture rate.  We adjusted the forfeiture rate to 6.4%, 10.7%, 14.2%, and 20.0% as of July 1, 2008, January 1, 2009, July 1, 2009, and October 1, 2009, respectively, to reflect our experience with actual forfeitures.  The expected option term is calculated using the “simplified” method permitted by SAB 107.  Our options have characteristics significantly different from those of traded options, and changes in the assumptions can materially affect the fair value estimates.

 

Inventory

 

Inventories are stated at the lower of cost or market.  Cost is determined using a weighted-average first-in-first-out (“FIFO”) method for gallons produced at our plants, gallons purchased from our marketing alliance partners and other gallons purchased for resale.  In assessing the ultimate realization of inventories, we perform a periodic analysis of market price and compare that to our weighted-average FIFO cost to ensure that our inventories are properly stated at the lower of cost or market.

 

Derivatives and Hedging Activities

 

Our operations and cash flows are subject to fluctuations due to changes in commodity prices.  We use derivative financial instruments from time-to-time to manage commodity prices.  Derivatives used are primarily commodity futures contracts, swaps and option contracts.

 

We apply the provisions of Accounting Standards Codification 815, Derivatives and Hedging (“ASC 815”), for our derivatives.  These derivative contracts are not designated as hedges and, therefore, except for contracts that meet the normal purchase or normal sale exception, are marked to market each period, with corresponding gains and losses recorded in other non-operating income (loss).  The fair value of these derivative contracts are recognized in other current assets or other current liabilities in the Consolidated Balance Sheets, net of any cash received from the relevant brokers.

 

ASC 815 requires a company to evaluate contracts to determine whether the contracts are derivatives.  Certain contracts that meet the literal definition of a derivative under ASC 815 may be exempted from the accounting and reporting requirements of ASC 815 as normal purchases or normal sales.  Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business.  The Company elects to designate its forward purchases of corn and forward sales of ethanol as normal purchases and sales under ASC 815.  Accordingly, these contracts are not recorded in our financial results until performance under them occurs.

 

Income Taxes

 

Under Accounting Standards Codification 740, Income Taxes (“ASC 740”), deferred tax liabilities and assets are recorded for the expected future tax consequences of events that have been recognized in our

 

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financial statements or tax returns.  Property, plant and equipment, stock-based compensation expense and investments in marketing alliance partners are the primary sources of these temporary differences.  Deferred income taxes also includes net operating loss and capital loss carryforwards.  The Company establishes valuation allowances to reduce deferred tax assets to amounts it believes are realizable and contingency reserves for implemented tax planning strategies.  These valuation allowances and contingency reserves are adjusted based upon changing facts and circumstances.

 

Pension and Postretirement Benefit Costs

 

Net pension and postretirement costs were $0.7 million for the year ended December 31, 2009 and $0.3 million for the year ended December 31, 2008.  Total estimated pension and postretirement expense in 2010 is expected to be similar to previous years.  These expenses are primarily included in cost of goods sold.  We made contributions to our defined benefit pension plan in 2009, 2008 and 2007 of $0.2 million, $0.9 million, and $0.5 million, respectively.  In 2010, we expect to make contributions totaling $0.8 million to our defined benefit plan.

 

Our pension and postretirement benefit costs are developed from actuarial valuationsInherent in these valuations are key assumptions including discount rates and expected long-term rates of return on plan assets.  Material changes in our pension and postretirement benefit costs may occur in the future due to changes in these assumptions, changes in the number of plan participants, changes in the level of benefits provided, changes to the level of contributions to these plans and other factors.

 

We determine our actuarial assumptions for our pension and post retirement plans, after consultation with our actuaries, on December 31 of each year to calculate liability information as of that date and pension and postretirement expense for the following year.  The discount rate assumption is determined based on a spot yield curve that includes bonds that are rated Corporate AA or higher with maturities that match expected benefit payments under the plan.

 

The expected long-term rate of return on plan assets reflects projected returns for the investment mix that have been determined to meet the plan’s investment objectives.  The expected long-term rate of return on plan assets is selected by taking into account the expected weighted averages of the investments of the assets, the fact that the plan assets are actively managed to mitigate downside risks, the historical performance of the market in general and the historical performance of the retirement plan assets over the past ten years.

 

Revenue Recognition

 

Revenue is generally recognized when title to products is transferred to an unaffiliated customer as long as the sales price is fixed or determinable and collectability is reasonably assured.  For the majority of sales, this generally occurs after the product has been offloaded at the customers’ site.  For others, the transfer of title occurs at the shipment origination point.  The majority of sales are invoiced at the final per unit price which may be a previously contracted fixed price or a market price at the time of shipment.  Other sales are invoiced and the initial receipts are collected based upon a provisional price, and such sales are adjusted to a final price based upon a monthly-average spot market price.  Sales are made under normal terms and usually do not require collateral.

 

The Company has marketed ethanol for other third-party producers.  Revenues from such non-Company produced gallons are generally recorded on a gross basis in the accompanying statements of operations, as the Company takes title to the product, assumes all risks associated with the purchase and sale of such gallons and is considered the primary obligor on the sale.  Transactions entered into with the same counterparty which have been negotiated in contemplation of one another are recorded on a net basis.

 

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The majority of sales are based upon a delivered price, which includes a cost for freight.  In such cases, the sales price, including the cost of delivery plus any respective motor fuel excise taxes, is invoiced and included in revenue.  If title transfers at the shipment origination point, the customer generally is responsible for freight costs, and the Company does not recognize such freight costs in its financial statements.

 

Results of Operations

 

Year Ended December 31, 2009, Compared with Year Ended December 31, 2008

 

Total gallons sold in 2009 were 277.5 million gallons, versus 936.0 million gallons sold in 2008, a decrease of 658.5 million gallons.  Ethanol gallons sourced were as follows:

 

For the Year Ended December 31,

 

(In thousands, except for percentages)

 

2009

 

2008

 

Increase/
(Decrease)

 

% Increase/
(Decrease)

 

Equity production

 

197,498

 

188,764

 

8,734

 

4.6

%

Marketing alliance purchases

 

30,858

 

505,254

 

(474,396

)

(93.9

)%

Purchase/resale

 

35,506

 

249,028

 

(213,522

)

(85.7

)%

Decrease (increase) in inventory

 

13,609

 

(7,060

)

20,669

 

N.M.

*

Total

 

277,471

 

935,986

 

(658,5155

)

(70.4

)%

 


*  Not meaningful

 

Net sales for 2009 were significantly lower at $594.6 million for 2009 versus $2.2 billion in 2008.  With severely declining gross profit margins and general liquidity stress due to frozen credit markets, we negotiated termination agreements with our marketing alliance partners and began to rationalize our distribution network to primarily focus on sales of our equity production  beginning in the fourth quarter of 2008.  We completed the disbanding of our marketing alliance and scaled back our purchase/resale program during the first quarter of 2009.  The average gross selling price of ethanol in 2009 decreased to $1.75 per gallon, from the $2.22 received in 2008.

 

Co-product revenue for 2009 totaled $98.0 million, a decrease of $30.5 million or 23.8%, from the 2008 total of $128.5 million.  Co-product revenue decreased during 2009 versus 2008 principally from a decrease in co-product pricing due to lower corn prices.  Co-product pricing tends to follow the price of corn since the co-products are a substitute for corn as an animal feedstock   We sold 1.1 million tons of co-products in both 2009 and 2008.  Co-product revenues, as a percentage of corn costs, were 34.1% during 2009, versus 35.9% in 2008.  Co-product returns, as a percentage of corn costs, decreased in 2009 compared to 2008 as the co-product prices decreased more than the decrease in corn costs.

 

Cost of goods sold for 2009 was $585.9  million, a significant decrease from the $2.2 billion in 2008.  Cost of goods sold consists of the cost to produce ethanol at our own facilities, the cost of purchasing ethanol from marketing alliance partners, the cost of purchasing ethanol and bio-diesel from other producers and marketers, freight and logistics costs and the cost of motor fuel taxes which have been billed to customers.

 

Purchased ethanol in 2009 totaled $138.5 million, versus approximately $1.5 billion in 2008.  The decrease in purchased ethanol results from a decrease in the number of gallons of ethanol purchased from marketing alliance partners as well as a decrease in purchase/resale gallons purchased, along with a decrease in the cost per gallon of ethanol purchased.  In 2009, we purchased 66.4 million gallons of ethanol

 

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at an average cost of $1.56 per gallon as compared to 754.3 million gallons of ethanol at an average cost of $2.04 in 2008.

 

Production costs include corn costs, conversion costs (defined as the cost of converting the corn into ethanol, and includes production salaries, wages and stock compensation costs, fringe benefits, utilities (including coal and natural gas), maintenance, denaturant, insurance, materials and supplies and other miscellaneous production costs) and depreciation.  Corn costs in 2009 totaled $287.1 million or $3.87 per bushel, versus $358.4 million, or $5.02 per bushel in 2008.  The decrease in corn costs is due to the record high corn prices in 2008.

 

Conversion costs for 2009 decreased to $96.7 million from $131.8 million for 2008.  The total dollars spent on conversion costs decreased year over year primarily as a result of significant cost reductions for natural gas, materials and supplies, outside services, and denaturant.  Conversion cost per gallon decreased year over year to $0.49 per gallon in 2009 versus $0.70 per gallon in 2008.  Our plants ran at 98 % and 94% of capacity for 2009 and 2008, respectively, after adjusting for differences in denaturant blending levels.

 

Depreciation for 2009 totaled $14.4 million, versus $14.5 million in 2008.  Motor fuel taxes were $5.6 million in 2009 versus $17.6 million in 2008.  The cost of motor fuel taxes are recovered through billings to customers.

 

Freight/logistics costs in 2009 decreased to $44.9 million, or approximately $0.16 per gallon, from $175.3 million, or $0.19 per gallon in 2008.  Freight/logistics cost per gallon is calculated by taking total freight/logistics costs incurred and dividing by the total ethanol gallons sold.  Total freight/logistics costs also include costs to ship co-products.

 

The average cost of inventory was $1.44 at the end of 2009 as compared to $1.54 at the end of the 2008 reflecting the decline in the average ethanol prices in 2009 using our weighted average FIFO approach to valuing inventory.  The economic impact of selling gallons that were previously held in inventory at the end of 2008 during 2009 was a decrease in gross margin of approximately $4.2 million.

 

SG&A expenses were $26.7 million in 2009, a decrease of $8.7 million or 24.6% as compared to $35.4 million in 2008.  The decrease in SG&A is primarily attributable to decreases in  salaries ($2.8 million), salaried stock compensation  ($3.5 million) and outside services ($1.6 million) partially offset by an increase of $0.9 million in bad debt expense.

 

Financial results for 2009 were also positively impacted by the recognition $10.2 million in income from termination of marketing agreements.

 

Interest income in 2009 was $11 thousand, versus $3.0 million in 2008.  The decrease in interest income is due to a reduction in available funds to invest.

 

Interest expense in 2009 was $14.7 million, as compared to $5.1 million in 2008.  Interest expense in 2009 consists of $8.1 million  on our $300 million aggregate principal amount of senior unsecured 10% fixed-rate notes, $2.5 million on borrowing on our secured revolving credit facility, $2.3 million for amortization of deferred financing fees, and $1.8 million on our debtor-in-possession debt facility.  We ceased  the accrual of interest on the senior unsecured notes as of the bankruptcy petition date.  Interest expense capitalization was suspended with the halting of the expansion projects at Mt. Vernon and Aurora West.  Interest expense in 2008 was reduced by the capitalization of $26.4 million in interest expense on the expansion projects.

 

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Due to our purchase in October 2008 of the remaining 21.58% of our Nebraska subsidiary we did not already own, we have been recognizing 100% of the operating results of Nebraska Energy, LLC in our consolidated financial statements during 2009.

 

Other non-operating income for 2009 includes $1.2 million net realized and unrealized gains on derivative contracts compared to $17.1 million in 2008.  We have significantly reduced our hedging activity since the first quarter with only $31 thousand of non-operating income recorded in the last three quarters of 2009.

 

The Company’s annual tax benefit rate for 2009 was 16.2% of pre-tax loss.  The income tax benefit recorded in 2009 is net of a valuation allowance of $24 million.  The valuation allowance recognized on our gross deferred tax assets reduced our deferred tax asset to the amount we believe is more likely than not to be realized.  The valuation allowance includes $13.7 million of reserve against the income tax benefit related to the capital losses incurred mainly on auction rate securities as we do not expect to have sufficient capital gains to offset the $35.2 million capital loss.

 

Year Ended December 31, 2008, Compared with Year Ended December 31, 2007

 

Total gallons sold in 2008 were 936.0 million gallons, versus 690.2 million gallons sold in 2007, an increase of 245.8 million gallons, or an increase of 35.6%.  The increase/(decrease) in gallons by source was as follows:

 

For the Year Ended December 31,

 

(In thousands, except for percentages)

 

2008

 

2007

 

Increase/
(Decrease)

 

% Increase/
(Decrease)

 

Equity production

 

188,764

 

191,999

 

(3,235

)

(1.7

)%

Marketing alliance purchases

 

505,254

 

395,001

 

110,253

 

27.9

%

Purchase/resale

 

249,028

 

111,451

 

137,577

 

123.4

%

Decrease (increase) in inventory

 

(7,060

)

(8,280

)

1,220

 

N.M.

*

Total

 

935,986

 

690,171

 

245,815

 

35.6

%

 


* N.M. — not meaningful

 

Net sales for 2008 were significantly higher as compared to 2007, at $2.2 billion for 2008 versus $1.6 billion in 2007.  Overall, an increase in gallons sold and a higher average sales price of ethanol was complemented by higher co-product revenue.  Gallons sold in 2008 increased, reflecting a higher number of gallons marketed on behalf of marketing alliance partners and a higher number of gallons purchased from other producers, offset somewhat by lower equity production.  In 2008, the volume of ethanol purchased from marketing alliance partners increased due to the addition of new or expanded alliance facilities, primarily in the second half of the year.  The average gross selling price of ethanol in 2008 increased to $2.22 per gallon, from the $2.08 received in 2007.

 

Co-product revenue for 2008 totaled $128.5 million, an increase of $29.2 million or 29.4%, from the 2007 total of $99.3 million.  Co-product revenue increased during 2008 versus 2007 principally from an increase in co-product pricing due to record high corn prices.  In 2008 and 2007, we sold 1.1 million tons of co-products.  Co-product revenues, as a percentage of corn costs, were 35.9% during 2008, versus 36.7% in 2007.  Co-product returns, as a percentage of corn costs, decreased in 2008 as compared to 2007 as the co-product prices failed to keep pace with the increase in corn prices in 2008.

 

Cost of goods sold for 2008 was $2.2 billion, a significant increase over the $1.5 billion in 2007.  Cost of goods sold consists of the cost to produce ethanol at our own facilities, the cost of purchasing ethanol from our marketing alliance partners, the cost of purchasing ethanol and bio-diesel from other

 

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producers and marketers, freight and logistics costs and the cost of motor fuel taxes which have been billed to customers.

 

Purchased ethanol in 2008 totaled $1.5 billion, versus approximately $972.5 million in 2007.  The increase in purchased ethanol resulted from an increase in the number of gallons of ethanol purchased from marketing alliance partners, as well as an increase in purchase/resale gallons purchased, along with an increase in the cost per gallon of ethanol purchased.  In 2008, we purchased 754.3 million gallons of ethanol at an average cost of $2.04 per gallon as compared to 506.5 million gallons of ethanol at an average cost of $1.92 in 2007.

 

Production costs included corn costs, conversion costs (defined as the cost of converting the corn into ethanol, and included production salaries, wages and stock compensation costs, fringe benefits, utilities (including coal and natural gas), maintenance, denaturant, insurance, materials and supplies and other miscellaneous production costs) and depreciation.  Corn costs in 2008 totaled $358.4 million or $5.02 per bushel, versus $270.4 million, or $3.76 per bushel in 2007.  The increase in corn costs was due to record high corn prices in 2008.

 

Conversion costs for 2008 increased to $131.8 million from $117.0 million for 2007.  The total dollars spent on conversion costs increased year over year principally as a result of the record prices for commodities including oil and related products.  Conversion cost per gallon increased year over year to $0.70 per gallon in 2008 versus $0.61 per gallon in 2007.  Our plants ran at 94% of capacity for both 2008 and 2007 after adjusting for differences in denaturant blending levels.

 

Depreciation for 2008 totaled $14.5 million, versus $12.6 million in 2007.  Motor fuel taxes were $17.6 million in 2008 versus $13.9 million in 2007.  The cost of motor fuel taxes are recovered through billings to customers.

 

Freight/logistics costs in 2008 increased to $175.3 million, or approximately $0.19 per gallon, from $120.2 million, or $0.17 per gallon in 2007.  Freight/logistics cost per gallon is calculated by taking total freight/logistics costs incurred and dividing by the total ethanol gallons sold.  Total freight/logistics costs also include costs to ship co-products.  The increase in freight/logistics cost was principally the result of record high oil prices and the related surcharges, and from general freight increases associated with moving product along longer supply lines to emerging new markets in the southeastern United States.

 

The average cost of inventory was $1.54 at the end of 2008 as compared to $1.80 at the end of the 2007 reflecting the decline in the average ethanol prices in 2008 using our weighted average FIFO approach to valuing inventory.  The economic impact of selling gallons that were previously held in inventory at the end of 2007 during 2008 was a decrease in gross margin of approximately $9.5 million.

 

SG&A expenses were relatively flat at $35.4 million in 2008, as compared to $36.4 million in 2007.

 

Financial results for 2008 were also negatively impacted by pre-tax charges of $31.6 million on the loss on the sale of auction rate securities, $9.9 million for demobilization expenses related to the suspension of our expansion projects, $4.3 million for a loss on an investment in another ethanol producer, $1.6 million related to the impairment of the plant development costs for our Pekin III expansion and the establishment of tax related valuation allowances totaling $16.1 million.

 

Interest income in 2008 was $3.0 million, versus $12.4 million in 2007.  The decrease in interest income was principally due to a reduction in funds available to invest.

 

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Interest expense in 2008 was $5.1 million, as compared to $16.2 million in 2007.  Interest expense in 2008 reflected $30 million of interest incurred on our $300 million aggregate principal amount of senior unsecured 10% fixed-rate notes and $1.5 million of interest on our secured revolving credit facility, net of $26.4 million of capitalized interest.  In 2007, our senior unsecured 10% fixed-rate notes were only outstanding from March to December.

 

The non-controlling interest for 2008 was a $1.2 million credit to income compared to $1.3 million charge to income for 2007.  This increase reflected the reduced operating performance of our Nebraska subsidiary caused primarily by the year over year significant increase in corn costs.  Due to our purchase in October 2008 of the remaining 21.58% we did not already own, we began recognizing 100% of the operating results of Nebraska Energy, LLC in our consolidated financial statements.

 

Other non-operating income for 2008 included $17.1 million net realized and unrealized gains on derivative contracts.  This included the effect of marking to market these contracts at December 31, 2008.  Net gains on corn derivatives totaling $18.4 million were offset by net losses on short gasoline forward contracts totaling $1.3 million.  For 2007, we recognized $0.1 million of net realized and unrealized loss on derivative contracts.  Net gains on corn derivatives totaling $8.6 million were offset by the net losses on short gasoline forward contracts totaling $8.7 million.

 

The Company’s annual tax rate for 2008 was 13.7% of pre-tax loss.  The income tax benefit recorded in 2008 was net of a valuation allowance of $16.1 million.  The valuation allowance recognized on our gross deferred tax assets reduced our deferred tax asset to the amount we believed was more likely than not to be realized.  The valuation allowance included $12.3 million of reserve against the income tax benefit related to the losses incurred on auction rate securities as we did not expect to have sufficient capital gains to offset the $31.6 million capital loss.

 

Trends and Factors that May Affect Future Operating Results

 

Bankruptcy

 

If the Plan is confirmed and is declared effective during the first quarter of 2010, the Company will continue to incur reorganization related professional fees and costs for some time, will experience a reduction in its tax attributes related to the COD income it will realize which will reduce future tax benefits, will have a new ownership structure, and will have significantly fewer liabilities.  Any one or more of these factors could impact the Company’s performance in the near future.  Operation of the Company’s ethanol facilities should not be affected by the emergence from bankruptcy.

 

Supply and Demand

 

Through November 2009, U.S. ethanol demand exceeded U.S. ethanol production by 139 million gallons.  Demand for ethanol increased by 12% over 2008 through increased penetration into new markets, and a government mandate but, the production capacity of U.S. ethanol producers continues to exceed demand.  At the end of 2009, there was approximately 1.2 billion gallons of production capacity shut-in.  If additional demand for ethanol is not created, either through discretionary blending or an increase in the blending percentage allowed by the EPA, the excess supply may cause additional plants to shutter production or cause ethanol prices to decrease further, perhaps substantially.

 

Commodity Prices

 

Our primary grain feedstock is corn.  The cost of corn is dependent upon factors that are generally unrelated to those affecting the selling price of ethanol.  Corn prices generally vary with international and

 

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regional grain supplies, and can be significantly affected by weather, planting and carryout projections, government programs, exports, and other international and regional market conditions.  Due to the significant expansion of the ethanol industry, corn futures have increased substantially as compared to historical averages.  This trend is likely to continue and will have a material impact on our results of operation and financial condition.  In addition, factors such as USDA estimates of acres planted, export demand and other domestic usage also have significant effects on the corn market.  Weather-related impacts upon the corn market and prices are expected to be mitigated by new more resilient hybrid varieties of corn.

 

We have purchased forward approximately 1.4 million bushels (or approximately 8%) of our corn requirements for the first quarter of 2010 at an average price of $3.95 per bushel.

 

Natural Gas Prices

 

Natural gas is an important input in our ethanol and co-product production process.  We use natural gas primarily to dry distillers grains for storage and transportation over longer distances.  This allows us to market distillers grains to broader livestock markets in the U.S.  Natural gas prices fluctuated significantly during 2009.  Our current natural gas usage is approximately 283,000  MMBtus per month.

 

Ethanol Supports

 

We receive significant benefits from federal and state statutes, regulations and programs and the trend at the governmental level appears to be to continue to try to provide economic support to the ethanol industry.  Notwithstanding the above, changes to federal and state statutes, regulations or programs could have an adverse effect on our business.  Recent federal legislation, however, has been of benefit to the ethanol industry.  In December 2007, the Energy Independence and Security Act of 2007 was passed which contained a new increased RFS.  The new RFS requires fuel refiners to use a certain minimum amount of renewable fuels (including ethanol) which will rise from 12.95 billion gallons in 2010 to 36 billion gallons by 2022.  Ethanol benefits from an excise tax credit of $0.45 per ethanol gallon (prior to January 1, 2009, the excise tax credit was $0.51 per gallon).  This excise tax credit provides incentives for blenders and refiners to blend ethanol with gasoline.

 

Expansion

 

We have suspended construction of our plants in Aurora and Mt. Vernon.  We remain contractually obligated to complete construction of the suspended plants at Aurora and Mt. Vernon and may incur significant penalties because of our failure to complete these facilities as previously scheduled.  See “Item 1 — Risk Factors — We are contractually obligated to complete certain capacity expansions in Aurora, Nebraska and Mount Vernon, Indiana.  If we fail to complete them in a timely manner we may be subject to material penalties.”

 

Cancellation of indebtedness income

 

We will recognize income from cancellation of indebtedness (“COD”) when we emerge from bankruptcy to the extent that debt is discharged for consideration to a creditor for an amount that is less than the amount of such debt.  For these purposes consideration includes the amount of cash and the fair market value of property, including stock of the debtor, transferred to the creditor.  The amount of COD income, in general, is the excess of (a) the adjusted issue price of the indebtedness satisfied, over (b) the sum of the amount of cash paid and the fair market value of any new consideration (including the new stock of the Company following emergence from bankruptcy) given in satisfaction of the cancelled debt.  Although the precise amount of COD income that we will realize cannot be determined until the effective date of the Plan

 

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of Reorganization, we currently estimate that the amount of COD income we could realize will be approximately $135 million to $175 million for U.S. federal income tax purposes.

 

To the extent of COD income, we will be required to reduce certain of our tax attributes (principally, the tax basis in our assets) in the year following emergence.  Among other things, this would have the effect of reducing our future depreciation deductions.  The American Recovery and Reinvestment Act of 2009 (“ARRA”) provided an exception to the immediate realization of COD income, which would permit us to elect to defer the current recognition of any COD income, and instead recognize any such income ratably over a five-year period beginning in 2014.  Currently, we cannot determine if we will make the deferral election for COD income, as described above.

 

Section 382 limitations

 

Section 382 of the Internal Revenue Code limits the ability of a company that undergoes an ownership change, which is generally any change in ownership of more than 50% of its stock over a three-year period, to utilize its net operating loss carryforwards and certain built-in losses (generally, the excess of the tax basis in an asset over its fair market value) following the ownership change. These rules generally operate by focusing on ownership changes among stockholders owning directly or indirectly 5% or more of the stock of a company and any change in ownership arising from a new issuance of stock by the company.  While we do not believe that we have to date experienced an ownership change under Section 382, we believe we will experience an ownership change in the future as a result of changes in the ownership of our stock or future issuances of our stock, coincident with the confirmation of the Plan of Reorganization in our current Chapter 11 bankruptcy proceedings.

 

We have net operating loss carryforwards of approximately $1.5 million as of December 31, 2009.  If we undergo an ownership change for purposes of Section 382, our ability to recognize our built-in losses (including in the form of depreciation deductions on our assets) during the five-year period after the date of any ownership change would be subject to the limitations of Section 382.  Depending on the resulting limitation, our ability to use a significant portion of our future depreciation deductions could be limited, which could have the effect of creating or increasing our tax liabilities in years after such an ownership change, and have a negative impact on our financial position and results of operations.  During the pendency of the bankruptcy proceedings, the Bankruptcy Court has entered an interim order that places limitations on trading in our common stock, including options to acquire common stock, as further specified in the order.  However, we can provide no assurances that these limitations will prevent an “ownership change” or that our ability to utilize our net operating loss carryforwards may not be significantly limited as a result of our reorganization.

 

Liquidity and Capital Resources

 

The following table sets forth selected information concerning our financial condition:

 

 

 

December 31, 2009

 

December 31, 2008

 

(In thousands)

 

 

 

 

 

Cash and cash equivalents

 

$

52,585

 

$

23,339

 

Net working capital

 

$

38,136

 

$

(294,039

)

Total debt (1)

 

$

42,765

 

$

352,200

 

Current ratio

 

1.60

 

0.39

 

 


(1)       As of December 31, 2009, total debt excludes our Senior Unsecured Notes due in 2017 which are recorded in Pre-petition liabilities subject to compromise.

 

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Overview and Outlook

 

As a result of filing for Chapter 11 bankruptcy protection, we have been accelerating our efforts to preserve existing liquidity, and are attempting to raise additional sources of liquidity and capital.  We have suspended construction of our expansion facilities at both Mt. Vernon, Indiana and Aurora, Nebraska.  We have also taken steps to reduce our fixed cost structure by rationalizing and reducing the size and scope of our distribution network.  We have taken and expect to take additional steps to preserve liquidity.

 

On April 7, 2009, certain of the Company’s bondholders entered into a term sheet for a first priority debtor-in-possession financing comprised of a term loan facility made available to certain of Aventine’s subsidiaries in a maximum aggregate principal amount of up to $30 million (the “DIP Facility”).  On May 5, 2009, the Bankruptcy Court overruled objections from the Debtors’ pre-petition secured lenders and approved the DIP Facility on a final basis.  The terms of the DIP Facility are described in further detail below under “Cash available under the DIP Facility.”

 

The amount of cash and borrowings available to us under our DIP facility at the end of the fourth quarter of 2009 was $15.0 million.

 

Although we suspended construction at both Aurora West and Mt. Vernon during the fourth quarter of 2008, we continue to have construction payment obligations to Kiewit.  On March 9, 2009, the Company received a notice from Kiewit cancelling the engineering, construction and procurement contracts for Aurora West and Mt. Vernon, referencing our failure to make a recent payment under the change order agreements dated December 31, 2008.  As a result, all remaining payments due to it and its sub-contractors totaling $23.2 million at December 31, 2009 are due and payable.  The breakdown of our recorded liability to Kiewit at December 31, 2009 is as follows:  $15.3 million is reflected in pre-petition liabilities subject to compromise and $7.9 million is reflected in other long-term liabilities on our consolidated balance sheet as of December 31, 2009.  We are currently engaged in discussions with Kiewit to negotiate a payment schedule that falls within the economic constraints with which we are currently operating.  We cannot give you any assurance that we will reach an agreement with Kiewit that works within our projected liquidity constraints.

 

We remain contractually obligated to complete the suspended plants at Aurora and Mt. Vernon and may incur significant penalties because of our failure to complete these facilities as previously scheduled.

 

Sources of Liquidity

 

Our principal sources of liquidity are cash, cash provided by operations, and cash available under our DIP facility.

 

Cash.  During 2009, cash increased by $29.2 million.  Cash and short-term investments as of December 31, 2009 and 2008 were $52.6 million and $23.3 million, respectively.

 

Cash provided by operations.  Net cash provided by operating activities in 2009 was $40.8 million, as compared to $35.6 million for 2008.

 

Cash available under the DIP Facility.  As of December 31, 2009, the Company had drawn $15 million of its $30 million DIP Facility.  The DIP Facility provides for a first priority term loan in a maximum aggregate principal amount of up to $30 million.  Proceeds of the DIP Facility can be used, among other things, to (i) fund the working capital and general corporate needs of the Debtors and the costs of the Bankruptcy Cases in accordance with an approved budget, and (ii) provide adequate protection, in

 

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accordance with the terms of the DIP Facility, to the pre-petition agent and pre-petition lenders under the Company’s existing credit facilities.  The DIP Facility bears interest at 16.5%.  The maturity date of the DIP Facility is April 6, 2010, or upon the occurrence of certain pre-defined events including emergence from bankruptcy.  The DIP Facility is secured by a super-priority administrative expense claim on our assets.  As of December 31, 2009, the Debtors are in compliance with the terms of its DIP Facility.  The Company accrues and pays interest expense on the DIP Facility in accordance with the Bankruptcy Court’s final order approving the DIP Facility.

 

Proposed Plan of Reorganization.  The proposed Plan of Reorganization provides that on the Effective Date we will complete a $105 million offering of 13% senior secured notes due 2015, the proceeds of which will, in part, be used to repay the DIP Facility in full.  In addition, the proposed Plan of Reorganization provides that, on or as soon as practicable after the Effective Date, we will close on a new credit facility with availability of up to $20 million.

 

Uses of Liquidity

 

Our principal use of liquidity during the year ended December 31, 2009 has been repayments of $24.4 million of borrowings under our secured revolving credit facility.

 

Off-Balance Sheet Arrangements

 

We have not entered into any off-balance sheet arrangements that either have, or are reasonably likely to have, a material adverse current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

 

Contractual Obligations and Commercial Commitments

 

The following table provides a summary of our contractual obligations and commercial commitments as of December 31, 2009.  Former obligations of the Company for contracts rejected in bankruptcy are excluded from the table below.  These obligations are recorded in pre-petition liabilities subject to compromise at the amount the Company estimates will be allowed by the court as a bankruptcy claim.  Other non-current liabilities included in our Consolidated Balance Sheet that may not be fully disclosed below include accrued pension and post retirement costs.  Refer to Notes 16 and 17 of the Notes to the Consolidated Financial Statements.

 

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Payments due or expiring by period

 

(In millions)

 

Total

 

Less Than
1 year

 

1-3 years

 

3-5 years

 

More than
5 years

 

Contractual obligations:

 

 

 

 

 

 

 

 

 

 

 

Railcar leases

 

$

2.1

 

$

1.0

 

$

0.7

 

$

0.2

 

$

0.2

 

Terminal leases

 

3.3

 

0.4

 

0.8

 

0.6

 

1.5

 

Ports of Indiana wharfage

 

4.6

 

0.3

 

0.5

 

0.6

 

3.2

 

Headquarters building lease

 

1.2

 

0.3

 

0.3

 

0.3

 

0.3

 

Headquarters furniture and equipment lease

 

0.3

 

0.3

 

 

 

 

Mt. Vernon Lease

 

6.2

 

0.4

 

0.7

 

0.7

 

4.4

 

IT Services and Licenses

 

1.4

 

0.4

 

0.9

 

0.1

 

 

Coal Contracts

 

11.4

 

11.4

 

 

 

 

Natural Gas

 

18.7

 

1.8

 

1.8

 

1.9

 

13.2

 

Denaturant

 

0.5

 

0.5

 

 

 

 

Corn

 

5.5

 

5.5

 

 

 

 

Commitments for Capital Expenditures

 

0.4

 

0.4

 

 

 

 

Master Development Agreement (1)

 

4.2

 

1.7

 

2.5

 

 

 

Total Contractual obligations

 

$

59.8

 

$

24.4

 

$

8.2

 

$

4.4

 

$

22.8

 

 


(1)          If the Aurora West facility is completed prior to July 2012, this commitment will be reduced.

 

Secured Revolving Credit Facility

 

As of December 31, 2009, $9.6 million in letters of credit and $27.8 million in revolving loans were outstanding under our pre-petition amended secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent and a lender.  As a result of our Bankruptcy Filing, all the commitments under the Company’s pre-petition secured revolving credit facility automatically terminated, and the principal of the loans and the reimbursement obligations then outstanding, together with accrued interest thereon and any unpaid fees and all other obligations of the borrowers accrued under the applicable loans documents, became immediately due and payable, subject to the automatic stay provisions of Section 362 of the Bankruptcy Code.  As a result, there is no longer any liquidity available to us under this facility.  Amounts owed under the Company’s pre-petition secured revolving credit facility have not been included in “pre-petition liabilities subject to compromise” as the secured debt is adequately collateralized.  The Secured Revolving Credit Facility is collateralized by a first security lien on essentially all of the Company’s assets, except for assets at the Mt. Vernon, Indiana facility.  The Company continues to accrue and pay interest on this credit facility in accordance with the Bankruptcy Court’s final debtor-in-possession financing order.  As of December 31, 2009, the Company holds a restricted cash account totaling $7.0 million providing collateral protection to the pre-petition lenders for certain outstanding letters of credit issued under this facility as provided for in a stipulation agreement among the Company, its pre-petition secured lenders, and the DIP Facility lenders.

 

Prior to our bankruptcy filing, availability under the secured revolving credit facility was determined via a borrowing base, which included a percentage of eligible receivables and inventory, and no more than $10 million of property, plant and equipment.  Effective with the bankruptcy petition date, and related automatic termination of commitments as discussed above, the Company has no borrowing availability under its secured revolving credit facility.

 

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Prior to our bankruptcy filing, borrowings on the amended facility generally bore interest, at our option, at the following rates (i) the Eurodollar rate or the LIBO rate plus a margin of 4.5%, with a LIBO rate minimum of 3%, or (ii) the greater of the prime rate or the federal funds rate plus 0.50% (with a minimum rate of LIBO rate plus 2.25%), plus a margin of 3.25%.  In addition, the following fees were also applicable:  an unused commitment fee of 0.50% on unused borrowing availability, an outstanding letters of credit fee of 4.625%, and administrative and legal costs.

 

Effective on the Petition Date, the interest rate on the revolving credit facility loan reverted to a default rate of 10.5% per annum, while fees for outstanding letters of credit reverted to a default rate of 6.625% per annum.  Accrued interest and other fees are payable monthly.

 

Environmental Matters

 

We are subject to extensive federal, state and local environmental laws, regulations and permit conditions (and interpretations thereof), including those relating to the discharge of materials into the air, water and ground, the generation, storage, handling, use, transportation and disposal of hazardous materials, and the health and safety of our employees.  These laws, regulations, and permits require us to incur significant capital and other costs, including costs to obtain and maintain expensive pollution control equipment.  They may also require us to make operational changes to limit actual or potential impacts to the environment.  A violation of these laws, regulations or permit conditions can result in substantial fines, natural resource damages, criminal sanctions, permit revocations and/or facility shutdowns.  In addition, environmental laws and regulations (and interpretations thereof) change over time, and any such changes, more vigorous enforcement policies or the discovery of currently unknown conditions may require substantial additional environmental expenditures.

 

We are also subject to potential liability for the investigation and cleanup of environmental contamination at each of the properties that we own or operate and at off-site locations where we arranged for the disposal of hazardous wastes.  For instance, soil and groundwater contamination has been identified in the past at our Illinois campus.  If any of these sites are subject to investigation and/or remediation requirements, we may be responsible under the Comprehensive Environmental Response, Compensation and Liability Act or other environmental laws for all or part of the costs of such investigation and/or remediation, and for damages to natural resources.  We may also be subject to related claims by private parties alleging property damage or personal injury due to exposure to hazardous or other materials at or from such properties.  While costs to address contamination or related third-party claims could be significant, based upon currently available information, we are not aware of any material liability relating to contamination or such third party claims.  We have not accrued any amounts for environmental matters as of December 31, 2009.  The ultimate costs of any liabilities that may be identified or the discovery of additional contaminants could adversely impact our results of operation or financial condition.

 

In addition, the hazards and risks associated with producing and transporting our products (such as fires, natural disasters, explosions, abnormal pressures and spills) may result in releases of hazardous substances, and may result in claims from governmental authorities or third parties relating to actual or alleged personal injury, property damage, or damages to natural resources.  We maintain insurance coverage against some, but not all, potential losses caused by our operations. Our coverage includes, but is not limited to, physical damage to assets, employer’s liability, comprehensive general liability, automobile liability and workers’ compensation.  We do not carry environmental insurance.  We believe that our insurance is adequate for our industry, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage.  The occurrence of events which result in significant personal injury or damage to our property, natural resources or third parties that is not covered by insurance could have a material adverse impact on our results of operations and financial condition.

 

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Our air emissions are subject to the federal Clean Air Act, as amended, and similar state laws which generally require us to obtain and maintain air emission permits for our ongoing operations as well as for any expansion of existing facilities or any new facilities.  Obtaining and maintaining those permits requires us to incur costs, and any future more stringent standards may result in increased costs and may limit or interfere with our operating flexibility.  In addition, the permits ultimately issued may impose conditions which are more costly to implement than we had anticipated.  These costs could have a material adverse effect on our financial condition and results of operations.  Because other ethanol manufacturers in the U.S. are and will continue to be subject to similar laws and restrictions, we do not currently believe that our costs to comply with current or future environmental laws and regulations will adversely affect our competitive position among domestic producers.  However, because ethanol is produced and traded internationally, these costs could adversely affect us in our efforts to compete with foreign producers not subject to such stringent requirements.

 

Federal and state environmental authorities have been investigating alleged excess VOC emissions and other air emissions from many U.S. ethanol plants, including our Illinois facilities.  The investigation relating to our Illinois wet mill facility is still pending, and we could be required to install additional air pollution control equipment or take other measures to control air pollutant emissions at that facility.  If authorities require us to install controls, we would anticipate that costs would be higher than the approximately $3.4 million we incurred in connection with a similar matter at our Nebraska facility due to the larger size of the Illinois wet mill facility.  In addition, if the authorities determine our emissions were in violation of applicable law, we would likely be required to pay fines that could be material.

 

We have made, and expect to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits, including compliance with the U.S. Environmental Protection Agency’s (“EPA”) National Emissions Standard for Hazardous Air Pollutants, or NESHAP, for industrial, commercial and institutional boilers and process heaters.  This NESHAP was issued but subsequently vacated.  The vacated version of the rule required us to implement maximum achievable control technology at our Illinois wet mill facility to reduce hazardous air pollutant emissions from our boilers.  We expect the EPA will revise the rule to impose more stringent requirements than were contained in the vacated version.  In the absence of a final EPA NESHAP for industrial, commercial and institutional boilers and process heaters, we are working with state authorities to determine what technology will be required at our Illinois wet mill facility and when such technology must be installed.  We currently cannot estimate the amount that will be needed to comply with any future federal or state technology requirement regarding air emissions from our boilers.

 

We currently generate revenue from the sale of carbon dioxide, which is a co-product of the ethanol production process at each of our Illinois and Nebraska facilities.  New laws or regulations relating to the production, disposal or emissions of carbon dioxide may require us to incur significant additional costs and may also adversely affect our ability to continue generating revenue from carbon dioxide sales.

 

See Note 19 of Notes to Consolidated Financial Statements and “Subsequent Events” for more information on our environmental commitments and contingencies.

 

Market Risks

 

We are exposed to various market risks, including changes in commodity prices and interest rates.  Market risk is the potential loss arising from adverse changes in market rates and prices.  In the ordinary course of business, we enter into various types of transactions involving financial instruments to manage and reduce the impact of changes in commodity prices and interest rates.

 

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Commodity Price Risks

 

We are subject to market risk with respect to the price and availability of corn, the principal raw material we use to produce ethanol and ethanol by-products.  In general, rising corn prices result in lower profit margins and, therefore, represent unfavorable market conditions.  This is especially true when market conditions do not allow us to pass along increased corn costs to our customers.  The availability and price of corn is subject to wide fluctuations due to unpredictable factors such as weather conditions, farmer planting decisions, governmental policies with respect to agriculture and international trade, and global demand and supply.  Our weighted-average gross corn costs for the years ended December 31, 2009 and 2008 were $3.87 and $5.02 per bushel, respectively.

 

We have firm-price purchase commitments with some of our corn suppliers under which we agree to buy corn at a price set in advance of the actual delivery of that corn to us.  Under these arrangements, we assume the risk of a decrease in the market price of corn between the time this price is fixed and the time the corn is delivered.  At December 31, 2009, we had firm-price purchase commitments to purchase 1.4 million bushels of corn at an average fixed price of $3.95 per bushel for delivery through December 2010.  We have elected to account for these transactions as normal purchases under ASC 815, and accordingly, have not marked these transactions to market.

 

In order to reduce our market exposure to price decreases, at the time we enter into a firm-price purchase commitment, we also often enter into commodity futures contracts to sell a like amount of corn at the then-current price for delivery to the counterparty at a later date.  However, at December 31, 2009, we were not party to any commodity futures contracts to hedge our risk with respect to corn price decreases.  When we have these types of commodity futures contracts, we account for them under ASC 815.  These futures contracts are not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income.  The fair value of these derivative contracts are recognized in other current assets in the Consolidated Balance Sheet, net of any cash paid to brokers.  Information on this type of derivative transaction is as follows:

 

 

 

Year Ended December 31,

 

(In millions)

 

2009

 

2008

 

 

 

 

 

 

 

Realized and unrealized net gain included in earnings

 

$

1.2

 

$

10.5

 

 

 

 

December 31,

 

(In millions)

 

2009

 

2008

 

 

 

 

 

 

 

Net bushels sold

 

0.0

 

5.0

 

Aggregate notional value of derivatives outstanding

 

$

0.0

 

$

26.7

 

Period through which derivative positions currently exist

 

N/A

 

December 2009

 

Unrealized gain on fair value of derivatives

 

$

0.0

 

$

6.0

 

The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value

 

$

0.0

 

$

(2.1

)

 

We also periodically enter into commodity futures contracts in connection with the purchase of corn to reduce our risk of future price increases.  We account for these transactions under ASC 815.  These futures contracts are not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income.  The fair value of these derivative contracts are recognized in other current assets in the Consolidated Balance Sheet, net of any cash received from the brokers.  At December 31, 2009, we were not party to any such commodity futures contracts to reduce our risk of future corn price increases.  Information on this type of derivative transaction is as follows:

 

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Year Ended December 31,

 

(In millions)

 

2009

 

2008

 

 

 

 

 

 

 

Realized and unrealized net gain included in earnings

 

$

0.0

 

$

7.9

 

 

 

 

December 31,

 

(In millions)

 

2009

 

2008

 

 

 

 

 

 

 

Net bushels bought

 

 

 

Aggregate notional value of derivatives outstanding

 

$

 

$

 

Period through which derivative positions currently exist

 

N/A

 

N/A

 

Unrealized gain on fair value of derivatives

 

$

 

$

 

The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value

 

$

 

$

 

 

We are also subject to market risk with respect to ethanol pricing.  Our ethanol sales are priced using contracts that can either be based upon a fixed price; based upon the price of wholesale gasoline plus or minus a fixed amount; or based upon a market price at the time of shipment.  We sometimes fix the price at which we sell ethanol using fixed price physical delivery contracts.  At December 31, 2009, we had no fixed-price contracts to sell ethanol.  When we have fixed-price contracts, we account for these transactions as normal sales under ASC 815, and accordingly, mark these transactions to market.

 

From time to time, we also sell forward ethanol using contracts where the price is determined at a point in the future based upon an index plus or minus a fixed amount.  At December 31, 2009, we had not sold forward any ethanol using wholesale gasoline as an index plus a fixed spread.  When we have  these arrangements, we assume the risk of a price decrease in the market price of gasoline.  In order to reduce our market exposure to price decreases, at the time we enter into a firm sales commitment, we may also enter into commodity forward contracts to sell a like amount of gasoline at the then-current price for delivery to the counterparty at a later date.  We account for these transactions under ASC 815.  These forward contracts are not designated as hedges and, therefore, are marked to market each period, with corresponding gains and losses recorded in other non-operating income.  The fair value of these derivative liabilities is recognized in other current liabilities in the Condensed Consolidated Balance Sheet, net of any cash paid to brokers.  Information on this type of derivative transaction is as follows:

 

 

 

Year Ended December 31,

 

(In millions)

 

2009

 

2008

 

 

 

 

 

 

 

Realized and unrealized net loss included in earnings

 

$

0.0

 

$

1.3

 

 

 

 

December 31,

 

(In millions)

 

2009

 

2008

 

 

 

 

 

 

 

Gallons sold

 

 

 

Aggregate notional value of derivatives outstanding

 

$

 

$

 

Period through which derivative positions currently exist

 

N/A

 

N/A

 

Unrealized loss on fair value of derivatives

 

$

 

$

 

The change in fair value due to the effect of a 10% adverse change in commodity prices to current fair value

 

$

 

$

 

 

We may also be subject to market risk with respect to our supply of natural gas which is consumed during the production of ethanol and its co-products and has historically been subject to volatile market conditions.  Natural gas prices and availability are affected by weather conditions, overall economic conditions and foreign and domestic governmental regulation.  The price fluctuation in natural gas prices

 

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over the ten year period from January 1, 2000 through December 2009, based on the New York Mercantile Exchange daily futures data, has ranged from a low of $1.83 per MMBtu in September 2001 to a high of $15.82 per MMBtu in 2005. Natural gas costs comprised 17.9% and 24.2%, respectively, of our total conversion costs for the years ended December 31, 2009 and 2008.

 

At December 31 2009, we had purchased forward 134,700 MMBtu’s of natural gas at an average fixed price of $6.19 per MMBtu through the first quarter of 2010.  We have elected to account for these transactions as normal purchases under ASC 815 and accordingly, have not marked these transactions to market.  Based upon our annual average estimated natural gas usage and the December 31, 2009 year end price of natural gas of $5.57 per MMBtu, a 10% increase in natural gas prices would negatively affect our results of operations by approximately $1.9 million.

 

Material Limitations

 

The disclosures with respect to the above noted risks do not take into account the underlying commitments or anticipated transactions.  If the underlying items were included in the analysis, the gains or losses on the futures contracts may be offset.  Actual results will be determined by a number of factors that are not generally under our control and could vary significantly from those results disclosed.

 

We are exposed to credit losses in the event of nonperformance by counterparties on the above instruments, as well as credit or performance risk with respect to our hedged commitments. Although nonperformance is possible, we do not anticipate nonperformance by any of these parties.

 

Subsequent Events

 

On February 3, 2010 the U.S. Environmental Protection Agency announced final revisions to the National Renewable Fuel Standard program (commonly known as the RFS program or RFS-2). This Rule makes changes to the Renewable Fuel Standard program as required by the Energy Independence and Security Act of 2007 (EISA). The revised statutory requirements establish new specific annual volume standards for cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel that must be used in transportation fuel. The revised statutory requirements also include new definitions and criteria for both renewable fuels and the feedstock used to produce them, including new greenhouse gas emission (GHG) thresholds as determined by lifecycle analysis.  The regulatory requirements for RFS-2 will apply to domestic and foreign producers and importers of renewable fuel used in the U.S.

 

This final action is intended to lay the foundation for achieving significant reductions of greenhouse gas emissions from the use and creation of renewable fuels, reductions of imported petroleum and further development and expansion of our nation’s renewable fuels sector.

 

This Rule sets the 2010 RFS volume standard at 12.95 billion gallons (bg). Further, for the first time, the EPA is setting volume standards for specific categories of renewable fuels including cellulosic, biomass-based diesel, and total advanced renewable fuels. For 2010, the cellulosic standard is set at 6.5 million gallons (mg); and the biomass based diesel standard is set at 1.15 bg, (combining the 2009 and 2010 standards as proposed).

 

In order to qualify for these new volume categories, fuels must demonstrate that they meet certain minimum greenhouse gas reduction standards, based on a lifecycle assessment, in comparison to the petroleum fuels they displace.  Generally, ethanol plants either must meet the 20% reduction test or are grandfathered under special provisions.  For plants under construction on which construction commenced prior to December 19, 2007 (including the company’s Mt. Vernon and Aurora-West plants under construction) the plants must be completed within 36 months in order to meet the requirements to be

 

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grandfathered or comply with the GHG reduction standards which require the use of Advanced Technologies defined by the regulations.  The Company is currently researching alternatives to assure these plants are compliant.

 

On February 23, 2010 the Board of Directors passed a resolution terminating the 2003 Stock Incentive Plan effective at the close of business on February 23, 2010.  If the proposed Plan of Reorganization is confirmed, all outstanding stock and option awards made under the 2003 Stock Incentive Plan will be cancelled on the Effective Date of emergence from bankruptcy.

 

Impact of Recently Issued Accounting Standards

 

See Note 3, Summary of Critical Accounting Policies - Recent Accounting Pronouncements, of the Notes to Consolidated Financial Statements.

 

Item 7A.  Quantitative and Qualitative Disclosures about Market Risk

 

The information required by this item is contained in “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations” and is incorporated herein by reference.

 

Item 8.  Financial Statements and Supplementary Data

 

 

Page

Consolidated Statements of Operations — For the years ended December 31, 2009, 2008 and 2007.

F-1

Consolidated Balance Sheets — December 31, 2009 and 2008.

F-2

Consolidated Statements of Stockholders’ Equity (Deficit) — For the years ended December 31, 2009, 2008 and 2007.

F-3

Consolidated Statements of Cash Flows — For the years ended December 31, 2009, 2008 and 2007.

F-4

Notes to Consolidated Financial Statements.

F-5

Report of Independent Registered Public Accounting Firm.

F-39

Report of Independent Registered Public Accounting Firm.

F-40

 

Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

None

 

Item 9A.  Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

Under the supervision of, and with the participation of management, including our Interim Chief Executive Officer, George T. Henning, Jr. who is also currently serving as our Interim Chief Financial Officer, the Company carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this report.  Based upon that evaluation, Mr. Henning has concluded that, as of the end of the period covered by this report, the Company’s disclosure controls and procedures have been designed and are effective to provide reasonable assurance that information required to be disclosed in the reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission.  These disclosure controls and procedures include, without

 

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limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed in such reports is accumulated and communicated to our management, including Mr. Henning, as appropriate to allow timely decisions regarding the required disclosure.  The design of any system of controls is based in part upon certain assumptions about the likelihood of future events.  There can be no assurance that any design will succeed in achieving its stated goal under all potential future conditions, regardless of how remote.

 

Changes in Internal Control over Financial Reporting

 

Based upon the evaluation performed by our management, which was conducted with the participation of Mr. Henning, there has been no change in our internal control over financial reporting during the fourth quarter of 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

Management’s Report on Internal Control over Financial Reporting

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a—15(f).  Management, with the participation of Mr. Henning, assessed the effectiveness of our internal control over financial reporting as of December 31, 2009.  In making this assessment, management used the framework set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based upon this assessment, our management concluded that, as of December 31, 2009, our internal control over financial reporting was effective to provide reasonable assurance that the desired control objectives were achieved.

 

The effectiveness of internal control over financial reporting has been audited by Ernst & Young LLP, independent registered public accounting firm, as stated in their report on page F-42 included in this 10-K.

 

Inherent Limitation of the Effectiveness of Internal Control

 

A control system, no matter how well conceived and operated, can only provide reasonable, not absolute, assurance that the objectives of the internal control system are met.  Because of the inherent limitations of any internal control system, no evaluation of controls can provide absolute assurance that all control issues, if any, within a company have been detected.

 

Item 9B.  Other Information

 

None.

 

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PART III

 

Item 10.  Directors and Executive Officers of the Registrant

 

The following table contains information regarding our current directors and executive officers.  Directors hold office until their terms expire and their successors have been elected and qualified.  Executive officers hold their positions until the annual meeting of the Board of Directors (the “Board”) or until their respective successors are elected and qualified.  The proposed Plan of Reorganization contemplates that Reorganized Aventine will amend and restate its certificate of incorporation and amend and restate its bylaws.  In addition, the proposed Plan of Reorganization contemplates the replacement of the members of the current Board.  The information contained in this Item 10 relates to our current directors and executive officers.

 

Name

 

Age

 

Position

 

 

 

 

 

George T. Henning, Jr.

 

68

 

Interim Chief Executive Officer and President Interim Chief Financial Officer

Daniel R. Trunfio, Jr.

 

49

 

Chief Operating Officer

 

 

 

 

 

Bobby L. Latham

 

69

 

Chairman of the Board of Directors

Theodore H. Butz

 

51

 

Director

Farokh S. Hakimi

 

61

 

Director and Chairman of the Audit Committee

Richard A. Derbes

 

63

 

Director

Michael C. Hoffman

 

47

 

Director

Arnold M. Nemirow

 

66

 

Director

Leigh J. Abramson

 

41

 

Director and Chairman of the Nominating and Governance Committee

Wayne D. Kuhn

 

74

 

Director and Chairman of the Compensation Committee

 

Our charter and bylaws provide for a Board comprised of between three and eleven directors divided into three classes of directors serving staggered three-year terms.  Each class shall consist, as nearly as possible, of one-third of the total number of directors constituting the entire Board.  Directors serve staggered terms ending on the third annual meeting of stockholders following the annual meeting at which the director was elected.  Even though the term for certain of these Directors would have otherwise expired under the foregoing staggered term arrangement, they remained in office pursuant to Company bylaw provisions providing that Directors shall serve until replaced.

 

Executive Officers

 

George T. Henning, Jr.  Mr. Henning was appointed as Interim Chief Executive Officer and President in October 2009.  Mr. Henning became our Interim Chief Financial Officer in March 2009.  Mr. Henning is a retired financial executive with over 35 years of senior financial management experience, including previous positions with Eastern Gas and Fuel Associates, LTV Corporation and its predecessor companies, and Pioneer Americas Company.  Mr. Henning holds an MBA from Harvard University and a BA from Pennsylvania State University.  Mr. Henning serves as a member of the Board of Trustees of the Pennsylvania State University.

 

Daniel R. Trunfio, Jr.  Mr. Trunfio has been our Chief Operating Officer since March 2007. Prior to joining Aventine, Mr. Trunfio spent 23 years with the Royal Dutch Shell Group in various leadership roles including General Manager and Vice President. Shell is one of the largest bio-fuels marketers in the world and a recognized global leader in second generation bio-fuels technology. Mr. Trunfio most recently led the development and implementation of Shell’s first and second generation bio-fuel strategies and operations

 

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worldwide. In this role, Mr. Trunfio was responsible for coordinating bio-fuel issues for Shell in the Americas working as a liaison with external stakeholders and governments. In addition, he was also responsible for managing Shell’s bio-fuel alliances in the Americas. While at Shell, Mr. Trunfio’s experience included positions (both domestic and internationally) in retail sales, marketing, supply, trading, e-commerce, strategy, product development and bio-fuels.

 

Directors

 

Bobby L. Latham.  Mr. Latham has been Chairman of the Board since May 2003.  He is currently a Managing Director of Amaryn Group LLC, a partnership formed to explore investment opportunities in the chemical and manufacturing industries.  From 1995 to 2000, Mr. Latham served as a consultant to MSLEF II portfolio companies.  From 1994 to 1995, he served as a Senior Vice President at Terra Nitrogen Corp.  From 1991 to 1994, Mr. Latham served as Chief Operating Officer of Beaumont Methanol Corp.  From 1990 to 1994, he served as Chief Operating Officer of Agricultural Minerals Corp. Mr. Latham has twenty-three years experience in methanol and fertilizer manufacturing as well as significant experience in strategic and operational planning.  He has also worked with the MSCP funds in evaluating numerous investment opportunities.  Mr. Latham is also a director of Terphane, a manufacturer of special polyester films.

 

Theodore H. Butz.  Mr. Butz has been a director since September 2008.  Mr. Butz is currently Vice President and General Manager, Specialty Chemicals Group for FMC Corporation, a global chemical company.  He has been FMC’s Vice President, Specialty Chemicals Group since 2003 and is responsible for specialty chemicals businesses.  The Specialty Chemicals Group supplies the food, pharmaceutical, polymers and energy storage markets.  In addition to his general management responsibility, he also leads FMC’s corporate development and health and safety functions.  He has held various management positions at FMC Corporation since beginning with them in 1991.

 

Farokh S. Hakimi.  Mr. Hakimi has been a director since May 2006.  Since July 2008, he  has held the position of President of Hakimi Investments, a Toronto-based private investment firm.  He is responsible for all of its investment activities.  From August 2006 until July 2008, he held the position of President and CEO of Viridian Resources, LLC, a private US-based start-up company involved in development of new technology for recovery of nickel and cobalt from low grade deposits. Prior to that, he was Executive Vice President of Inco Limited, a mining and metal company, from November 2005 until March 2006. From March 2002 until November 2005, he served as Executive Vice President and Chief Financial Officer, having previously served as Inco’s Chief Development Officer from January 2002 until March 2002.  Mr. Hakimi was Vice President and Chief Financial Officer of Rio Algom Limited, a global mining and metals company based in Toronto, Ontario from January 2000 until July 2001.

 

Richard A. Derbes.  Mr. Derbes has been a director since May 2003.  He was head of Morgan Stanley’s Investment Banking client coverage for the Chemical Industry from 1986 until he retired in December 2001 (except for about a year and a half in 1993-1994, when he was with Gleacher & Co.).  Prior to that, he was a sell-side equity research analyst for Morgan Stanley and other investment banks, from 1976 until 1985.  He was a member of the Institutional Investor All-American Team for the chemical industry for nine years.  Mr. Derbes has been an advisor to the MSCP funds on numerous chemical investment opportunities.

 

Michael C. Hoffman.  Mr. Hoffman has been a director since May 2003.  He is a Managing Director of Metalmark Capital LLC and a Managing Director of Citi Capital Advisors.  He joined Morgan Stanley & Co. Incorporated in 1986 and worked in the firm’s Strategic Planning Group prior to joining Morgan

 

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Stanley Capital Partners in 1990.  Mr. Hoffman is a Director of  HDT Engineered Technologies and MBA Polymers.  Mr. Hoffman was previously a director of Enfor Systems.

 

Arnold M. Nemirow.  Mr. Nemirow has been a director since March 2007.  Mr. Nemirow retired in 2006 as Chairman, President and Chief Executive Officer of Bowater Incorporated, a major producer of forest products, based in Greenville, South Carolina.  He became Chief Executive Officer of Bowater in 1995 and Chairman in 1996. He served as President of Bowater beginning in September 1994 and served as Chief Operating Officer of Bowater from September 1994 through February 1995.

 

Leigh J. AbramsonMr. Abramson has been a director since May 2003.  He is a Managing Director of Metalmark Capital LLC and a Managing Director of Citi Alternative Investments, Inc.  He joined Morgan Stanley in 1990 and Morgan Stanley Capital Partners in 1992.  Mr. Abramson is a director of several private companies.

 

Wayne D. Kuhn.  Mr. Kuhn has been a director since May 2003.  He was a partner in Sorgenti Investment Partners, a chemical expertise group that explores investment opportunities in the chemical industry, from 1997 to 2007.  He is currently engaged as a consultant in the chemical industry.  Mr. Kuhn spent 30 years at Arco and was instrumental in developing Arco’s position as the world’s largest manufacturer of MTBE, a gasoline additive.  He retired as Vice President of Arco where he was in charge of a $3 billion worldwide business which included Arco’s commodity chemicals for the urethane industry as well as specialty chemicals.

 

Section 16(a) Beneficial Ownership Reporting Compliance

 

The members of the Board, our executive officers and persons who hold more than ten percent of our common stock are subject to the reporting requirements of Section 16(a) of the Securities Exchange Act of 1934, as amended, which require them to file reports of beneficial ownership and changes in beneficial ownership of our equity securities and to furnish us with copies of all reports they file.  Based solely upon our review of the copies of such reports received by us and written representations from our executive officers and directors, we believe that, for the fiscal year ended December 31, 2009, all required reports were filed timely except that Mr. Trunfio’s report for an employment contract stock option grant was filed approximately one week late due to bankruptcy filing activities.

 

Corporate Governance

 

The charters of the Compensation Committee, Audit Committee and Nominating and Corporate Governance Committee, as well as our Corporate Governance Guidelines and our Code of Business Conduct and Ethics that applies to our directors, officers and employees (including our chief executive officer, chief financial officer, principal accounting officer, controller or other persons performing similar functions), are available on our website (www.aventinerei.com) or in print upon written request at no charge.  If we amend or grant any waivers under the code that are applicable to our chief executive officer, our chief financial officer, or our chief accounting officer and that relate to any element of the SEC’s definition of a code of ethics, which we do not anticipate doing, we will promptly post that amendment or waiver on our website, www.aventinerei.com, under “Corporate Governance.”

 

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Item 11.  Executive Compensation

 

Compensation Discussion and Analysis

 

Executive Compensation Program Objectives

 

On April 7, 2009, the Company and its subsidiaries filed voluntary petitions for reorganization relief under the provisions of Chapter 11 of Title 11 of the U.S. Code in the U.S. Bankruptcy Court for the District of Delaware.  Therefore in fiscal year 2009, the long-term objectives of our compensation programs were constrained by our Chapter 11 filing in order to conserve cash and maintain the operations and compliance activities of the Company .  There were no increases in the base salaries of our executives other than those associated with Mr. Henning assuming the additional role of Interim CEO and President and Mr. Trunfio assuming additional responsibilities upon the departure of our former CEO and President, Mr. Ronald Miller.  In addition, other than the Key Employee Incentive Plan discussed below there were no short or long-term bonus plans initiated in 2009.

 

Target Competitive Positioning

 

Historically our compensation programs have been designed to link pay to performance.  Aside from base salaries, all other compensation components have been tied to performance.  In the past we positioned target base salaries and total direct compensation opportunities between the 25th percentile and median of our comparator group to recognize that Aventine is smaller than the typical peer company.  In the past we structured our programs to provide the appropriate balance between cash and equity compensation, and short-term and long-term incentives, to further the program objectives identified above. However, due to the bankruptcy filing on April 7, 2009 there were no regular annual increases in base salaries awarded and there were no short or long-term incentive plans established for 2009.

 

The loss of any of our officers could have a material adverse effect upon our results of operations and our financial position and could delay or prevent the achievement of our business objectives.  Our ability to develop and successfully consummate a plan of reorganization is highly dependent upon the skills, experience and effort of our senior leadership and other personnel.  Our ability to attract, motivate and retain key employees is restricted, however, by provisions of the Bankruptcy Code, which limit or prevent our ability to implement a retention program or take other measures intended to motivate key employees to remain with the Company during the pendency of the Chapter 11 proceedings.  In addition, we may be required to obtain Bankruptcy Court approval of employment contracts and other employee compensation programs.  The loss of the services of one or more members of our senior leadership or certain employees with critical skills, or a diminution in our ability to attract talented, committed individuals to fill vacant positions when needs arise, could have a material adverse effect on our ability to successfully reorganize and emerge from bankruptcy.

 

To help insure that certain members of the senior leadership and management team are and remain properly motivated to undertake the substantial efforts that will be required of them to complete the necessary negotiations with various creditor constituencies in order to formulate and propose a Chapter 11 plan and to emerge from Chapter 11 in the first quarter of 2010, the Company has adopted the Aventine Renewable Energy, Inc. and Affiliates Key Executive Incentive Plan (the “KEIP”), which was approved by the Bankruptcy Court through an order dated December 15, 2009.

 

The KEIP is designed to provide certain senior executives and managers of the Company (collectively, the “Eligible Employees”) with appropriate incentives in order to maximize their efforts to aid in the negotiation, formulation, and consummation of the Chapter 11 plan, and to motivate the Eligible

 

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Employees to continue effectively managing the Debtors’ operations and minimize expenditures during the Chapter 11 plan process.

 

The KEIP is limited to eight employees and a maximum total payout of $346,662, including one named executive officer, Mr. Dan Trunfio whose maximum bonus under the plan is $117,000.  Pursuant to the KEIP, each of the eligible employees may be entitled to an incentive bonus payment if the Company meets or exceeds certain specified targets, relating to cash position, production level, and the date on which we emerge from bankruptcy.  These targets were designed to be challenging, but attainable.

 

Below is a summary of the plan components, the targets and the incentive payments available for meeting each target:

 

Plan Components

 

% Weighting of maximum
incentive bonus

 

Target

1.

Cash Position

 

30%

 

90% or greater of the planned cash position at emergence

2.

Production Level

 

40%

 

Production level at emergence equal to or above 105% of plan

3.

Emergence Date

 

30%

 

March 31, 2010

 

Unless terminated “without cause,” the eligible employees must be employed by the Company as of the effective date of a Chapter 11 plan or the closing of a sale of substantially all of the Company’s assets in order to receive any payments under the KEIP.

 

Compensation Committee Procedure and the Compensation Consultant

 

The Compensation Committee of the Board is responsible for determining the nature and amount of compensation for Aventine’s executive officers and directors.  The Compensation Committee consists of three non-employee directors: Wayne D. Kuhn (Chair), Leigh J. Abramson, and Arnold M. Nemirow.  The charter of the Compensation Committee gives the Compensation Committee the ability to delegate its authority to subcommittees or the Chairman of the Compensation Committee when it deems appropriate and in the interest of Aventine.  The Compensation Committee does not, however, delegate its authority with respect to named executive officer (“NEO”) compensation.

 

Since 2006, the Compensation Committee has periodically engaged Frederic W. Cook & Co. (“Cook”) as its independent compensation consultant.  Cook does no work for management without the consent of the Compensation Committee chair, receives no compensation from Aventine other than for its work in advising the Compensation Committee, and maintains no other economic relationships with Aventine.  While the Compensation Committee values the advice of its independent consultant, the Compensation Committee may choose to take a different approach than that recommended by the consultant for various reasons.

 

In 2008, Cook performed an updated comprehensive review of Aventine’s executive compensation program in terms of design and compensation levels.  The review included a total direct compensation analysis for eight executive positions; a carried-interest ownership analysis for the five highest paid executives; and aggregate share usage, fair value transfer, and potential dilution analyses.  The results of the competitive review and Cook’s preliminary recommendations for the 2008 compensation program were presented and discussed at the July 31, 2008 Board meeting.  No such review was performed in 2009.

 

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Input of Executive Officers on Compensation

 

On an ongoing basis, the Compensation Committee receives input from the CEO on the personal performance achievements of the executives who report to him.  The evaluation of personal performance is made through a “Right Results — Right Way” analysis which each executive completes in conjunction with the CEO.  This individual performance assessment determines a portion of the annual compensation for each executive.  In addition, the CEO provides input on salary increases, incentive compensation opportunities, and long-term incentive grants for the executives who report to him, which the Compensation Committee considers when making executive compensation decisions.  The Compensation Committee does its own performance review of the CEO, and discusses it with the full Board.

 

In addition, management provides input into our compensation programs by establishing annual plans and budgets.  These are then reviewed and approved by the Board, as the performance goals used in our compensation programs are tied to these annual plans and budgets.

 

Compensation Elements

 

Our compensation program historically had the following elements:

 

·                  Base salary;

·                  Annual incentives (cash bonuses);

·                  Long-term incentives; and

·                  Benefits and perquisites.

 

Base Salary

 

Prior to the Chapter 11 Bankruptcy filing our policy has been to establish base salaries necessary to attract and retain executive level talent and to provide some minimum level of fixed compensation while reserving an incentive compensation component.  Our base salaries have been  reviewed annually and are generally targeted between the competitive 25th percentile and median, but may deviate from this competitive position based on the scope of the individual’s role in the organization, his or her level of experience in the current position and individual performance.

 

The Compensation Committee made a determination early in 2009 that no salary increases for 2009 would be approved at that time but that the matter could be revisited if conditions changed.  Ultimately only two increases were approved for Messrs. Henning and Trunfio as Mr. Henning assumed the additional role of Interim CEO and President and Mr. Trunfio assumed additional responsibilities upon the resignation of Mr. Miller, the former CEO and President.  Mr. Henning’s original compensation terms were established in March 2009 when he assumed the role of Interim Chief Financial Officer to guide the Company through the bankruptcy process.

 

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Base salary information for the NEOs is as follows:

 

Executive

 

2009
Starting
Salary

 

Current
2010
Salary

 

Ronald H. Miller

 

$

390,000

(1)

$

 

George T. Henning, Jr.

 

300,000

(2)

450,000

(3)

Daniel R. Trunfio, Jr.

 

315,000

 

390,000

(4)

Ajay Sabherwal

 

262,080

 

(5)

 


(1)             Represents Mr. Miller’s annualized 2009 salary.  Mr. Miller resigned his position effective October 23, 2009.

(2)             Represents Mr. Henning’s annualized 2009 salary.  Mr. Henning began employment effective March 16, 2009.

(3)             Mr. Henning’s salary was increased by the Compensation Committee effective October 24, 2009 in recognition of additional duties he has assumed as Interim CEO and President.

(4)             Mr. Trunfio’s salary was increased by the Board effective October 24, 2009 in recognition of additional duties he has assumed.

(5)             Represents Mr. Sabherwal’s annualized 2009 salary.  Mr. Sabherwal resigned his position effective March 13, 2009.

 

Annual Incentives

 

The Compensation Committee made the determination early in 2009 that no incentive plan would be established for 2009 but that the matter could be revisited if circumstances changed.  Ultimately, no incentive plan was implemented for 2009.

 

Long-Term Incentive Compensation

 

The Compensation Committee made the determination early in 2009 that a long-term incentive program for 2009 would not be established at that time but that this matter could be revisited if circumstances changed.  Ultimately, no long-term incentive plan was implemented for 2009.

 

Hiring of Interim Chief Executive Officer, President and Interim Chief Financial Officer

 

On March 9, 2009, the Board appointed George T. Henning, Jr. as Interim Chief Financial Officer of the Company.  The Board brought Mr. Henning in to assist the Company through the Chapter 11 bankruptcy process and, upon the resignation of Ajay Sabherwal, the former Chief Financial Officer, they appointed him Interim Chief Financial Officer.  Pursuant to an offer letter dated March 5, 2009 (the “Offer Letter”), Mr. Henning initially received an annual base salary of $300,000 and was eligible for a potential annual bonus as the Board may determine.  Mr. Henning receives the normal Company benefits for which he may be eligible and the Company pays all reasonable costs, including temporary living and transportation expenses and taxes thereon, related to his position of Interim Chief Financial Officer.  The Board established Mr. Henning’s compensation based upon his over 35 years experience in capital-intensive industries and his experience leading companies through the bankruptcy process.

 

On October 14, 2009, upon the resignation of Ronald Miller, the former Chief Executive Officer and President, the Board appointed Mr. Henning as Interim Chief Executive Officer and President of the Company, effective October 24, 2009, in addition to his role as Interim Chief Financial Officer.  In connection with his additional responsibilities the Board increased his salary to $450,000.  Mr. Henning’s offer letter does not provide for any special payments upon termination.

 

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Benefits and Perquisites

 

The NEOs participate in the same benefits programs as other Aventine employees, including health and dental insurance programs, group term life insurance, short-term disability coverage, business travel accident insurance, and our tax-qualified 401(k) plan.   We have no supplemental retirement plans or pension plans in which named executive officers participate.  We generally do not provide any executive perquisites.  However, we have paid relocation expenses (e.g., moving expenses, temporary living expenses) in connection with hiring new executives.  In the case of Mr. Henning we paid his temporary living and transportation expenses and applied a tax gross-up to keep him whole with respect to the reimbursement of these expenses.

 

Employment Agreements, Severance and Changes in Control

 

Other than the employment offer letter for Mr. Trunfio, we have no employment or severance agreements currently in place with any executive officer.  The terms provided for in Mr. Trunfio’s offer letter were what we deemed necessary to provide in order to recruit this executive and were established through arms-length negotiations.  For information regarding Mr. Trunfio’s offer letter, please see “Employment Offer Letter — Mr. Daniel R. Trunfio, Jr. Chief Operating Officer.”  We do not have a formal severance plan, nor do we have a change-in-control severance program.  However, if there is a “Sale of the Company” as defined in the 2003 Stock Plan as amended (the “Stock Plan”), all unvested stock options from grants made prior to March 19, 2007 will become vested.  Starting with grants made after March 19, 2007, the Stock Plan uses “double-trigger” vesting acceleration of equity grants upon a change-in-control.  That is, vesting of equity grants will only accelerate upon a change-in-control if the successor organization does not assume, convert or replace the awards, or if the participant is terminated without cause or resigns for “good reason” within 24 months of the change-in-control.  We believe the “double-trigger” vesting acceleration is fair to both employees and stockholders.  A double trigger supports stockholder interests by maintaining retention value and avoiding windfalls to executives whose jobs remain unaffected by a change in control, while still being fair to executives who are terminated without cause or whose equity compensation is cancelled by the successor organization.

 

Accounting Treatment of Awards

 

We account for stock-based employee compensation using the fair value based method of accounting described in ASC 718.  We record the cost of awards with service conditions (i.e., service-vesting stock options) based on the grant-date fair value of the award.  The cost of the awards is recognized over the period during which an employee is required to provide service in exchange for the award (i.e., the vesting period).  In the event of certain terminations of employment (resignation, termination without cause, etc.), no further compensation cost is recognized and the remaining unvested stock grant is cancelled.  We record the cost of awards with performance conditions (i.e., performance-shares) based on per-share grant-date fair value, with the ultimate expense based on the number of shares that are actually earned.  This expense is accrued based on our expectation of performance results as of each reporting date, and is being amortized over the performance period.

 

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Compensation Committee Report

 

The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis of the Company with management.  Based on the review and discussions, the Compensation Committee recommended to the Board of Directors, and the Board has approved, that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

 

 

Submitted by the Compensation Committee

 

 

 

Wayne D. Kuhn, Chairman

 

Leigh J. Abramson

 

Arnold M. Nemirow

 

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Summary Compensation Table

 

The following table sets forth the total compensation for certain of the Company’s current and former executive officers (the “NEOs”), including the President and CEO and the Chief Financial Officer for the years ended December 31, 2009, 2008 and 2007.

 

Name and Principal
Position

 

Year

 

Salary
($)

 

Bonus
($)

 

Stock
Awards
($)(6)

 

Option
Awards
($)(6)

 

Non-Equity
Incentive Plan
Compensation
($)(7)

 

Change in
Pension Value
And
Nonqualified
Deferred
Compensation
Earnings

 

All Other
Compensation
($)(8)

 

Total

 

(a)

 

(b)

 

(c)

 

(d)

 

(e)

 

(f)

 

(g)

 

(h)

 

(i)

 

(j)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

George Henning, Jr

 

2009

 

$

271,154

(3)

 

 

 

 

 

$

58,082

 

$

329,236

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interim CEO & CFO

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ronald Miller

 

2009

 

373,875

(4)

 

 

740,763

 

 

 

14,700

 

1,129,338

 

Former President

 

2008

 

383,654

 

 

 

1,191,300

 

51,371

 

 

24,415

 

1,650,740

 

& CEO

 

2007

 

353,846

 

 

44,798

 

1,108,088

 

31,245

 

 

26,992

 

1,564,969

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ajay Sabherwal

 

2009

 

80,673

(5)

 

 

(902,911

)

 

 

4,840

 

(817,398

)

Former CFO

 

2008

 

257,815

 

 

 

1,115,789

 

22,572

 

 

21,170

 

1,417,346

 

 

 

2007

 

245,654

 

 

27,066

 

1,558,014

 

15,184

 

 

21,781

 

1,867,699

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Daniel Trunfio

 

2009

 

341,538

 

 

200,000

 

426,033

 

 

 

19,057

 

986,628

 

COO

 

2008

 

308,654

 

 

200,000

 

416,078

 

27,023

 

 

83,762

 

1,035,517

 

 

 

2007

 

230,769

(1)

173,764

(2)

188,733

 

299,568

 

14,264

 

 

80,344

 

987,442

 

 


(1)             Mr. Trunfio began employment on March 19, 2007 and his compensation for 2007 is for a partial year.

(2)             Represents Mr. Trunfio’s signing bonus.

(3)             Mr. Henning began employment on March 16, 2009 as the Company’s Interim Chief Financial Officer.  Effective October 24, 2009, Mr. Henning became the Company’s Interim Chief Executive Officer and President, while retaining his duties as Interim Chief Financial Officer.

(4)             Mr. Miller resigned his position effective October 23, 2009.

(5)             Mr. Sabherwal resigned his position effective March 16, 2009.

(6)             The value shown under “Stock Awards” and “Option Awards” in the table above represents the dollar amount recognized for financial statement reporting purposes in accordance with ASC 718 with respect to each fiscal year, disregarding estimated forfeitures related to service-based vesting conditions.  The assumptions and methodology used to determine such amounts are set forth in Footnote 20 in our Notes to Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2009.

(7)             For 2007, represents each executive’s award under our annual bonus program with respect to each performance year.  Bonuses have not yet been paid for 2008 due to the bankruptcy filing and no bonus plan was in place for 2009.  For additional information regarding the Plan, see Compensation Discussion and Analysis — Compensation Elements — Annual Incentives.

(8)             All Other Compensation for 2009 consisted of:

 

Executive

 

401(k)
Company
Matching

 

Tax
Gross-up

 

Relocation
Expenses

 

2009
Total

 

Miller

 

$

14,700

 

 

 

$

14,700

 

Trunfio

 

14,700

 

 

4,357

 

19,057

 

Sabherwal

 

4,840

 

 

 

4,840

 

Henning

 

 

17,105

 

40,977

 

58,082

 

 

Other than an employment offer letter for Mr. Trunfio, we have no employment or severance agreements currently in place with any named executive officer.  Additional terms of the employment offer

 

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letter of Mr. Trunfio and relating to payments received upon the termination of employment are discussed below under “Potential Payments Upon Termination or Change-in-Control.”

 

Employment Offer Letter — Mr. Daniel R. Trunfio, Jr., Chief Operating Officer

 

Our employment offer letter to Mr. Daniel R. Trunfio, Jr., dated February 7, 2007, provides for at-will employment.  Pursuant to the offer letter, Mr. Trunfio’s starting annual base salary was $300,000.  Mr. Trunfio also received a signing bonus of $173,764 (intended to provide him $100,000, net of taxes).  Mr. Trunfio is eligible for equity grants in accordance with the Plan, and was granted an initial $1,000,000 in restricted stock and 200,000 non-qualified stock options on March 19, 2007.  These grants vest over a five-year period and the options have an exercise price equal to the closing price of Aventine’s common stock on the grant date.  These awards were provided, in part, to make up for benefits that Mr. Trunfio forfeited from his former employer when he left to join Aventine.  Pursuant to the offer letter terms, Mr. Trunfio was granted 50,000 non-qualified stock options on March 19, 2008 and March 19, 2009, each with five-year installment vesting and an exercise price equal to the closing price of Aventine’s stock on the grant date.  The letter also provides for Mr. Trunfio’s participation in Aventine’s Long-Term Incentive Plan and in other benefits programs available to employees and to senior executive officers of Aventine.

 

2009 Grants of Plan Based Awards

 

The following table sets forth new grants of plan-based awards and opportunities for awards under Incentive Plans in 2009:

 

 

 

 

 

Estimated Future Payouts Under
Non-Equity Incentive Plan Awards

 

Estimated Future Payouts Under
Equity Incentive Plan Awards

 

All Other
Stock
Awards:
Number of
Securities

 

Exercise
or Base
Price of
Option

 

Grant
Date
Fair
Value of

 

Name

 

Grant
Date

 

Threshold
($)

 

Target
($)

 

Maximum
($)

 

Threshold
(Shs)

 

Target
(Shs)

 

Maximum
(Shs)

 

Underlying
Options

 

Awards
($/sh)

 

Option
Awards

 

Daniel Trunfio

 

3/19/2009

 

 

 

 

 

 

 

50,000

 

$

0.18

(1)

$

5,150

 

 


(1)             Grant date fair value of stock options was calculated in accordance with ASC 718 using a form of the Black-Scholes option pricing model and the following assumptions:  $0.18 current share price and exercise price, 58% volatility, 0% dividend yield, 6.5 year expected term, and 4.57% risk free interest rate.  These options become exercisable in equal annual installments on the first five anniversaries of the grant date, or earlier upon a “Change in Control”, as defined in the Plan.  These options were granted on the anniversary of Mr. Trunfio’s date of hire, and have an exercise price which is the closing price of our stock on that date.  This option award, in combination with an initial restricted stock award, and other option awards made to Mr. Trunfio pursuant to the terms of his offer letter, was provided, in part, to make up for benefits that he forfeited from his former employer when he left to join Aventine in March 2007.

 

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2009 Outstanding Equity Awards at Fiscal Year-End

 

The following table sets forth the option and stock awards outstanding for Aventine’s NEOs as of December 31, 2009:

 

 

 

Option Awards

 

Stock Awards

 

Name

 

Number of
Securities
Underlying
Unexercised
Options
Exercisable
(#)

 

Number of
Securities
Underlying
Unexercised
Option
Unexercisable
(#)

 

Option
Exercise
Price ($)

 

Option
Expiration
Date

 

Number
of Shares
or Stock
Units That
Have Not
Vested (#)

 

Market
Value of
Shares or
Stock
Units
That Have
Not
Vested ($)

 

Equity
Incentive
Plan
Awards:
Number
of
Unearned
Shares,
Units or
Other
Rights
that Have
Not
Vested (#)

 

Equity
Incentive
Plan
Awards:
Market
Value or
Payout
Value of
Unearned
Shares,
Units or
Other
Rights
That Have
Not
Vested (#)

 

Ronald Miller

 

510,203

 

 

$

0.232

 

6/17/2013

(1)

 

 

$

 —

 

 

 

 

 

 

 

260,007

 

 

 

2.918

 

9/6/2015

(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Daniel Trunfio

 

80,000

 

120,000

 

15.260

 

3/19/2017

(1)

 

 

 

 

 

 

 

 

 

 

6,000

 

24,000

 

7.050

 

2/28/2018

(1)

 

 

 

 

 

 

 

 

 

 

10,000

 

40,000

 

4.800

 

3/19/2018

(1)

 

 

 

 

 

 

 

 

 

 

 

50,000

 

0.18

 

3/19/2009

(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

39,319

(2)

14,548

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

7,250

(3)

2,683

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

7,250

(4)

2,683

 

 


(1)          These stock options have ten-year terms and vest in equal annual installments on the first five anniversaries of the grant date.  The vesting schedules for Mr. Trunfio’s unvested awards are outlined below:

 

Name

 

# of
Options

 

Vesting Schedule

 

Trunfio

 

120,000

 

40,000 options vest on each of 3/19/10, 3/19/11, and 3/19/12

 

Trunfio

 

24,000

 

6,000 options vest on each of 2/28/10, 2/28/11, 2/28/12, 2/28/13

 

Trunfio

 

40,000

 

10,000 options vest on each of 3/19/10, 3/19/11, 3/19/12, 3/19/13

 

Trunfio

 

50,000

 

10,000 options vest on each of 3/19/10, 3/19/11, 3/19/12, 3/19/13, 3/19/14

 

 

(2)          Mr. Trunfio’s restricted shares vest in five equal annual installments starting one year from the date of grant of 3/19/07.

 

(3)          Represents the target number of performance shares outstanding under the 2007-2009 performance cycle.  The payout value of these shares is based upon the closing market price of our common stock on December 31, 2009, which was $0.37.  At December 31, 2009, we do not estimate that any amount will ultimately be paid out under this Plan.

 

(4) Represents the target number of performance shares outstanding under the 2007-2010 performance cycle.  The payout value of these shares is based upon the closing market price of our common stock on December 31, 2009, which was $0.37.   At December 31, 2009, we do not estimate that any amount will ultimately be paid out under this Plan.

 

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2009 Option Exercises and Stock Vested

 

The following table sets forth the stock options exercised for Aventine’s NEOs for the year ended December 31, 2009:

 

 

 

Option Awards

 

Stock Awards

 

Name

 

Number of
Shares
Acquired on
Exercise (#)

 

Value
Realized on
Exercise ($)

 

Number of
Shares
Equal on
Vesting (#)

 

Value
Realized on
Vesting ($)

 

Ronald H. Miller

 

85,000

 

$

10,252

 

0

 

$

0

 

Daniel Trunfio

 

0

 

0

 

13,106

 

2,359

 

 

Pension Benefits and Non-Qualified Deferred Compensation

 

We do not maintain any pension benefit plans or nonqualified deferred compensation plans for our salaried employees.

 

Potential Payments Upon Termination or Change in Control

 

The table below reflects the amount of compensation to each of the NEOs in the event of a termination related to a change in control, as a result of the accelerated vesting of unvested stock options, restricted shares, and performance shares.  The amounts shown assume termination was effective December 31, 2009 and assume a share price of $0.37, our closing share price on December 31, 2009, the last trading day of the calendar year.

 

NEO

 

Accelerated Vesting of
Unvested Equity
Compensation*

 

 

 

 

 

Daniel Trunfio

 

$

29,413

 

 


*                         Represents the intrinsic value of unvested stock options, unvested restricted shares, and the value of the target number of performance shares granted in 2007 and 2008, as of December 31, 2009, based on a share price of $0.37, our closing price on December 31, 2009.

 

Upon termination with cause, all options will be immediately forfeited.  Upon termination due to death or disability, vested options will remain exercisable for the earlier of one year or their original expiration date, and unvested options will be forfeited.  For all other terminations, vested options would remain exercisable for the earlier of 90 days or their original expiration date unless the employee has been granted a Board “approved retirement” in which case they remain exercisable for two years, and unvested options will be forfeited.

 

In the event of termination due to death, disability, or approved retirement, or in the event of a change in control of the Company, vesting of Mr. Trunfio’s unvested restricted shares accelerate.

 

In the event of termination, Mr. Henning receives no additional benefits beyond those accorded to all employees relative to unused earned vacation and reimbursement of ordinary business expenses incurred to the date of termination.

 

There were no employment agreements with Messrs. Miller and Sabherwal providing for termination benefits beyond those accorded to all employees.

 

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In the event of a change in control of the Company, if the successor organization does not assume or replace performance shares awarded under the Plan, or if the executive is involuntarily terminated without cause or voluntarily terminates for good reason within 24 months of the transaction, the target number of performance shares is deemed to have been earned.  In the event of termination due to death, disability or approved retirement, the Compensation Committee has the discretion to allow the participant (or his or her estate) to receive a pro-rated award based on the time worked during the performance period.  In this case, any award would be paid out based on actual results at the same time other participants receive their earned awards.  In the case of all other terminations, unearned performance shares would be forfeited.

 

Independence

 

The Board has affirmatively determined that Messrs. Abramson, Butz, Derbes, Hakimi, Hoffman, Kuhn and Nemirow are all independent of Aventine and its management.  In making such determination, the Board took into account the matters described in this Annual Report on Form 10-K under “Certain Relationships and Related Transactions and Director Independence—The MSCP Funds and Metalmark Capital LLC.”

 

Director Compensation

 

Our compensation program for non-employee directors consists of:

 

Cash Compensation

 

·                  $35,000 annual cash retainer, payable in equal quarterly installments;

·                  Additional $65,000 annual retainer to the Chairman of the Board;

·                  Additional committee chair retainers of $10,000 per year for the Chair of the Audit Committee and $5,000 for other Committee Chairs;

·                  $1,500 per Board meeting attended ($750 for telephonic meetings); and

·                  $750 per committee meeting attended, either in person or via phone.

 

Equity Compensation

 

·                  Annual grants totaling $35,000 in restricted stock units (RSUs).  These RSUs vest after one year.

·                  One-time initial grant to newly elected directors of $75,000 in RSUs, subject to three-year vesting.  The annual grant of $35,000 will not be made in the year of initial election.

·                  After vesting, RSUs must be held for the duration of a director’s Board service, and they will only be converted into shares after retirement or other termination.

 

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The following table sets forth certain information regarding the compensation earned by or awarded to each non-employee director who served on the Board in 2009:

 

Name

 

Fees Earned
or Paid in
Cash ($)

 

Stock Awards
($) (2)

 

Total
Compensation ($)

 

 

 

 

 

 

 

 

 

Bobby Latham

 

118,750

 

14,748

 

133,498

 

Farokh Hakimi

 

69,000

 

23,505

 

92,505

 

Arnold Nemirow

 

65,750

 

36,978

 

102,728

 

Wayne Kuhn

 

65,500

 

14,748

 

80,248

 

Leigh Abramson (1)

 

64,750

 

14,748

 

79,498

 

Richard Derbes

 

56,750

 

14,748

 

71.498

 

Michael Hoffman (1)

 

50,750

 

14,748

 

65,498

 

Theodore Butz

 

56,750

 

24,250

 

81,000

 

 


(1)          Cash fees paid to Messrs. Abramson and Hoffman are paid directly to Metalmark Capital LLC.

 

(2)          Represents the dollar amount recognized for financial statement reporting purposes in accordance with ASC 718, Compensation — Stock with respect to fiscal 2009 for restricted stock and RSU awards, disregarding estimated forfeitures related to service-based vesting conditions.  No shares of restricted stock were granted to directors in fiscal 2009.

 

The aggregate number of unvested shares of restricted stock and RSUs outstanding as of December 31, 2009 for each director was as follows:  Abramson — 0 shares, Butz — 12,658 shares, Derbes — 0 shares, Hakimi — 0 shares, Hoffman — 0 shares, Kuhn — 0 shares, Latham — 0 shares, and Nemirow — 1,405 shares.

 

Director Ownership Policies

 

Our non-employee directors are subject to ownership requirements to hold 5,000 shares of common stock within five years of the later of January 1, 2006 (the date the policy was adopted) or initial election. Like our employee stock ownership requirement, until the director ownership requirement is met in full, the director may not sell shares acquired from Aventine’s compensation programs, other than to satisfy minimum withholding obligations at the time of exercise or settlement or to satisfy the exercise price with respect to an option.  Our director compensation program also facilitates ownership among directors by requiring that the RSUs granted to directors be held for the duration of each director’s Board service.

 

Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

The following table presents certain information with respect to the beneficial ownership of our shares as of February 16, 2010 by (a) any person or group who beneficially owns more than five percent of our common stock, (b) each of our directors and named executive officers and (c) all directors and executive officers as a group. The percentage of beneficial ownership is based on 43,443,078 shares outstanding.

 

Except as indicated in footnotes to this table, we believe that the stockholders named in this table have sole voting and investment power with respect to all shares of common stock shown to be beneficially owned by them, based on information provided to us by such stockholders.

 

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Beneficial holders

 

Number of shares
beneficially held
(6)

 

Percentage of
beneficial
ownership

 

Aventine Renewable Energy Holdings LLC(1) c/o Metalmark Capital LLC, 1177 Avenue of the Americas, 40th Floor, New York, NY 10036

 

11,833,495

 

27.5

%

Daniel R. Trunfio, Jr.

 

122,212

 

 

*

Bobby L. Latham(2)

 

4,744

(3)

 

*

Farokh S. Hakimi

 

6,132

(3)

 

*

Wayne D. Kuhn(2)

 

7,244

(3)

 

*

Richard A. Derbes(2)

 

6,744

(3)

 

*

Arnold M. Nemirow

 

5,553

(3)

 

*

Leigh J. Abramson(4)

 

4,744

(3)

 

*

Michael C. Hoffman(4)

 

4,744

(3)

 

*

Theodore H. Butz

 

(3)

 

*

George Henning, Jr.

 

 

 

*

All directors and executive officers as a group (11 persons)

 

162,117

(5)

0.4

%

 


*   Less than 1%.

 

(1)                                  As disclosed on Amendment No. 2 to Schedule 13G filed on February 16, 2010 by Aventine Renewable Energy Holdings LLC (“Aventine Holdings LLC”), Morgan Stanley Dean Witter Capital Partners IV, LP (“MSDW IV”), MSDW IV 892 Investors, L.P. (“MSDW 892”), Morgan Stanley Dean Witter Capital Investors IV L.P. (“MSDW Capital Investors”), MSDW Capital Partners IV, LLC and MSDW Capital Partners IV, Inc., which we refer to collectively as the “MSCP funds”, hold in the aggregate approximately 96.2% of the voting units of Aventine Holdings LLC.  In July 2004, Morgan Stanley Investment Management Inc. entered into definitive agreements under which Metalmark Subadvisor LLC, an affiliate of Metalmark Capital LLC (“Metalmark”), manages certain of the MSCP funds on a subadvisory basis.  As a result, Metalmark may be deemed to control our management and policies.  MSDW IV may be deemed to indirectly beneficially own 9,837,908 shares of the reported securities by virtue of its direct ownership interest in Aventine Holdings LLC.  Metalmark may be deemed to have beneficial ownership of 10,691,928 shares of the reported securities, including both vested and unvested restricted shares and the 10,677,248 shares indirectly beneficially owned by MSDW IV and MSDW 892.  MSDW IV, MSDW 892, MSDW Capital Investors and Metalmark each disclaim beneficial ownership of the reported securities except to the extent of their pecuniary interests therein.

 

(2)                                  Messrs. Latham and Kuhn hold 600 and 100 voting units, respectively, in Aventine Holdings LLC, which represents approximately 1.4% of the outstanding voting units. Messrs. Derbes, Latham and Kuhn also hold non-voting units in Aventine Holdings LLC.  The non-voting units beneficially owned by Mr. Latham are held by BLL Energy, LLC of which Mr. Latham is the managing director.

 

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(3)                                  Does not include restricted stock units held by the following non-employee directors that are not settleable within 60 days of February 16, 2010: Mr. Latham, 2,560; Mr. Hakimi, 2,560; Mr. Kuhn, 2,560; Mr. Derbes, 2,560; Mr. Nemirow, 3,895; Mr. Abramson, 2,560; Mr. Hoffman, 2,560; and Mr. Butz, 18,978.

 

(4)                                  Messrs. Abramson and Hoffman are employees of Metalmark and disclaim beneficial ownership of the shares owned by Aventine Holdings LLC.

 

(5)           None of the shares held by the directors or named executive officers have been pledged as security.

 

(6)                                  Does not include ownership by Messrs. Miller or Sabherwal as they are no longer employed by the Company and the Company does not have access to information regarding their respective ownership.

 

Equity Compensation Plan Information

 

The following table provides information about our equity compensation plan as of December 31, 2009:

 

Plan category

 

(a)
Number of securities to be
issued upon exercise of
outstanding options,
warrants and rights

 

(b)
Weighted average exercise
price of outstanding options,
warrants
and rights

 

(c)
Number of securities
remaining available for
future issuance under equity
compensation plans
(excluding securities
reflected in column (a))

 

Equity compensation plans approved by security holders (1),(2)

 

2,688,466

 

$

5.05

(2)

2,745,287

 

Equity compensation plans not approved by security holders

 

-0-

 

 

 

-0-

 

Total

 

2,688,466

 

 

 

2,745,287

 

 


(1)          Aventine Renewable Energy Holdings, Inc. 2003 Stock Incentive Plan, as amended through April 30, 2008.  The amount shown in column (a) consists of 2,584,644 stock options, 39,318 shares of unvested restricted stock and 64,504 restricted stock units.

 

(2)          Does not include outstanding rights to receive common stock upon the vesting of restricted stock units.

 

Item 13.  Certain Relationships and Related Transactions and Director Independence

 

Aventine has adopted a policy governing the review and approval of related person transactions that may require disclosure.  Potential related person transactions are identified based on information provided by our directors and executive officers and submitted to the Audit Committee for review. The Audit Committee will consider all relevant facts and circumstances, including the commercial reasonableness of the terms, the benefits, if any, to the Company, opportunity costs of alternate transactions, the materiality and character of the related person’s direct or indirect interest in the transaction and the actual or apparent conflict of interest of the related person, in determining whether to approve or ratify a transaction. The terms of the policy provide that the Audit Committee will not approve or ratify a related person transaction unless it has determined in good faith that the transaction is in, or not inconsistent with, the best interests of Aventine and its stockholders.

 

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The MSCP Funds and Metalmark Capital LLC

 

Through their ownership of Aventine Holdings LLC, the MSCP funds beneficially own approximately 27.5% of our outstanding common stock.  Metalmark Subadvisor LLC, an affiliate of  Metalmark, an independent private equity firm established by former principals of Morgan Stanley Capital Partners, manages certain MSCP funds on a subadvisory basis.  In January 2008, substantially all of the employees of Metalmark became employees of Citi Alternative Investments Inc., although Metalmark remains an independent entity owned by those individuals and continues to manage the applicable MSCP funds on a subadvisory basis.  Two of our directors, Messrs. Abramson and Hoffman, are currently employees of both Metalmark and Citi Alternative Investments Inc.

 

As a result, Metalmark may be deemed to control our management and policies. Metalmark may have an interest in pursuing transactions that, in their judgment, enhance the value of the applicable funds’ equity investment in Aventine, even though those transactions may involve risks to our other stockholders.  In addition, circumstances could arise under which the interests of Metalmark could be in conflict with the interests of our other stockholders.  For example, Metalmark has and may in the future make significant investments in other companies, some of which may be competitors. Metalmark is not obligated to advise us of any investment or business opportunities of which they are aware, and they are not restricted or prohibited from competing with us.

 

Item 14.  Principal Accounting Fees and Services

 

Fees (including reimbursement for out-of-pocket expenses) to our independent registered public accounting firm for services in 2009 and 2008 were as follows:

 

 

 

Audit
Fees

 

Audit-Related
Fees

 

Tax Fees

 

All Other
Fees

 

2009

 

 

 

 

 

 

 

 

 

E&Y

 

$

1,357,223

 

$

88,312

 

$

795,947

 

$

 

 

 

 

 

 

 

 

 

 

 

2008

 

 

 

 

 

 

 

 

 

E&Y

 

$

1,055,945

 

$

58,780

 

$

201,297

 

$

 

 

Audit Fees include fees for the audit of the annual financial statements and internal control over financial reporting, reviews of the related quarterly statements, and related SEC and other filings.

 

Audit-Related Fees include fees for audit-related work in connection with employee benefit plans of Aventine and accounting due diligence.

 

Tax Fees include fees related to ordinary tax advisory services, tax compliance services and approximately $277 thousand for bankruptcy related tax consultation and services.

 

The Audit Committee considers the compatibility of non-audit services by its independent registered public accounting firm.

 

Audit Committee’s Pre-Approval Policies and Procedures

 

The Audit Committee of the Board reviews and approves the scope of the audit performed by our independent registered public accounting firm and our accounting principles and internal accounting controls.  The Audit Committee is composed of four independent directors, and operates under a written charter adopted and approved by the Board.  The Board has determined that Messrs. Hakimi, Butz, Derbes and Nemirow are audit committee financial experts within the meaning of SEC regulations.

 

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Table of Contents

 

The Audit Committee has adopted an Audit and Non-Audit Services Approval Policy that requires the Audit Committee to pre-approve audit and non-audit services provided by Aventine’s independent registered public accounting firm.  100% of such services were pre-approved by the Audit Committee in 2009 and 2008.  The Audit Committee will review such services and approve only those services that are consistent with the SEC’s rules on auditor independence.

 

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PART IV

 

Item 15.  Exhibits and Financial Statement Schedules

 

(a)          Index to exhibits, financial statements and schedules.

 

(1)          The following consolidated financial statements and reports are included beginning on page F-1 hereof:

Consolidated Statements of Operations — For the years ended December 31, 2009, 2008, and 2007.

Consolidated Balance Sheets — December 31, 2009 and 2008.

Consolidated Statements of Stockholders’ Equity (Deficit) — For the years ended December 31, 2009, 2008, and 2007.

Consolidated Statements of Cash Flows — For the years ended December 31, 2009, 2008, and 2007.

Notes to Consolidated Financial Statements.

Reports of Independent Registered Public Accounting Firm.

 

(2)          The following consolidated financial statement schedule of the Company is included on page F-45 hereof:

 

SCHEDULE II       Valuation and Qualifying Accounts

 

All other financial statements and schedules not listed have been omitted since the required information is included in the consolidated financial statements or the notes thereto, or is not applicable or required.

 

(3)   Exhibits required by Item 601 of Regulation S-K:

 

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Table of Contents

 

EXHIBIT INDEX

 

Exhibit
Number

 

Description

 

 

 

3.1

 

Amended and Restated Certificate of Incorporation of Aventine Renewable Energy Holdings, Inc. (incorporated by reference to Exhibit 3.1 to Aventine’s Registration Statement on Form S-1 (333-132860) filed on March 30, 2006)

 

 

 

3.2

 

Amended and Restated Bylaws of Aventine Renewable Energy Holdings, Inc. (incorporated by reference to Exhibit 3.2 to Aventine’s Registration Statement on Form S-1/A (333-132860) filed on June 13, 2006)

 

 

 

4.1

 

Registration Rights Agreement dated as of December 12, 2005 among Aventine Renewable Energy Holdings, Inc., the Investor Holders and the Management Holders named therein (incorporated by reference to Exhibit 4.3 to Aventine’s Registration Statement on Form S-1 (333-132860) filed on March 30, 2006)

 

 

 

4.2

 

Indenture, dated as of March 27, 2007, among Aventine Renewable Energy Holdings, Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, N.A. and the form of note (incorporated by reference to Exhibit 4. 1 to Aventine’s Current Report on Form 8-K filed on April 2, 2007)

 

 

 

10.1

 

Lease Agreement, dated as of October 31, 2006 by and between the Indiana Port Commission and Aventine Renewable Energy — Mt. Vernon, LLC (the “Mt. Vernon Lease Agreement”) (incorporated by reference to Exhibit 10.1 to Aventine’s Annual Report on Form 10-K filed on March 5, 2007)

 

 

 

10.1.1

 

First Amendment to Mt. Vernon Lease Agreement, dated as of June 14, 2007 (incorporated by reference to Exhibit 10.1.1 to Aventine’s Annual Report on Form 10-K filed on March 5, 2008)

 

 

 

10.1.2

 

Second Amendment to Mt. Vernon Lease Agreement, dated as of October 18, 2007 (incorporated by reference to Exhibit 10.1.2 to Aventine’s Annual Report on Form 10-K filed on March 5, 2008)

 

 

 

10.1.3

 

Third Amendment to Mt. Vernon Lease Agreement, dated as of January 26, 2008 (incorporated by reference to Exhibit 10.1.3 to Aventine’s Annual Report on Form 10-K filed on March 5, 2008)

 

 

 

10.1.4

 

Fourth Amendment to Mt. Vernon Lease Agreement, dated as of June 19, 2008 (incorporated by reference to Exhibit 10.1.4 to Aventine’s Annual Report on Form 10-K filed on March 16, 2009)

 

 

 

10.1.5

 

Fifth Amendment to Mt. Vernon Lease Agreement, dated as of December 18, 2008 (incorporated by reference to Exhibit 10.1.5 to Aventine’s Annual Report on Form 10-K filed on March 16, 2009)

 

 

 

10.1.6

 

Sixth Amendment to Mt. Vernon Lease Agreement, dated as of February 12, 2009 (incorporated by reference to Exhibit 10.1.6 to Aventine’s Annual Report on Form 10-K filed on March 16, 2009)

 

 

 

10.1.7

 

Seventh Amendment to Mt. Vernon Lease Agreement, dated as of April 23, 2009 (incorporated by reference to Exhibit 10.1 of Aventine’s Quarterly Report on Form 10-Q filed on August 10, 2009)

 

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Table of Contents

 

10.2

 

Rights Agreement dated as of December 19, 2005 between Aventine Renewable Energy Holdings. Inc. and American Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 10.5 to Aventine’s Registration Statement on Form S-1 (333-132860) filed on March 30, 2006)

 

 

 

10.3

 

Non-Employee Director Compensation Schedule (incorporated by reference to Exhibit 10.12 to Aventine’s amended Registration Statement on Form S-1/A (333-132860) filed on June 13, 2006)*

 

 

 

10.4

 

Form of Performance Stock Unit Award Agreement (2003 Stock Incentive Plan) (incorporated by reference to Exhibit 10.1 to Aventine’s Current Report on Form 8-K filed on February 27, 2007)*

 

 

 

10.5

 

Form of Stock Option Award Agreement (2003 Stock Incentive Plan) (incorporated by reference to Exhibit 10.2 to Aventine’s Current Report on Form 8-K filed on February 27, 2007)*

 

 

 

10.6

 

Form of Restricted Stock Award Agreement (2003 Stock Incentive Plan) (incorporated by reference to Exhibit 10.3 to Aventine’s Current Report on Form 8-K filed on February 27, 2007)*

 

 

 

10.7

 

Form of Non-employee Director Restricted Stock Unit Award Agreement (2003 Stock Incentive Plan (incorporated by reference to Exhibit 10.4 to Aventine’s Current Report on Form 8-K filed on February 27, 2007)*

 

 

 

10.8

 

Purchase Agreement, dated as of March 21, 2007, among the Company, the subsidiary guarantors named therein and J.P. Morgan Securities, Inc., as representative of several initial purchasers (incorporated by reference to Exhibit 10.1 to Aventine’s Current Report on Form 8-K filed on March 27, 2007)

 

 

 

10.9

 

Credit Agreement, dated as of March 23, 2007, by and among Aventine Renewable Energy, Inc., Aventine Renewable Energy — Mt. Vernon, LLC and Aventine Renewable Energy — Aurora West, LLC, the other Loan Parties thereto, the lenders thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to Aventine’s Current Report on Form 8-K filed on March 26, 2007)

 

 

 

10.9.1

 

First amendment to Credit Agreement, dated as of March 10, 2009, by and among Aventine Renewable Energy, Inc., Aventine Renewable Energy — Mt. Vernon, LLC and Aventine Renewable Energy — Aurora West, LLC, the other Loan Parties thereto, the lenders thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.15.1 to Aventine’s Annual Report on Form 10-K filed March 16, 2009)

 

 

 

10.9.2

 

Letter agreement dated March 12, 2009, related to the Credit Agreement, dated as of March 23, 2007, by and among Aventine Renewable Energy, Inc., Aventine Renewable Energy — Mt. Vernon, LLC and Aventine Renewable Energy — Aurora West, LLC, the other Loan Parties thereto, the lenders thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.15.2 to Aventine’s Annual Report on Form 10-K filed March 16, 2009)

 

 

 

10.9.3

 

Letter agreement dated March 30, 2009, between the Company, Aventine Renewable Energy — Mt. Vernon, LLC, Aventine Renewable Energy — Aurora West, LLC, JPMorgan Chase Bank, N.A., (as administrative agent and a lender), and the other lenders to its Credit Agreement, dated as of March 23, 2007 (as amended) (incorporated by reference to Exhibit 10.1 to Aventine’s Current Report on Form 8-K filed on April 3, 2009)

 

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Table of Contents

 

10.10

 

Aventine Renewable Energy Holdings, Inc. 2003 Stock Incentive Plan (Amended and Restated as of April 16, 2007) (incorporated by reference to Exhibit 10.1 to Aventine’s Current Report on Form 8-K filed on April 16, 2007)*

 

 

 

10.11

 

Settlement and Release Agreement, dated as of February 27, 2008, by and among the Company, The Williams Companies, Inc. and Williams Energy Services, LLC (incorporated by reference to Exhibit 10.21 to Aventine’s Annual Report on Form 10-K filed on March 5, 2008)

 

 

 

10.12

 

Debtor in Possession Credit Facility Term Sheet, dated as of April 7, 2009, by and among Brigade Leveraged Capital Structures Fund, Ltd., Nomura Corporate Research & Asset Management, Inc., as Investment Manager for and on behalf of certain lenders, Whitebox Hedged High Yield Partners, L.P., Pandora Select Partners, L.P. (as lenders), Aventine Renewable Energy, Inc., Aventine Renewable Energy — Mt Vernon, LLC, and Aventine Renewable Energy — Aurora West LLC on a joint and several basis as debtors in possession under chapter 11 of the United States Bankruptcy Code in jointly administered cases in the United States Bankruptcy Court for the District of Delaware and the Guarantors named therein (incorporated by reference to Exhibit 10.1 to Aventine’s Current Report on Form 8-K filed on April 13, 2009)

 

 

 

21.1

 

List of subsidiaries of the Registrant

 

 

 

23.1

 

Consent of Ernst & Young LLP

 

 

 

31.1

 

Certificate of Chief Executive Officer of Aventine Renewable Energy Holdings, Inc. pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934

 

 

 

31.2

 

Certificate of Chief Financial Officer of Aventine Renewable Energy Holdings, Inc. pursuant to Rule 13(a)-14(a) under the Securities Exchange Act of 1934

 

 

 

32.1

 

Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

 

 

32.2

 

Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 


*              Compensatory plan or arrangement.

 

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Table of Contents

 

SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Pekin, State of Illinois, on the 23rd day of February, 2010.

 

 

AVENTINE RENEWABLE ENERGY HOLDINGS, INC.

 

 

 

By:

/s/ William J. Brennan

 

Name:  William J. Brennan

 

Title:  Principal Accounting Officer

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.

 

Signature

 

Title

 

Date

 

 

 

 

 

 

By:

/s/ George T. Henning, Jr.

 

Interim Chief Executive Officer, President and Chief Financial Officer (Acting Principal Executive and Financial Officer)

 

February 23, 2010

               George T. Henning, Jr.

 

 

 

 

 

By:

/s/ William J. Brennan

 

Chief Accounting and Compliance Officer (Principal Accounting Officer)

 

February 23, 2010

               William J. Brennan

 

 

 

 

 

 

By:

/s/ Bobby Latham

 

Non-Executive Chairman of the Board of Directors

 

February 23, 2010

               Bobby Latham

 

 

 

 

 

 

By:

/s/ Leigh J. Abramson

 

Director

 

February 23, 2010

               Leigh J. Abramson

 

 

 

 

 

 

By:

/s/ Theodore H. Butz

 

Director

 

February 23, 2010

               Theodore H. Butz

 

 

 

 

 

 

By:

/s/ Richard A. Derbes

 

Director

 

February 23, 2010

               Richard A. Derbes

 

 

 

 

 

 

By:

/s/ Farokh S. Hakimi

 

Director

 

February 23, 2010

               Farokh S. Hakimi

 

 

 

 

 

 

By:

/s/ Michael C. Hoffman

 

Director

 

February 23, 2010

               Michael C. Hoffman

 

 

 

 

 

 

By: 

/s/ Wayne D. Kuhn

 

Director

 

February 23, 2010

               Wayne D. Kuhn

 

 

 

 

 

 

By:

/s/ Arnold M. Nemirow

 

Director

 

February 23, 2010

               Arnold M. Nemirow

 

 

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Table of Contents

 

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

(Debtor-in-Possession)

Consolidated Statements of Operations

 

 

 

Year ended December 31,

 

 

 

2009

 

2008

 

2007

 

(In thousands except per share amounts)

 

 

 

 

 

 

 

Net sales

 

$

594,623

 

$

2,248,301

 

$

1,571,607

 

Cost of goods sold

 

585,904

 

2,239,340

 

1,497,807

 

Gross profit

 

8,719

 

8,961

 

73,800

 

 

 

 

 

 

 

 

 

Selling, general and administrative expenses

 

26,694

 

35,410

 

36,367

 

Demobilization costs associated with expansion projects

 

 

9,874

 

 

Impairment of plant development costs

 

 

1,557

 

 

Other income (expense)

 

(1,510

)

2,936

 

1,113

 

Operating income (loss)

 

(19,485

)

(34,944

)

38,546

 

Other income (expense):

 

 

 

 

 

 

 

Income from termination of marketing agreements

 

10,176

 

 

 

Loss on sale of auction rate securities

 

 

(31,601

)

 

Interest income

 

11

 

3,040

 

12,432

 

Interest expense (contractual interest expense was $36.6 million for the year ended December 31, 2009)

 

(14,697

)

(5,077

)

(16,240

)

Gain (loss) on derivative transactions

 

1,219

 

17,110

 

(78

)

Loss on marketing alliance investment

 

 

(4,326

)

 

Income (loss) before reorganization items and income taxes

 

(22,776

)

(55,798

)

34,660

 

Reorganization items

 

(32,440

)

 

 

Income (loss) before income taxes

 

(55,216

)

(55,798

)

34,660

 

Income tax expense (benefit)

 

(8,956

)

(7,472

)

(477

)

Net income (loss)

 

(46,260

)

(48,326

)

35,137

 

Net income (loss) attributable to non-controlling interest

 

 

(1,230

)

1,338

 

Net income (loss) attributable to controlling interest

 

$

(46,260)

 

$

(47,096

)

$

33,799

 

 

 

 

 

 

 

 

 

Income (loss) per common share—basic

 

$

(1.08

)

$

(1.12

)

$

0.81

 

Basic weighted-average number of shares

 

42,968

 

42,136

 

41,886

 

 

 

 

 

 

 

 

 

Income (loss) per common share—diluted

 

$

(1.08

)

$

(1.12

)

$

0.80

 

Diluted weighted-average number of common and common equivalent shares

 

42,968

 

42,136

 

42,351

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

F-1



Table of Contents

 

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

(Debtor-in-Possession)

Consolidated Balance Sheets

 

 

 

December 31,

 

 

 

2009

 

2008

 

(In thousands except share and per share amounts)

 

 

 

 

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and equivalents

 

$

52,585

 

$

23,339

 

Accounts receivable, net of allowance for doubtful accounts of $2,400 in 2009 and $272 in 2008

 

10,947

 

55,888

 

Inventories

 

24,237

 

85,421

 

Income taxes receivable

 

5,796

 

15,135

 

Prepaid expenses and other current assets

 

8,302

 

10,198

 

Total current assets

 

101,867

 

189,981

 

Property, plant and equipment, net

 

95,791

 

107,168

 

Construction in process

 

493,258

 

493,969

 

Restricted cash

 

7,451

 

 

Available for sale securities

 

5,442

 

673

 

Investment in marketing alliance partners, at cost

 

 

1,000

 

Other assets

 

9,866

 

6,668

 

Total assets

 

$

713,675

 

$

799,459

 

Liabilities and Stockholders’ Equity

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Senior unsecured 10% fixed-rate notes

 

$

 

$

300,000

 

Secured revolving credit facility

 

27,765

 

52,200

 

Debtor-in-possession debt facility

 

15,000

 

 

Accounts payable

 

11,164

 

110,903

 

Accrued interest

 

302

 

7,500

 

Accrued liabilities

 

2,242

 

3,517

 

Other current liabilities

 

7,258

 

9,900

 

Total current liabilities

 

63,731

 

484,020

 

 

 

 

 

 

 

Pre-petition liabilities subject to compromise

 

365,549

 

 

Deferred tax liabilities

 

2,936

 

2,444

 

Other long-term liabilities

 

13,927

 

4,199

 

Total liabilities

 

446,143

 

490,663

 

Stockholders’ equity:

 

 

 

 

 

Common stock, par value $0.001 per share; 185,000,000 shares authorized, 43,048,158 and 42,970,988 shares outstanding as of December 31, 2009 and 2008, respectively, net of 21,548,640 shares held in treasury as of December 31, 2009 and 2008

 

44

 

43

 

Preferred stock, 50,000,000 shares authorized, no shares issued or outstanding

 

 

 

Additional paid-in capital

 

294,297

 

292,984

 

Retained earnings (deficit)

 

(28,421

)

17,839

 

Accumulated other comprehensive income (loss), net

 

1,612

 

(2,070

)

Total stockholders’ equity

 

267,532

 

308,796

 

Total liabilities and stockholders’ equity

 

$

713,675

 

$

799,459

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

F-2



Table of Contents

 

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

(Debtor-in-Possession)

Consolidated Statements of Stockholders’ Equity (Deficit)

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

 

 

Additional

 

Retained

 

Other

 

Total

 

 

 

Treasury

 

Common Stock

 

Paid-In

 

Earnings

 

Comprehensive

 

Stockholders’

 

 

 

Shares

 

Shares

 

Amount

 

Capital

 

(Deficit)

 

Gain/(Loss)

 

Equity

 

(In thousands except number of shares)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31, 2006

 

21,229,025

 

41,782,276

 

$

42

 

$

274,307

 

$

30,888

 

$

(1,074

)

$

304,163

 

Tax benefit of stock option exercises

 

 

 

 

 

 

 

180

 

 

 

 

 

180

 

Stock option exercises

 

 

 

201,031

 

 

 

510

 

 

 

 

 

510

 

Repurchase of common stock for the treasury

 

319,615

 

(319,615

)

 

 

(2,983

)

 

 

 

 

(2,983

)

Cumulative effect FIN 48 adoption

 

 

 

 

 

 

 

 

 

248

 

 

 

248

 

Stock-based compensation

 

 

 

 

 

 

6,811

 

 

 

 

 

6,811

 

Issuance of restricted stock awards and amortization of unearned compensation

 

 

 

70,531

 

 

 

393

 

 

 

 

 

393

 

Comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

 

 

 

 

33,799

 

 

 

33,799

 

Pension and postretirement liability adjustment, net of tax

 

 

 

 

 

 

 

 

 

 

 

750

 

750

 

Total comprehensive income

 

 

 

 

 

 

 

 

 

 

 

 

 

34,549

 

Balance at December 31, 2007

 

21,548,640

 

41,734,223

 

42

 

279,218

 

64,935

 

(324

)

343,871

 

Tax effect of exercised and lapsed stock options

 

 

 

(342

)

 

 

(57

)

 

 

 

 

(57

)

Stock option exercises (forfeitures)

 

 

 

 

 

 

 

(24

)

 

 

 

 

(24

)

Stock-based compensation

 

 

 

 

 

 

 

5,729

 

 

 

 

 

5,729

 

Purchase of minority interest

 

 

 

1,000,000

 

1

 

6,618

 

 

 

 

 

6,619

 

Issuance of common stock

 

 

 

237,107

 

 

 

1,500

 

 

 

 

 

1,500

 

Comprehensive (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss)

 

 

 

 

 

 

 

 

 

(47,096

)

 

 

(47,096

)

Pension and postretirement liability adjustment, net of tax

 

 

 

 

 

 

 

 

 

 

 

(1,746

)

(1,746

)

Total comprehensive (loss)

 

 

 

 

 

 

 

 

 

 

 

 

 

(48,842

)

Balance at December 31, 2008

 

21,548,640

 

42,970,988

 

43

 

292,984

 

17,839

 

(2,070

)

308,796

 

Tax effect of exercised and lapsed stock options

 

 

 

(4,830

)

 

 

(1,242

)

 

 

 

 

(1,242

)

Stock option exercises (forfeitures)

 

 

 

85,000

 

1

 

19

 

 

 

 

 

20

 

Stock-based compensation

 

 

 

 

 

 

 

2,536

 

 

 

 

 

2,536

 

Forfeiture of nonvested restricted stock

 

 

 

(3,000

)

 

 

 

 

 

 

 

 

 

 

Comprehensive (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss)

 

 

 

 

 

 

 

 

 

(46,260

)

 

 

(46,260

)

Pension and postretirement liability adjustment, net of tax

 

 

 

 

 

 

 

 

 

 

 

773

 

773

 

Unrealized holding gain on available-for-sale securities, net of tax

 

 

 

 

 

 

 

 

 

 

 

2,909

 

2,909

 

Total comprehensive (loss)

 

 

 

 

 

 

 

 

 

 

 

 

 

(42,578

)

Balance at December 31, 2009

 

21,548,640

 

43,048,158

 

$

44

 

$

294,297

 

$

(28,421

)

$

1,612

 

$

267,532

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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Aventine Renewable Energy Holdings, Inc. and Subsidiaries

(Debtor-in-Possession)

Consolidated Statements of Cash Flows

 

 

 

Year ended December 31,

 

(In thousands)

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Operating Activities

 

 

 

 

 

 

 

Net income (loss)

 

$

(46,260

)

$

(48,326

)

$

35,137

 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

Provision for rejected executory contracts and leases

 

26,403

 

 

 

Loss on sale of auction rate securities

 

 

31,601

 

 

Depreciation and amortization

 

16,709

 

15,465

 

13,265

 

Deferred income taxes

 

(2,610

)

4,489

 

(6,664

)

(Gain) loss on disposal of fixed assets

 

 

194

 

(3

)

Stock-based compensation expense

 

2,536

 

5,729

 

7,204

 

Impairment loss on marketing alliance investment

 

 

4,326

 

 

Impairment of plant development costs

 

 

1,557

 

 

Gain on sale of investments in marketing alliances

 

(1,000

)

 

 

Other

 

 

(546

)

180

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Accounts receivable, net

 

44,941

 

17,170

 

6,671

 

Income tax receivable

 

9,339

 

(3,173

)

(5,516

)

Inventories

 

61,184

 

(3,933

)

(14,437

)

Prepaid expenses and other current assets

 

2,876

 

1,951

 

(8,701

)

Other assets

 

(16,921

)

 

 

 

 

Accounts payable

 

(61,988

)

(8,385

)

14,429

 

Demobilization costs for expansion projects

 

 

9,874

 

 

Accrued liabilities, including pension and postretirement benefits

 

5,607

 

7,608

 

6,016

 

Net cash provided by operating activities

 

40,816

 

35,601

 

47,581

 

 

 

 

 

 

 

 

 

Investing Activities

 

 

 

 

 

 

 

Additions to property, plant and equipment, net

 

(2,279

)

(265,878

)

(235,211

)

Purchases of short-term securities

 

 

 

(690,948

)

Redemptions of short-term securities

 

 

179,899

 

578,373

 

Indemnification proceeds

 

 

3,046

 

 

Transaction costs for purchase of Nebraska Energy interest

 

 

(200

)

 

Proceeds from the sale of investments in marketing alliance

 

2,000

 

 

 

Proceeds from the sale of property, plant and equipment

 

 

 

5

 

Net cash used for investing activities

 

(279

)

(83,133

)

(347,781

)

 

 

 

 

 

 

 

 

Financing Activities

 

 

 

 

 

 

 

Proceeds from issuance of senior unsecured 10% fixed-rate notes

 

 

 

300,000

 

Net borrowings from (repayments of) revolving credit facilities

 

(24,435

)

52,200

 

 

Borrowings from debtor-in-possession debt facility

 

15,000

 

 

 

Financing fees and expenses paid pre-petition

 

(1,876

)

 

(8,220

)

Distribution to minority shareholders

 

 

 

(1,727

)

Proceeds from issuance of common stock, net

 

 

1,500

 

 

Repurchase of common stock

 

 

 

(2,983

)

Proceeds from stock option exercises

 

20

 

 

510

 

Net cash provided by (used for) financing activities

 

(11,291

)

53,700

 

287,580

 

Net increase (decrease) in cash and equivalents

 

29,246

 

6,168

 

(12,620

)

Cash and equivalents at beginning of year

 

23,339

 

17,171

 

29,791

 

Cash and equivalents at end of year

 

$

52,585

 

$

23,339

 

$

17,171

 

 

 

 

 

 

 

 

 

Supplemental disclosure of cash flow:

 

 

 

 

 

 

 

Interest paid

 

$

6,040

 

$

31,514

 

$

15,333

 

Income taxes paid (refunded)

 

$

(16,408

)

$

806

 

$

11,033

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

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Table of Contents

 

Aventine Renewable Energy Holdings, Inc. and Subsidiaries

(Debtor-in-Possession)

Notes to Consolidated Financial Statements

 

1.             Nature of Operations and Basis of Presentation

 

Aventine Renewable Energy Holdings, Inc. and Subsidiaries (the “Company,” “Aventine,” “we,” “our,” or “us”) is a producer and marketer of ethanol.  Our own production facilities produced 197.5 million gallons of ethanol in 2009 and 188.8 million gallons of ethanol in 2008.  We have also been a large marketer of ethanol, distributing ethanol purchased from other third-party producers in addition to our own ethanol production.  In 2009 and 2008, we distributed 66.4 million gallons and 754.3 million gallons, respectively, of ethanol produced by others.  Taken together, we marketed and distributed 277.5 million gallons of ethanol in 2009 and 936.0 million gallons of ethanol in 2008.  In addition to producing ethanol, our facilities also produce several co-products including: corn gluten feed and meal, corn germ, condensed corn distillers solubles, dried distillers grain with solubles, wet distillers grain with solubles, carbon dioxide and brewers’ yeast.

 

2.             Chapter 11 Bankruptcy Proceedings

 

On April 7, 2009 (the “Petition Date”), Aventine Renewable Energy Holdings, Inc. and all of its direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions for relief (collectively, the “Bankruptcy Filing”) under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”) with the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”).  The Chapter 11 cases are being jointly administered by the Bankruptcy Court as Case No. 09-11214 (KG) (collectively, the “Bankruptcy Cases”).  The Debtors specifically are (i) Aventine Renewable Energy Holdings, Inc.; (ii) Aventine Renewable Energy, LLC, a Delaware limited liability company; (iii) Aventine Renewable Energy, Inc., a Delaware corporation; (iv) Aventine Renewable Energy — Mt. Vernon, LLC, a Delaware limited liability company; (v) Aventine Renewable Energy — Aurora West, LLC, a Delaware limited liability company; (vi) Aventine Power, LLC, a Delaware limited liability company, and (vii) Nebraska Energy, LLC, a Kansas limited liability company.

 

Subject to certain specific exceptions under the Bankruptcy Code, the Bankruptcy Filing automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against the Debtors or their property to recover on, collect or secure a claim arising prior to the Petition Date.  Thus, for example, most creditor actions to obtain possession of property from the Debtors, or to create, perfect or enforce any lien against the property of the Debtors, or to collect on or otherwise exercise rights or remedies with respect to a pre-petition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.

 

The Bankruptcy Filing constituted an event of default under both the Company’s secured revolving credit facility and its 10% senior unsecured notes due 2017 (“the Notes”) (see Note 7), and those debt obligations became automatically and immediately due and payable, subject to an automatic stay of any action to collect, assert, or recover a claim against the Company and the application of applicable bankruptcy law.  As a result, the accompanying Consolidated Balance Sheet as of December 31, 2009 includes reclassifications of $309.7 million to reflect as “pre-petition liabilities subject to compromise” amounts owed to holders of the Notes, including pre-petition accrued interest, net of the unamortized debt issuance costs on the Notes.  The Company classifies “pre-petition liabilities subject to compromise” as a long-term liability because management does not believe the Company will use existing current assets or create additional current liabilities to fund these obligations.  Amounts owed under the Company’s pre-petition secured revolving credit facility and certain other collateralized obligations have not been included in “pre-petition liabilities subject to compromise” as they are adequately collateralized.

 

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Chapter 11 Process

 

The Debtors are currently operating as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court, and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.  In general, as debtors-in-possession, the Debtors are authorized under the Bankruptcy Code to continue to operate as an ongoing business, but may not engage in transactions outside of the ordinary course of business without the approval of the Bankruptcy Court.

 

On April 7, 2009, certain of the Company’s bondholders entered into a term sheet (the “DIP Term Sheet”) for a $30 million Debtor-in-Possession Credit Facility with the Debtors.  The DIP Term Sheet provides, subject to certain conditions as described in the Debtor-in-Possession Credit Facility Term Sheet filed as Exhibit 10.1 to our Form 8-K filed on April 13, 2009 for a first priority debtor-in-possession financing comprised of a term loan facility made available to certain of Aventine’s subsidiaries in a maximum aggregate principal amount of up to $30 million (the “DIP Facility”).  On May 5, 2009, the Bankruptcy Court overruled objections from the Debtors’ pre-petition secured lenders and approved the DIP Facility on a final basis.  Proceeds of the DIP Facility are available to, among other things, (i) fund the working capital and general corporate needs of the Debtors and the costs of the Bankruptcy Cases in accordance with an approved budget, and (ii) provide adequate protection, in accordance with the terms of the DIP Facility, to the pre-petition agent and pre-petition lenders under the Company’s existing credit facilities.  The DIP Facility bears interest at 16.5% per annum.  The maturity date of the DIP Facility is April 6, 2010, or upon the occurrence of certain pre-defined events.  The DIP Facility is secured by a super-priority administrative claim on our assets.

 

At a hearing held on April 9, 2009, the Bankruptcy Court granted the Debtors’ “First Day Motions.”  The relief granted by the Bankruptcy Court through the First Day Motions was designed to stabilize the Company’s operations and business relationships with vendors, lenders, employees and others, minimize the effects of the commencement of the Bankruptcy Cases and preserve the value of the Debtors’ assets.   The First Day Motions allowed, among other things, the payment of vendors and other providers in the ordinary course for goods and services ordered pre-petition but received on or after the Petition Date and other business-related payments necessary to maintain the operation of our businesses.  The First Day Motions also included the payment of pre-petition employee wages, salaries and benefits.  The Debtors have retained, with Bankruptcy Court approval, legal and financial professionals to advise the Debtors on the bankruptcy proceedings and certain other  “ordinary course” professionals.  From time to time, the Debtors may seek Bankruptcy Court approval for the retention of additional professionals.

 

On or about April 29, 2009, the Debtors caused notice of the commencement of the Bankruptcy Cases to be served on all known or potential creditors and other parties in interest.  Vendors are being paid for goods furnished and services provided after the Petition Date in the ordinary course of business.

 

As required by the Bankruptcy Code, the United States Trustee for Delaware appointed an official committee of unsecured creditors (the “Creditors’ Committee”). The Creditors’ Committee and its legal representatives have a right to be heard on all matters that come before the Bankruptcy Court with respect to the Debtors.  There can be no assurance that the Creditors’ Committee will support the Debtors’ positions on matters to be presented to the Bankruptcy Court in the future or on any plan of reorganization.  Disagreements between the Debtors and the Creditors’ Committee could protract the Bankruptcy Cases, negatively impact the Debtors’ ability to operate, and delay the Debtors’ emergence from the Chapter 11 proceedings.

 

Under Section 365 of the Bankruptcy Code, the Debtors may assume, assume and assign, or reject executory contracts and unexpired leases, including real property, railcars and equipment leases, subject to

 

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the approval of the Bankruptcy Court and certain other conditions.  Rejection constitutes a court-authorized breach of the lease or contract in question and, subject to certain exceptions, relieves the Debtors of future obligations under such lease or contract, but creates a pre-petition claim for damages caused by such breach or rejection, subject to the Debtors’ right to review and contest such claim.  Parties whose contracts or leases are rejected may file claims against the Debtors for damages.  Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure all prior defaults under such executory contract or unexpired lease, including all pre-petition arrearages, and to provide adequate assurance of future performance.  In this regard, the Debtors’ financial statements include amounts classified as “pre-petition liabilities subject to compromise” that the Debtors believe that the Bankruptcy Court will allow as claim amounts as a result of the Debtors’ rejection of various executory contracts and unexpired leases.  Additional amounts may be included in “pre-petition liabilities subject to compromise” in future periods if additional executory contracts and unexpired leases are rejected.  Conversely, the Debtors would expect that the assumption of certain executory contracts and unexpired leases may convert certain liabilities shown in future financial statements as subject to compromise to post-petition liabilities.  Due to the uncertain nature of many of the potential claims, the Debtors are unable to project the magnitude of such claims with any degree of certainty.

 

The Bankruptcy Court established September 8, 2009 at 4:00 p.m. eastern time as the deadline for the filing of proofs of claim, thereby requiring the Debtors’ creditors to submit claims for alleged liabilities not paid and/or damages incurred arising from or related to periods prior to the Petition Date.  In certain cases, differences exist between the amounts at which the Company has recorded liabilities for rejected contracts and other pre-petition liabilities in the Company’s financial statements and the amount claimed by Aventine’s creditors based on the Company’s estimate of the magnitude of claim to be allowed by the Bankruptcy Court.  Significant litigation may be required to resolve any such disputes or discrepancies.

 

In order to successfully exit Chapter 11, the Debtors will need to obtain confirmation by the Bankruptcy Court of a plan of reorganization that satisfies the requirements of the Bankruptcy Code.  A plan of reorganization could, among other things, resolve the Debtors’ pre-petition obligations, set forth the revised capital structure of the newly reorganized entity and provide for corporate governance subsequent to exit from bankruptcy.  As provided in the Bankruptcy Code, the Debtors have the exclusive right for 120 days after the Petition Date to file a plan of reorganization and 60 additional days to solicit and obtain necessary acceptances.  Such periods may be extended by the Bankruptcy Court for cause to up to 18 months and 20 months, respectively, after the Petition Date.   If the Debtors’ exclusivity period lapses, any party in interest may file a plan of reorganization for Aventine.  The Debtors have filed three motions with the Bankruptcy Court requesting extension of the exclusive filing and solicitation deadlines under section 1121 of the Bankruptcy Code.  The first motion, approved by the Bankruptcy Court by order dated August 18, 2009, extended the exclusive deadline to file a plan of reorganization to October 5, 2009 and the solicitation of the necessary acceptances to December 3, 2009.  The second motion, approved by the Bankruptcy Court by order dated October 27, 2009 further extended the exclusive deadline to file a plan of reorganization through and including December 4, 2009 and the exclusive solicitation period through and including February 1, 2010.  The third motion, approved by the Bankruptcy Court by order dated January 7, 2010 further extended the exclusive deadline to file a plan of reorganization through and including March 4, 2010 and the exclusive solicitation period through and including May 3, 2010.

 

On December 4, 2009, the Debtors filed the Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code Dated as of December 4, 2009 (as amended “the Plan”) and the Disclosure Statement for the Debtors’ Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code Dated as of December 4, 2009 (as amended “the Disclosure Statement”).

 

On January 13, 2010, the Bankruptcy Court approved an order allowing  the Debtors’ entry into the Backstop Commitment Agreement related to the offering of new senior secured notes and equity through

 

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the Plan.  The Bankruptcy Court, also on January 13, 2010, approved the Disclosure Statement as containing adequate information as required by section 1125 of the Bankruptcy Code and thus entered the Order (I) Approving the Disclosure Statement; (II) Establishing Procedures for Solicitation and Tabulation of Votes to Accept or Reject the Plan, Including (A) Approving Form and Manner of Solicitation Procedures, (B) Approving the Form and Notice of the Confirmation Hearing, (C) Establishing Record Date and Approving Procedures for Distribution of Solicitation Packages, (D) Approving Forms of Ballots, (E) Establishing Deadline for Receipt of Ballots, and (F) Approving Procedures for Vote Tabulations; (III) Establishing Deadline and Procedures for Filing Objections to (A) Confirmation of the Plan, and (B) the Debtors’ Proposed Cure Amounts for Unexpired Leases and Executory Contracts Assumed Pursuant to the Plan; (IV) Approving the Secured Notes Offering Procedures; and (V) Granting Related Relief.  The Bankruptcy Court established January 13, 2010 as the record date for purposes of determining which creditors and interest holders are entitled to vote on the Plan and receive materials in connection with the solicitation of votes to accept or reject the Plan, including notices of non-voting status.  The voting deadline for the holders of claims and interest holders entitled to vote under the Plan was established by the Bankruptcy Court as February 17, 2010.

 

Pursuant to section 1128 of the Bankruptcy Code, the Bankruptcy Court has scheduled a hearing to consider confirmation of the Plan for February 24, 2010 at 3:00 p.m. prevailing eastern time before the Honorable Kevin Gross, United States Bankruptcy Court, 824 North Market Street, 6th Floor, Wilmington, Delaware 19801 (the “Confirmation Hearing”).  The Bankruptcy Court has directed that objections, if any, to confirmation of the Plan be served and filed so that they are received on or before February 17, 2010 at 4:00 p.m., prevailing eastern time.  The Confirmation Hearing may be adjourned from time to time by the Bankruptcy Court without further notice except for the announcement of the adjournment date made at the Confirmation Hearing or at any subsequent adjourned Confirmation Hearing. Chapter 11 of the Bankruptcy Code provides that unless the terms of section 1129(b) of the Bankruptcy Code are satisfied, for a bankruptcy court to confirm a Chapter 11 plan as a consensual plan, the holders of impaired claims against a debtor in each class of impaired claims must accept such plan by the requisite majorities set forth in the Bankruptcy Code.  An impaired class of claims shall have accepted a chapter 11 plan if (a) the holders of at least two-thirds in amount of the claims in such class actually voting on a plan have voted to accept it, and (b) more than one-half in number of the holders in such class actually voting on the plan have voted to accept it.  Pursuant to the provisions of the Bankruptcy Code, only holders of allowed claims or equity interests in classes of claims or equity interests that are impaired and that are not deemed to have rejected a Chapter 11 plan are entitled to vote to accept or reject such proposed plan.  Generally, a claim or interest is impaired under a plan if the holder’s legal, equitable or contractual rights are altered under such plan.  Classes of claims or equity interests under a chapter 11 plan in which the holders of claims or equity interests are unimpaired are deemed to have accepted such plan and are not entitled to vote to accept or reject the proposed plan.  In addition, classes of claims or equity interests in which the holders of claims or equity interests will not receive or retain any property on account of their claims or equity interests are deemed to have rejected the plan and are not entitled to vote to accept or reject the plan.  Under circumstances specified in the so-called “cramdown” provisions of Section 1129(b) of the Bankruptcy Code, the Bankruptcy Court may confirm a plan even if such plan has not been accepted by all impaired classes.  The precise requirements and evidentiary showing for confirming a Chapter 11 plan notwithstanding its rejection by one or more impaired classes of claims or equity interests depends upon a number of factors, including the status and seniority of the claims or equity interests, in the rejecting class — i.e., secured claims or unsecured claims, subordinated or senior claims, or common stock.

 

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, post-petition liabilities and pre-petition liabilities must be satisfied in full before stockholders of the Debtors are entitled to receive any distribution or retain any property under a plan of reorganization.  The ultimate recovery, if any, to creditors and stockholders of the Debtors will not be determined until confirmation and consummation of a plan of reorganization.  No assurance can be given as to what values,

 

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if any, will be ascribed in the Bankruptcy Cases to each of these constituencies or what types or amounts of distributions, if any, they would receive.  Under the proposed Plan of Reorganization, if confirmed, the existing outstanding common stock of Aventine Renewable Energy Holdings, Inc. will be terminated and 8,550,000 shares of new common stock will be issued.  Accordingly, the Debtors urge that appropriate caution be exercised with respect to existing and future investments in any of the Company’s common stock or any of the Company’s liabilities.

 

Although the Debtors  filed the Plan, which provides for emergence from Chapter 11 some time in the future, there can be no assurance that the Plan, or any other Chapter 11 plan, will be confirmed by the Bankruptcy Court, or that any such Chapter 11 plan will be consummated.  In order to successfully emerge from Chapter 11, the Debtors will need to, among other things, obtain alternative financing to replace the DIP Facility.  The Company has filed the Disclosure Statement, which was approved by the Bankruptcy Court as containing adequate information under section 1125 of the Bankruptcy Code, and the Plan, that includes a backstop lending agreement, which may be confirmed at a hearing on February 24, 2010.

 

The Debtors have incurred and will continue to incur significant costs associated with the reorganization.  The amount of these costs, which are being expensed as incurred, are expected to significantly affect the Debtors’ results of operations.

 

Going Concern Matters

 

The ability of the Company to continue as a going concern is dependent upon, among other things, (i) the Company’s ability to comply with the terms and conditions of the DIP Facility; (ii) the ability of the Company to maintain adequate cash on hand; (iii) the ability of the Company to generate cash from operations; (iv) the ability of the Company to obtain confirmation of and to consummate a plan of reorganization under the Bankruptcy Code; (v) the cost and outcome of the reorganization process; (vi) the Company’s ability to obtain alternative financing; and (vii) the Company’s ability to achieve profitability.  Uncertainty as to the outcome of these factors raises substantial doubt about the Company’s ability to continue as a going concern.  The Company is currently evaluating various courses of action to address the issues the Company is facing.  There can be no assurance that any of these efforts will be successful.

 

The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of our Chapter 11 proceedings.  In particular, the financial statements do not purport to show (i) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (ii) as to pre-petition liabilities, the amounts that may be allowed for claims or contingencies, or the status and priority thereof; (iii) as to shareowners’ equity accounts, the effect of any changes that may be made in our capitalization; or (iv) as to operations, the effect of any changes that may be made to our business.

 

We have prepared  the consolidated financial statements in accordance with Accounting Standards Codification 852, Reorganizations (“ASC 852”).  This guidance requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business.  Accordingly, certain expenses (including professional fees), realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings are recorded in reorganization items on the accompanying Consolidated Statements of Operations.  In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on the  Consolidated Balance Sheet at December 31, 2009 in “pre-petition liabilities subject to compromise.”  These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

 

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Table of Contents

 

3.             Summary of Significant Accounting Policies

 

Financial Statement Presentation

 

As a result of our bankruptcy filing, we have applied the authoritative guidance of ASC 852 in preparing the 2009 consolidated financial statements.  ASC 852 requires that the financial statements for periods subsequent to a chapter 11 filing separate transactions and events that are directly associated with the reorganization from the ongoing operations of the business (see Note 12).

 

ASC 852 also requires pre-petition liabilities that are subject to compromise to be reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts (see Note 13).

 

Principles of Consolidation

 

The accompanying consolidated financial statements include the accounts of Aventine and its subsidiaries.  All significant intercompany transactions and accounts have been eliminated in consolidation.

 

Prior to October 13, 2008, Aventine owned 78.4% of Nebraska Energy, L.L.C. (“NELLC”) and the remaining 21.58% of NELLC was owned by Nebraska Energy Cooperative (“NEC”).  Aventine included in its consolidated financial statements all of the revenues and expenses of NELLC and the interest therein of NEC was reflected as non-controlling interest.

 

On October 13, 2008, the Company completed its purchase of the 21.58% of NELLC that it did not already own from NEC.  The Company issued 1 million shares of its common stock, resulting in a purchase price of $6.8 million, including related costs.  As a result of the acquisition, the Company fully consolidates its interest in NELLC for all periods subsequent to the purchase date.

 

The purchase was accounted for under the purchase method of accounting in accordance with the provisions of FAS 141, Business Combinations. The purchase accounting allocation related to the acquisition has been recorded in the accompanying consolidated financial statements as of, and for the period subsequent to October 13, 2008.  The estimated fair value of assets acquired and liabilities assumed was $10.4 million and $1.7 million, respectively.  The excess of the fair value of the acquired net assets over the purchase price was allocated to reduce the carrying values of net book value of property, plant, and equipment by $1.9 million.

 

Use of Estimates

 

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the financial statements, as well as amounts of revenue and expenses during the reporting periods.  Actual results could differ from those estimates.

 

Industry Segments

 

We operate in one reportable segment, the manufacture and marketing of fuel-grade ethanol.

 

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Revenue Recognition

 

Revenue is generally recognized when title to products is transferred to an unaffiliated customer as long as the sales price is fixed or determinable and collectability is reasonably assured.  For the majority of sales, this generally occurs after the product has been offloaded at the customers’ site.  For others, the transfer of title occurs at the shipment origination point.  The majority of sales are invoiced at the final per unit price which may be a previously contracted fixed price or a market price at the time of shipment.  Other sales are invoiced and the initial receipts are collected based upon a provisional price, and such sales are adjusted to a final price in the same month based upon a monthly-average spot market price.  Sales are made under normal terms and usually do not require collateral.

 

Historically, the Company has also marketed ethanol for other third-party producers.  Revenues from such non-Company produced gallons are generally recorded on a gross basis in the accompanying statements of operations, as the Company takes title to the product, assumes all risks associated with the purchase and sale of such gallons and is considered the primary obligor on the sale.  Transactions entered into with the same counterparty which have been negotiated in contemplation of one another are recorded on a net basis.  This activity was significantly reduced due to the termination of our marketing alliance in late 2008 and early 2009 and a substantial reduction in purchase/resale activity in 2009.

 

The majority of sales are based upon freight cost being paid by the buyer, and the Company excludes such freight costs from its financial statements.  The remaining sales are based upon a delivered price, including freight, and the Company does recognize such freight costs in the financial statements.  Revenue recognized from delivered sales includes the product sale, cost of delivery, plus any respective motor fuel taxes, while revenue recognized from non-delivered sales would exclude the cost of delivery.

 

Cash Equivalents

 

We consider all highly liquid short-term investments purchased with a maturity of three months or less to be cash equivalents.  Cash equivalents are carried at cost, which approximates fair value.

 

Accounts Receivable and Concentration of Credit Risk

 

Accounts receivable are recorded on a gross basis, with no discounting, less an allowance for doubtful accounts.  Management estimates the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers, and the amount and age of past due accounts.

 

The Company sells ethanol to most of the major integrated oil companies and a significant number of large, independent refiners and petroleum wholesalers.  Our trade receivables result primarily from our ethanol marketing operations.  As a general policy, collateral is not required for receivables, but customers’ financial condition and creditworthiness are evaluated regularly.  Credit risk concentration related to our accounts receivable results from our top 10 customers having generated 54.7% and 47% of our consolidated net sales for the years ended December 31, 2009 and 2008, respectively.

 

In 2009, Biourja Trading accounted for 10.5% and Exxon Mobil accounted for 11.1% of our Net sales.  No other customers in 2009 represented more than 10% of our consolidated net sales volume.  No customers in 2008 or 2007 represented more than 10% of our consolidated net sales volume.

 

Labor Concentration

 

Approximately 55% of our full-time employees at December 31, 2009 (comprised of the hourly employees at our Illinois facilities) are covered by a collective bargaining agreement between our

 

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subsidiary, Aventine Renewable Energy, Inc., and the United Steelworkers International Union, Local 7-662.  Our contract with the Union is scheduled to expire on October 31, 2010.

 

Inventories

 

Inventories are stated at the lower of cost or market.  Cost is determined using a weighted average first-in-first-out (“FIFO”) method for gallons produced at our plants, gallons purchased from our marketing alliance partners and other gallons purchased for resale when applicable.  Inventory costs include expenditures incurred bringing inventory to its existing condition and location.

 

Property, Plant and Equipment

 

Newly acquired land, buildings and equipment are carried at cost less accumulated depreciation.  Depreciation is provided over the estimated useful lives of the assets, generally on the straight-line method for financial reporting purposes (furniture and fixtures 3 — 20 years, machinery and equipment 5 — 25 years, storage tanks 25 — 30 years, and buildings and improvements 20 — 45 years), and on accelerated methods for tax purposes.

 

Impairment of Long-Lived Assets

 

Long-lived assets are evaluated for impairment under the provisions of ASC 360, Property, Plant and Equipment.  When facts and circumstances indicate that long-lived assets used in operations may be impaired, and the undiscounted cash flows estimated to be generated from those assets are less than their carrying values, an impairment charge is recorded equal to the excess of the carrying value over fair value.

 

Investments in Marketing Alliances

 

We have previously made non-controlling investments in other ethanol producers.  Investments made by the Company in other ethanol producers are recorded on the cost basis and aggregated $1 million as of December 31, 2008.  All such investments were sold during 2009 with a recognized gain of $1 million.

 

Available for sale securities

 

In 2008, Indiana Bio-Energy, LLC (“IBE”), one of our cost basis investees, was acquired by Green Plains Renewable Energy (“GPRE”).  Our investment in IBE was valued at December 31, 2007 at our initial investment cost of $5.0 million.  On October 15, 2008, IBE merged with GPRE, a publically held company whose shares are traded on the NASDAQ national market, and our $5.0 million original investment was converted to 365,999 shares of GPRE stock.  On October 15, 2008, we recorded a loss of $2.8 million on the exchange and reduced the value of our investment from $5.0 million to $2.2 million, which was the market price of the GPRE shares at that date.  As our investment in GPRE shares is considered an available for sale investment in accordance with ASC 320, we recognized an other than temporary loss of $1.5 million on December 31, 2008.  In making our determination that the loss in GPRE stock was other than temporary, we considered our lack of ability and intent to hold this security to recover its value given our  liquidity situation at that time.  Available for sale securities are presented in the balance sheet at fair market value.  Cumulative unrealized holding gains and losses are presented in “Accumulated other comprehensive income (loss)” in the stockholders’ equity section of our consolidated balance sheets.  The market value of our investment in GPRE at December 31, 2009 based upon the closing price of GPRE stock on the last trading day of 2009 was $5.4 million.

 

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Employment-Related Benefits

 

Employment-related benefits associated with pensions and postretirement health care are expensed as actuarially determined.  The recognition of expense is impacted by estimates made by management, such as discount rates used to value certain liabilities, investment rates of return on plan assets, increases in future wage amounts and future health care costs.  The Company uses third-party specialists to assist management in appropriately measuring the expense and liabilities associated with employment-related benefits.

 

We determine our actuarial assumptions for the pension and post retirement plans, after consultation with our actuaries, on December 31 of each year to calculate liability information as of that date and pension and postretirement expense for the following year.  The discount rate assumption is determined based on a spot yield curve that includes bonds that are rated Corporate AA or higher with maturities that match expected benefit payments under the plan.

 

The expected long-term rate of return on plan assets reflects projected returns for the investment mix that have been determined to meet the plans’ investment objectives.  The expected long-term rate of return on plan assets is selected by taking into account the expected weighted averages of the investments of the assets, the fact that the plan assets are actively managed to mitigate downside risks, the historical performance of the market in general and the historical performance of the retirement plan assets over the past ten years.

 

Income Taxes

 

Under ASC 740, deferred tax liabilities and assets are recorded for the expected future tax consequences of events that have been recognized in our financial statements or tax returns.  Property, plant and equipment, stock-based compensation expense and investments in marketing alliance partners are the primary sources of these temporary differences.  Deferred income taxes also includes net operating loss and capital loss carryforwards.  The Company establishes valuation allowances to reduce deferred tax assets to amounts it believes are realizable and contingency reserves for implemented tax planning strategies.  These valuation allowances and contingency reserves are adjusted based upon changing facts and circumstances.

 

Earnings Per Common Share

 

Basic earnings per share is computed by dividing net income by the weighted-average number of common shares outstanding.  Diluted earnings per share is calculated by including the effect of all dilutive securities, including stock options.  To the extent that stock options and unvested restricted stock are anti-dilutive, they are excluded from the calculation of diluted earnings per share.

 

Derivatives and Hedging Activities

 

Our operations and cash flows are subject to fluctuations due to changes in commodity prices.  Historically, we have used derivative financial instruments to manage commodity prices.  Derivatives used were primarily commodity futures contracts, swaps and option contracts.  No derivative financial instruments have been approved by the Bankruptcy Court for use by the Company.

 

We applied the provisions of ASC 815, Derivatives and Hedging,  for the Company’s derivatives.  These futures contracts were not designated as hedges and, therefore, were marked to market each period, with corresponding gains and losses recorded in other non-operating income.  The fair value of these derivative instruments was recognized in other current assets or liabilities in the Consolidated Balance Sheet, net of any cash received from the brokers.

 

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ASC 815 requires a company to evaluate contracts to determine whether the contracts are derivatives.  Certain contracts that meet the literal definition of a derivative under ASC 815 may be exempted from the accounting and reporting requirements of ASC 815 as normal purchases or normal sales.  Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business.  The Company elects to designate its forward purchases of corn and natural gas and forward sales of ethanol as normal purchases and normal sales under ASC 815.  Accordingly, these contracts are not reflected in the consolidated financial statements  until execution.  As a result, we have significantly reduced our hedging activity since the first quarter of 2009.

 

Fair Values of Financial Instruments

 

We use the following methods in estimating fair value disclosures for financial instruments:

 

Cash and equivalents, accounts receivable and accounts payable:  The carrying amount reported in the Consolidated Balance Sheets approximates fair value.

 

Revolving credit facility and long-term debt:  The carrying amount of our borrowings under our revolving credit facilities approximates fair value.  The fair value of our senior unsecured 10% fixed-rate notes are based upon quoted closing market prices at year-end.

 

Commodity derivatives:  Commodity derivative instruments entered into periodically by the Company consist of futures contracts, swaps and option contracts.  The fair value of these commodity derivative instruments are determined by reference to quoted market prices.

 

Available for sale securities:  Available for sale securities consist of a common stock investment in exchanged traded securities and the fair value of these securities is determined using quoted market prices at year-end.

 

Environmental Expenditures

 

Environmental expenditures that pertain to our current operations and relate to future revenue are expensed or capitalized consistent with our capitalization policy.  Expenditures that result from the remediation of an existing condition caused by past operations, and that do not contribute to future revenue, are expensed.

 

Research and Development Costs

 

Expenditures relating to the development of new products and processes, including significant improvements and refinements to existing products, are expensed as incurred.  The amounts charged to expense were approximately $0.0 million, $0.1 million and $0.3 million for the years ended 2009, 2008 and 2007, respectively.

 

Recent Accounting Pronouncements

 

In December 2008, the Financial Accounting Standards Board (FASB) issued FSP No. FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets, which requires enhanced disclosures about plan assets in an employer’s defined benefit pension or other post-retirement plan.  These disclosures are intended to provide users of financial statements with a greater understanding of how

 

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investment allocation decisions are made, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets and significant concentrations of risk within plan assets. We adopted this pronouncement in 2009.

 

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interest in Consolidated Financial Statements.  This Statement changes the way the consolidated income statement is presented.  It requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest.  Previously, net income attributable to the noncontrolling interest generally was reported as an expense or other deduction in arriving at consolidated net income.  This Statement was effective for us as of January 1, 2009.  The presentation and disclosure requirements of this statement are applied retrospectively for all periods presented.

 

In May 2009, the FASB issued SFAS No. 165, Subsequent Events (“SFAS 165”).  SFAS 165 establishes general standards of accounting for disclosing events that occur after the balance sheet date but before financial statements are issued or are available to be issued.  It requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for selecting that date, that is, whether that date represents the date the financial statements were issued or were available to be issued.  SFAS 165 is effective for interim or annual financial periods ending after June 15, 2009.  We adopted FAS 165 in the second quarter of 2009.

 

On July 1, 2009, the FASB Accounting Standards Codification became the single source of authoritative U.S. GAAP (other than rules and interpretive releases of the U.S. Securities and Exchange Commission).  The Codification is topically based with topics organized by ASC number and updated with Accounting Standards Updates (“ASUs”).  ASUs replace accounting guidance that was historically issued as Statements of Financial Accounting Standards (“SFAS”), FASB Interpretations (“FIN”), FASB Staff Positions (“FSP”), Emerging Issue Task Force (“EITF”) Abstracts and other types of accounting standards.  The Codification became effective July 1, 2009 for the Company and disclosures within this report have been updated to reflect the change.

 

In January 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.  ASU 2010-06 requires new disclosures and clarifies some existing disclosures regarding fair value measurements.  ASU 2010-06 is effective in the first quarter of 2010.

 

4.             Related Party Transactions

 

As of May 30, 2003, the date we were acquired from the William’s Companies, Aventine’s principal shareholders were the Morgan Stanley Capital Partners (“MSCP”) funds.  Morgan Stanley Investment Management, Inc. subsequently entered into definitive agreements under which Metalmark Subadvisor LLC, an affiliate of Metalmark, an independent private equity firm established by former principals of MSCP, manages the MSCP funds on a sub-advisory basis.  In January 2008, substantially all of the employees of Metalmark became employees of Citi Alternative Investments, Inc., although Metalmark remains an independent entity owned by those individuals and continues to manage the applicable MSCP funds on a sub-advisory basis.  The MSCP funds owned 27.5% of our common stock at December 31, 2008 and 2009.

 

Two of the Company’s directors are currently employees of Metalmark.  Our amended and restated certificate of incorporation provides that directors may not be removed from office by the stockholders

 

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except for cause and only by an affirmative vote of the holders of not less than 85% of the voting power of the issued and outstanding shares of our capital stock entitled to vote generally at an election of directors.

 

In exchange for providing professional expertise, services, consulting, or advice in accordance with an agreement entered into with one of the MSCP funds prior to the MSCP funds’ acquisition of the Company, the directors received Class B units in Aventine Holdings LLC (Aventine Holdings, LLC is the investment vehicle in which MSCP holds the common stock of the Company).  Class B units have no voting rights, participate in distributions only after a specified threshold is met, and are subject to certain additional limitations.

 

5.             Inventories

 

Inventories are as follows at December 31:

 

(In thousands)

 

2009

 

2008

 

 

 

 

 

 

 

Finished products

 

$

17,664

 

$

76,968

 

Work-in-process

 

2,430

 

2,568

 

Raw materials

 

2,938

 

3,600

 

Supplies

 

1,205

 

2,285

 

Totals

 

$

24,237

 

$

85,421

 

 

6.             Prepaid Expenses and Other Current Assets

 

Prepaid expenses and other current assets are as follows at December 31:

 

(In thousands)

 

2009

 

2008

 

 

 

 

 

 

 

Prepaid motor fuel taxes and other miscellaneous receivables

 

$

 

$

3,667

 

Fair value of derivative instruments

 

 

1,521

 

Prepaid insurance

 

3,257

 

1,435

 

Deferred income taxes current

 

979

 

1,593

 

Prepaid inventory

 

1,197

 

512

 

Prepaid benefits

 

279

 

364

 

Prepaid utility deposits

 

926

 

 

Other prepaid expenses

 

778

 

1,106

 

Other current assets

 

886

 

 

Totals

 

$

8,302

 

$

10,198

 

 

7.             Fair Value Measurements

 

ASC 820

 

The Company adopted ASC 820 effective January 1, 2008 for financial assets and liabilities measured at fair value on a recurring basis.  The Company adopted ASC 820 for nonfinancial assets and nonfinancial liabilities effective January 1, 2009.  ASC 820 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis.  There was no impact of adoption of ASC 820 to the consolidated balance sheet or statement of operations.  ASC 820 establishes a framework for measuring fair value and expands disclosure about fair value measurements.  The statement requires that fair value measurements be classified and disclosed in one of the following three categories:

 

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·                  Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;

 

·                  Level 2: Quoted prices in markets that are not active, for inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability;

 

·                  Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity).

 

In October 2008, the FASB issued FSP 157-3 (“FSP 157-3”), Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active.  FSP 157-3 clarifies the application of ASC 820 in a market that is not active, and addresses application issues such as the use of internal assumptions when relevant observable data does not exist, the use of observable market information when the market is not active, and the use of market quotes when assessing the relevance of observable and unobservable data.  FSP 157-3 is effective for all periods presented in accordance with SFAS No. 157.  There was no impact upon the adoption of FSP 157-3 to the consolidated financial statements or the fair values of our financial assets and liabilities.

 

The following table summarizes the valuation of our financial instruments which are carried at fair value by the above ASC 820 pricing levels as of December 31, 2009:

 

 

 

 

 

Fair Value Measurements at the Reporting Date Using

 

 

 

Fair Value
at
December 31,
2009

 

Quoted Prices in
Active Markets
Using Identical
Assets
(Level 1)

 

Significant Other
Observable
Inputs

(Level 2)

 

Significant
Unobservable
Inputs
(Level 3)

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

52,585

 

$

52,585

 

$

 

$

 

Available for sale securities

 

5,442

 

5,442

 

 

 

 

The Company did not hold any financial assets requiring the use of Level 2 or Level 3 inputs during 2009.

 

In 2008, the Company recorded losses from Level 3 assets (auction rate securities) of $30.1 million.  In addition, the Company also sold auction rate securities prior to these assets being classified as Level 3 assets incurring a loss of $1.5 million.  The total losses incurred by the Company in 2008 related to auction rate securities were $31.6 million.  This loss was included in “loss on sale of auction rate securities” in the Consolidated Statement of Operations.  The Company held no auction rate securities as of December 31, 2008 or 2009.

 

The Company recorded net gains of $1.2 million and $17.1 million, respectively,  for the full-years ended December 31, 2009 and 2008 under “other non-operating income” in the Condensed Consolidated Statements of Operations for the changes in the fair value of its derivative transactions.

 

The Company recorded a loss of $4.3 million for the year-ended December 31, 2008 relating to an other than temporary investment loss in a marketing alliance partner, now classified as available for sale.  The 2008 loss was recorded in the Condensed Consolidated Statements of Operations as “Loss on marketing alliance investment.”

 

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ASC 825

 

The Company adopted ASC 825 effective January 1, 2008.  We have not elected the fair value option for any of our financial assets or liabilities.

 

The carrying value of other financial instruments, including cash, accounts receivable, accounts payable and accrued liabilities and amounts owed under our secured revolving credit facility approximate fair value due to their short maturities or variable-rate nature of the respective balances.  The following table presents the other financial instruments that are not carried at fair value but which require fair value disclosure as of December 31, 2009 and 2008.

 

 

 

As of December 31, 2009

 

As of December 31, 2008

 

 

 

Carrying Value

 

Fair Value

 

Carrying Value

 

Fair Value

 

Investment in other ethanol producers, at cost

 

 

 

$

1,000

 

n/a

 

Commodity margin deposits

 

 

 

$

1,521

 

$

1,521

 

Senior Unsecured Notes

 

$

(300,000

)

$

(267,000

)

$

(300,000

)

$

(49,500

)

 

Prior to 2008, the Company’s investments in minority positions of other ethanol operating companies have historically been recorded at cost, as these investments were in non-publicly traded companies for which it was not practical to estimate a fair value.  In October 2008, one of the investments made by the Company was exchanged for shares in a NASDAQ listed publicly traded entity which we recorded at fair value.

 

8.                                      Property, Plant and Equipment

 

Property, plant and equipment at December 31 are as follows:

 

(In thousands)

 

2009

 

2008

 

 

 

 

 

 

 

Land and improvements

 

$

1,659

 

$

1,659

 

Building and improvements

 

5,391

 

5,391

 

Machinery and equipment

 

134,164

 

132,700

 

Storage tanks

 

4,634

 

3,108

 

Furniture and fixtures

 

25

 

25

 

Less accumulated depreciation

 

(50,082

)

(35,715

)

Totals

 

$

95,791

 

$

107,168

 

 

 

 

 

 

 

Construction-in-progress

 

$

493,258

 

$

493,969

 

 

Depreciation expense in 2009, 2008 and 2007 was $14.4 million, $14.5 million and $12.6 million, respectively.

 

In 2008, we recorded an impairment charge of $1.6 million relating to our decision to indefinitely suspend development of our Pekin III facility.

 

Construction-in-progress at December 31, 2009 includes $23.2 million of capitalized costs which are due to the Company’s primary construction contractor, Kiewit.  This obligation was due in installments through June 2009.  Subsequent to December 31, 2008, the Company ceased making payments to Kiewit on amounts owed and Kiewit has filed liens against the construction projects.  On March 9, 2009, the Company received a notice from Kiewit cancelling the engineering, construction and procurement contracts for the Aurora West and Mt. Vernon expansion projects, referencing our failure to make a payment under the

 

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change order agreements dated December 31, 2008.  As a result, all remaining payments due to it and its sub-contractors totaling $23.2 million at December 31, 2009 are due and payable.  Under our proposed Plan of Reorganization, we intend to pay $17.9 million in cash and issue a note payable to Kiewit for the remainder of $5.3 million.

 

Under the proposed Plan of Reorganization, it is contemplated that the expansion projects at Mt. Vernon and Aurora West, on which construction has been suspended, will be completed following emergence from Bankruptcy.

 

The 2009 construction accrual has been treated as a non-cash item in the accompanying Statement of Cash Flows.

 

9.                                      Restricted Cash

 

Restricted cash of $7.5 million represents cash held in segregated bank accounts of the Company, which is set aside as collateral to fund certain letters of credit and utility deposits.

 

10.                               Other Assets

 

Other assets at December 31 are as follows:

 

(In thousands)

 

2009

 

2008

 

 

 

 

 

 

 

Deferred debt issuance costs

 

$

396

 

$

6,668

 

Prepaid utility costs and deposits

 

9,470

 

 

Totals

 

$

9,866

 

$

6,668

 

 

Deferred debt issuance costs are subject to amortization.  Remaining deferred debt issuance costs of $0.4 million related to our secured revolving credit facility and our debtor-in-possession debt facility will be fully amortized by the end of the first quarter of 2010.

 

In conjunction with the construction of our new ethanol plant at Mt. Vernon, Indiana, the Company negotiated with certain utility providers to extend an existing natural gas pipeline to supply power for and construct electrical infrastructure for the new Mt. Vernon facility.  In order to provide adequate assurance for the construction costs of the pipeline and electrical infrastructure, the Company, under its secured revolving credit facility, issued letters of credit to the utility providers in the aggregate amount of $15.3 million.  As a result of our suspending construction and our Bankruptcy Filing, one of the utility providers noted above has drawn $9.0 million on its respective letter of credit.  A second utility provider has filed a claim under the Company’s bankruptcy proceedings and also filed a mechanic’s lien on the Company’s Mt. Vernon facility, which is partially collateralized by a letter of credit.  The Company expects this $8.2 million claim and related mechanic’s lien will be allowed to stand unabated through its bankruptcy confirmation proceedings.  Accordingly, the Company has reflected prepaid utility costs and deposits equal to its obligations to utility providers under drawn letters of credit and secured liens, excluding cash funded letters of credit described below.  We expect the prepaid utility costs and deposits to reduce cash outlays for future utility demand charges to the Company or a potential buyer once the Mt. Vernon facility has been completed and is operational.  Should the Mt. Vernon facility not be completed, we may be unable to recover any amounts and would be required to reduce the value of this asset to zero.

 

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11.                               Other Current Liabilities

 

Other current liabilities are as follows at December 31:

 

(In thousands)

 

2009

 

2008

 

Deferred revenue

 

$

4,513

 

$

8,425

 

Accrued sales taxes

 

10

 

339

 

Deferred income taxes

 

979

 

507

 

Accrued property taxes

 

817

 

575

 

Other accrued operating expenses

 

65

 

54

 

Reserve for uncertain tax positions (See Note 20)

 

855

 

 

Accrued interest on uncertain tax positions (See Note 20)

 

19

 

 

Totals

 

$

7,258

 

$

9,900

 

 

12.                               Debt

 

The following table summarizes the Company’s outstanding debt at December 31:

 

(In thousands)

 

2009

 

2008

 

Senior unsecured 10% notes due April 2017

 

$

300,000

 

$

300,000

 

Secured revolving credit facility

 

27,765

 

52,200

 

Debtor-in-possession debt facility

 

15,000

 

 

 

 

342,765

 

352,200

 

Less: reclassification to pre-petition liabilities subject to compromise

 

(300,000

)

 

Less: short-term borrowings

 

(42,765

)

(352,200

)

Total long-term debt

 

$

 

$

 

 

Senior Unsecured Notes

 

As of December 31, 2009, the Company had outstanding $300 million aggregate principal amount of Senior Unsecured Notes.  The Notes were issued pursuant to an indenture dated as of March 27, 2007, between the Company and Wells Fargo Bank, N.A., as trustee and were exchanged for registered notes with the same terms on August 10, 2007.  The Notes are general unsecured obligations of the Company and its subsidiaries.  In April 2009, Deutsche Bank National Trust Company replaced Wells Fargo Bank as Successor Indenture Trustee.  As a result of the Bankruptcy Filing, the outstanding principal amount of the Notes and accrued interest thereon became immediately due and payable, and the Notes have been reclassified to “pre-petition liabilities subject to compromise” (see Note 14).  The Company discontinued the accrual of interest on these Notes beyond the petition date of April 7, 2009.  Contractual interest expense not recorded from April 8, 2009 through December 31, 2009 would have totaled $21.9 million.

 

Secured Revolving Credit Facility

 

As of December 31, 2009, $9.6 million in letters of credit and $27.8 million in revolving loans were outstanding under our pre-petition amended secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent and a lender.  As a result of our Bankruptcy Filing, all the commitments under the Company’s pre-petition secured revolving credit facility automatically terminated, and the principal of the loans and the reimbursement obligations then outstanding, together with accrued interest thereon and any unpaid fees and all other obligations of the borrowers accrued under the applicable loans documents, became immediately due and payable, subject to the automatic stay provisions of Section 362 of the Bankruptcy Code.  As a result, there is no longer any liquidity available to us under this facility.  Amounts owed under the Company’s pre-petition secured revolving credit facility have not been included in “pre-petition liabilities subject to compromise” as the secured debt is adequately collateralized.  The

 

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Secured Revolving Credit Facility is collateralized by a first security lien on essentially all of the Company’s assets, except for assets of the Mt. Vernon facility.  The Company continues to accrue and pay interest on this credit facility in accordance with the Bankruptcy Court’s final debtor-in-possession financing order.  As of December 31, 2009, the Company holds a restricted cash account totaling $7.0 million providing collateral protection to the pre-petition lenders for certain outstanding letters of credit issued under this facility as provided for in a stipulation agreement among the Company, its pre-petition secured lenders, and the DIP Facility lenders.

 

Prior to our Bankruptcy Filing, availability under the secured revolving credit facility was determined via a borrowing base, which includes a percentage of eligible receivables and inventory, and no more than $10 million of property, plant and equipment.  Effective with the bankruptcy petition date and related automatic termination of commitments as discussed above, the Company has no borrowing availability under its secured revolving credit facility.

 

Prior to our Bankruptcy Filing, borrowings on the amended facility generally bore interest, at our option, at the following rates (i) the Eurodollar rate or the LIBO rate plus a margin of 4.5%, with a LIBO rate minimum of 3%, or (ii) the greater of the prime rate or the federal funds rate plus 0.50% (with a minimum rate of LIBOR plus 2.25%), plus a margin of 3.25%.  In addition, the following fees were also applicable: an unused commitment fee of 0.50% on unused borrowing availability, an outstanding letters of credit fee of 4.625%, and administrative and legal costs.

 

Effective with the Bankruptcy Filing, the interest rate on the revolving credit facility loan reverted to a default rate of 10.5% per annum, while fees for outstanding letters of credit reverted to a default rate of 6.625% per annum.  Accrued interest and other fees are payable monthly.

 

Debtor-in-possession Debt Facility

 

As of December 31, 2009, the Company has drawn $15 million of its $30 million DIP Facility.  The DIP Facility provides for a first priority term loan in a maximum aggregate principal amount of up to $30 million.  Proceeds of the DIP Facility can be used, among other things, to (i) fund the working capital and general corporate needs of the Debtors and the costs of the Bankruptcy Cases in accordance with an approved budget, and (ii) provide adequate protection, in accordance with the terms of the DIP Facility, to the pre-petition agent and pre-petition lenders under the Company’s existing credit facilities.  The DIP Facility bears interest at 16.5%.  The maturity date of the DIP Facility is April 6, 2010, or upon the occurrence of certain pre-defined events including emergence from bankruptcy.  The DIP Facility is secured by a super-priority administrative expense claim on our assets.  As of December 31, 2009, the Debtors are in compliance with the terms of the DIP Facility.  The Company accrues and pays interest expense on this DIP Facility in accordance with the Bankruptcy Court’s final order approving the DIP Facility.

 

13.                               Reorganization Items

 

ASC 852 requires separate disclosure of reorganization items such as realized gains and losses from the settlement of pre-petition liabilities, provisions for losses resulting from the reorganization and restructuring of the business, as well as professional fees directly related to the process of reorganizing the Debtors under Chapter 11.  The Debtors’ reorganization items during 2009 consist of the following:

 

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Year ended
December 31,

 

(in thousands)

 

2009

 

 

 

 

 

Provision for rejected executory contracts and leases

 

$

26,403

 

Professional fees directly related to reorganization (a)

 

7,449

 

Interest income

 

(3

)

Other (b)

 

(1,409

)

Total reorganization items

 

$

32,440

 

 


(a)       Professional fees directly related to the reorganization include post-petition fees associated with advisors to the Debtors, the statutory committee of unsecured creditors and certain secured creditors. Professional fees are estimated by the Debtors and will be reconciled to actual invoices when received.

(b)      Other includes gains on the settlement of pre-petition critical vendor claims for less than amounts owed and other adjustments.

 

14.                               Pre-Petition Liabilities Subject to Compromise

 

Pre-petition liabilities subject to compromise refers to unsecured obligations that will be accounted for under a plan of reorganization.  Generally, actions to enforce or otherwise effect payment of pre-Chapter 11 liabilities are stayed.  ASC 852 requires pre-petition liabilities that are subject to compromise to be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts.  These liabilities represent the estimated amount expected to be allowed on known or potential claims to be resolved through the Chapter 11 process, and remain subject to future adjustments arising from negotiated settlements, actions of the Bankruptcy Court, rejection of executory contracts and unexpired leases, the determination as to the value of any potential collateral securing the claims, proofs of claim, or other events.  Pre-petition liabilities subject to compromise also include certain items that may be assumed under the plan of reorganization, and as such, may be subsequently reclassified to liabilities not subject to compromise.  At hearings held in April 2009, the Court granted final approval of many of the Debtors’ First Day Motions covering, among other things, human capital obligations, supplier relations, insurance, customer relations, business operations, certain tax matters, cash management, utilities, case management and retention of professionals.  Obligations associated with these matters are not classified as pre-petition liabilities subject to compromise.

 

In accordance with ASC 852, debt issuance costs associated with borrowing classified as pre-petition liabilities subject to compromise should be viewed as valuation adjustments to the related debt.  When the debt has become an allowed claim and the allowed claim differs from the net carrying amount of the debt, the recorded amount should be adjusted to the amount of the allowed claim (thereby adjusting existing debt issuance costs to the extent necessary to report the debt at this allowed amount).  Through December 31, 2009, the Bankruptcy Court had not classified any of the Debtors’ outstanding debt as allowed claims. The Company has classified the Debtors’ Notes as “pre-petition liabilities subject to compromise on the Condensed Consolidated Balance Sheet.  The Company has not adjusted debt issuance costs, totaling $5.8 million at December 31, 2009, related to the Debtors’ Notes, but has classified these costs as “pre-petition liabilities subject to compromise.”  The Company may be required to expense these amounts or a portion thereof upon determination of the allowed claim by the Bankruptcy Court.

 

The Debtors have rejected certain pre-petition executory contracts and unexpired leases with respect to the Debtors’ operations with the approval of the Bankruptcy Court and may reject additional agreements in the future.  Damages resulting from rejection of executory contracts and unexpired leases are

 

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generally treated as general unsecured claims and will be classified as “pre-petition liabilities subject to compromise.”  Holders of pre-petition claims (excluding governmental entities holding governmental claims) were required to file proofs of claims by the “general bar date”, which was September 8, 2009.  A bar date is the date by which certain claims against the Debtors must be filed if the claimants wish to receive any distribution in the Chapter 11 cases on account of such claims.  Creditors were notified of the general bar date and the requirement to file a proof of claim with the Bankruptcy Court.  Differences between liability amounts estimated by the Debtors and claims filed by creditors are being investigated and, if necessary, the Bankruptcy Court will make a final determination of the allowable claim.  The determination of how liabilities will ultimately be treated cannot be made until the Bankruptcy Court approves a Chapter 11 plan of reorganization.  Accordingly, the ultimate amount or treatment of such liabilities is not determinable at this time.  Amounts recorded at December 31, 2009 are the Company’s best estimate of the amounts that the Bankruptcy Court will allow as a claim.

 

Pre-petition liabilities subject to compromise consist of the following at December 31:

 

(In thousands)

 

2009

 

 

 

 

 

10% senior unsecured notes due 2017

 

$

300,000

 

Provision for rejected executory contracts and other accruals

 

26,403

 

Pre-petition accounts payable

 

29,451

 

Accrued interest on Notes

 

15,500

 

Unamortized issuance costs of 10% senior unsecured notes

 

(5,805

)

Total pre-petition liabilities subject to compromise

 

$

365,549

 

 

Pre-petition liabilities subject to compromise include trade accounts payable related to pre-petition purchases.  As a result, the Company’s cash flows from operations were favorably affected by the stay of payment related to these accounts payable.  Accrued interest represents amounts due on the Notes as of the Petition Date.  No interest has been accrued on the Notes subsequent to the Petition Date because such amounts are not expected to become part of an allowed claim.

 

15.                               Other Long-Term Liabilities

 

Other long-term liabilities at December 31 are as follows:

 

(In thousands)

 

2009

 

2008

 

 

 

 

 

 

 

Unfunded postretirement benefit obligation

 

$

1,984

 

$

1,834

 

Unfunded pension liability

 

442

 

1,491

 

Pre-petition liabilities not compromised

 

11,501

 

 

Reserve for uncertain tax positions (See Note 20)

 

 

848

 

Accrued interest on uncertain tax positions (See Note 20)

 

 

26

 

Totals

 

$

13,927

 

$

4,199

 

 

The pre-petition liabilities not compromised consist of pre-petition accounts payable secured by liens, and pre-petition payables which are priority claims and will be paid in full.

 

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16.                               Interest Expense

 

The following table summarizes interest expense:

 

 

 

Year Ended December 31,

 

(in thousands)

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Interest expense — senior unsecured notes

 

$

8,083

 

$

30,000

 

$

22,833

 

Interest expense — revolving credit facility

 

2,464

 

188

 

3

 

Interest expense — debtor in possession debt facility

 

1,785

 

 

 

Amortization of deferred debt issuance costs

 

2,343

 

943

 

693

 

Other

 

22

 

5

 

7

 

Less capitalized interest

 

 

(26,059

)

(7,296

)

Total interest expense

 

$

14,697

 

$

5,077

 

$

16,240

 

 

The Company discontinued the accrual of interest on the Notes beyond the bankruptcy petition date of April 7, 2009.

 

The capitalization of interest expense was discontinued when construction on the Mt. Vernon and Aurora West expansion facilities was suspended in December 2008.

 

17.                               Retirement and Pension Plans

 

We have 401(k) plans covering substantially all of our employees. We provide, at our discretion, a match of employee salaries contributed to the plans.  We recorded expense with respect to these plans of $0.9 million in 2009, $1.1 million in 2008, and $1.0 million in 2007.

 

Qualified Retirement Plan

 

We have a defined benefit pension plan (Retirement Plan) that is noncontributory which covers unionized employees at our Pekin, Illinois facility who fulfill minimum age and service requirements.  Benefits are based on a prescribed formula based upon the employee’s years of service.  The Retirement Plan was amended in 2006 to increase the Company’s contribution rate for years of service in response to provisions in a new labor agreement between the Company and its unionized employees, which became effective in June 2006.

 

The average asset allocations for our Retirement Plan at December 31 are as follows:

 

 

 

2009

 

2008

 

 

 

 

 

 

 

Equity securities

 

54

%

54

%

Debt securities

 

46

 

36

 

Cash and equivalents

 

 

10

 

Total

 

100

%

100

%

 

The Company’s Pension Committee is responsible for overseeing the investment of pension plan assets.  The Pension Committee is responsible for determining and monitoring the appropriate asset allocations and for selecting or replacing investment managers, trustees, and custodians.  The pension plan’s current investment target allocations are 50% equities and 50% debt.  The Pension Committee

 

F-24



 

reviews the actual asset allocation in light of these targets periodically and rebalances investments as necessary.  The Pension Committee also evaluates the performance of investment managers as compared to the performance of specified benchmarks and peers and monitors the investment managers to ensure adherence to their stated investment style and to the plan’s investment guidelines.

 

On December 31, 2009, the annual measurement date, our Retirement Plan had a projected accumulated benefit obligation of $9.3 million and the fair value of the plan assets was $8.8 million.  In accordance with ASC 715, we recognized the underfunded status of the plan by recording an accrued pension liability of $0.4 million.  The offsetting amount charged to accumulated other comprehensive loss adjusts the total in other comprehensive loss to $1.3 million pre-tax, which is the amount of the net unrecognized actuarial loss and unrecognized prior service cost.

 

Items not yet recognized as a component of net periodic pension cost and amounts recognized in the Consolidated Balance Sheets are as follows at December 31:

 

(In thousands)

 

2009

 

2008

 

Funded/(unfunded) status

 

$

(442

)

$

(1,491

)

 

 

 

 

 

 

Amounts recognized in

 

 

 

 

 

Long-term liabilities

 

$

(442

)

$

(1,491

)

Deferred taxes

 

1,039

 

1,550

 

Accumulated other comprehensive loss:

 

 

 

 

 

Unamortized prior service cost

 

447

 

490

 

Unamortized net actuarial loss/(gain)

 

2,216

 

3,483

 

 

The amount of unamortized prior service costs that will be recognized as a component of net periodic pension cost in 2010 is expected to be $42 thousand.  The amount of unamortized net actuarial losses that will be recognized as a component of net periodic pension cost in 2010 is expected to be $93 thousand.

 

Certain assumptions utilized in determining the benefit obligations for the Retirement Plan for the years ended December 31 are as follows:

 

 

 

2009

 

2008

 

Discount rate

 

5.87

%

6.00

%

 

A summary of the components of net periodic pension cost for the Retirement Plan for the years ended December 31 is as follows:

 

(In thousands)

 

2009

 

2008

 

2007

 

Service cost

 

$

339

 

$

288

 

$

351

 

Interest cost

 

508

 

496

 

497

 

Expected return on plan assets

 

(561

)

(716

)

(720

)

Amortization of net actuarial loss

 

178

 

 

25

 

Amortization of prior service cost

 

42

 

42

 

42

 

Net periodic pension cost

 

$

506

 

$

110

 

$

195

 

 

We recognized no amortization of our net actuarial loss in 2008, as losses as of January 1, 2008 did not exceed 10% of our projected benefit obligation.

 

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Table of Contents

 

Certain assumptions utilized in determining the net periodic benefit cost for the years ended December 31 are as follows:

 

 

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Discount rate

 

6.00

%

6.50

%

5.75

%

Expected long-term rate of return on plan assets

 

7.75

%

7.75

%

8.50

%

 

The following table sets forth a reconciliation of the projected benefit obligation for the years ended December 31:

 

(In thousands)

 

2009

 

2008

 

 

 

 

 

 

 

Benefit obligation at the beginning of the year

 

$

8,805

 

$

7,815

 

Service costs

 

339

 

288

 

Interest costs

 

508

 

496

 

Actuarial (gain)/loss

 

20

 

568

 

Benefits paid

 

(391

)

(361

)

Benefit obligation at the end of the year

 

$

9,281

 

$

8,805

 

 

At December 31, 2009 and 2008, the projected benefit obligation and the accumulated benefit obligation are equal.

 

The actuarial loss for the year ended December 31, 2009 results primarily from the decrease in the discount rate used in the calculation of the benefit obligation to 6.00% from 6.50%.  The actuarial gain for the year ended December 31, 2008 results primarily from the increase in the discount rate used in the calculation of the benefit obligation to 6.50% from 5.75%.

 

The following table sets forth a reconciliation of the plan assets for the years ended December 31:

 

(In thousands)

 

2009

 

2008

 

 

 

 

 

 

 

Fair value of plan assets at the beginning of the year

 

$

7,314

 

$

8,999

 

Employer contributions

 

246

 

880

 

Actual return on plan assets

 

1,670

 

(2,204

)

Benefits paid

 

(391

)

(361

)

Fair value of plan assets at the end of the year

 

$

8,839

 

$

7,314

 

 

In 2010, we anticipate making contributions totaling $0.8 million.

 

The expected future benefits payments for the plan are as follows:

 

(in thousands)

 

 

 

2010

 

$

416

 

2011

 

437

 

2012

 

456

 

2013

 

493

 

2014

 

521

 

2015 — 2019

 

$

2,934

 

 

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Table of Contents

 

Plan Assets

 

Plan assets are invested using a total return investment approach whereby a mix of equity securities and debt securities are used to preserve asset values, diversify risk and achieve our target investment return benchmark. Investment strategies and asset allocations are based on careful consideration of plan liabilities, the plan’s funded status and our financial condition. Investment performance and asset allocation are measured and monitored on an ongoing basis.

 

Plan assets are managed in a balanced portfolio comprised of two major components: an equity portion and a fixed income portion. The expected role of Plan equity investments is to maximize the long-term real growth of Fund assets, while the role of fixed income investments is to generate current income, provide for more stable periodic returns and provide some protection against a prolonged decline in the market value of Fund equity investments.

 

Equity securities include U.S. and international equity, while fixed income securities include long-duration and high-yield bond funds.

 

The fair values of our pension plan assets at December 31, 2009 by asset category are as follows:

 

Asset Category

 

Market
Value at
12/31/09

 

Quoted Prices in Active
Markets for Identical
Assets (Level 1)

 

Significant
Observable Inputs
(Level 2)

 

Significant
Unobservable
Inputs (Level 3)

 

Large Cap U.S. Equity Securities (a)

 

$

2,996

 

$

 

$

2,996

 

$

 

Small/Mid Cap U.S. Equity Securities (b)

 

$

572

 

$

 

$

572

 

$

 

International Equity Securities (c)

 

$

1,047

 

$

 

$

1,047

 

$

 

Real Estate Mutual Fund (d)

 

$

145

 

$

 

$

145

 

$

 

Debt Securities (e)

 

$

4,079

 

$

 

$

4,079

 

$

 

Total Pension Assets

 

$

8,839

 

$

 

$

8,839

 

$

 

 


(a)          This category includes investments in equity securities of large U.S. companies.  The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

 

(b)         This category includes investments in equity securities of small and medium sized U.S. companies.  The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

 

(c)          This category includes investments in equity securities of foreign companies including emerging markets.  The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

 

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(d)         This category includes investments in a single mutual fund which invests in real estate.  The funds are valued using a publicly quoted market price of the mutual fund, although the value of the separate account is not publicly available.

 

(e)          This category includes investments in U.S. and foreign investment grade fixed income securities, high yield fixed income securities that are rated below investment grade, U.S. treasury securities, mortgage backed securities and other asset backed securities.  The funds are valued using the net asset value method in which an average of the market prices for the underlying investments is used to value the fund.

 

18.          Postretirement Benefit Obligation

 

We sponsor a health care plan and life insurance plan (“Postretirement Plan”) that provides postretirement medical benefits and life insurance to certain “grandfathered” unionized employees.  The plan is contributory, with contributions required at the same rate as active employees.  Benefit eligibility under the plan reduces at age 65 from a defined benefit to a defined dollar cap based upon years of service.

 

On December 31, 2009, the annual measurement date, our Postretirement Plan had an accumulated benefit obligation of $2.0 million, which is greater than the accumulated benefit obligation at December 31, 2008 of $1.9 million.  The Postretirement Plan is unfunded and has no assets.

 

Items not yet recognized as a component of net periodic pension cost and recognized in the Consolidated Balance Sheets are as follows at December 31:

 

(In thousands)

 

2009

 

2008

 

 

 

 

 

 

 

Unfunded status

 

$

(2,022

)

$

(1,863

)

 

 

 

 

 

 

Amounts recognized in:

 

 

 

 

 

Current liabilities

 

(38

)

(29

)

Long-term liabilities

 

(1,984

)

(1,834

)

Deferred taxes

 

(209

)

(226

)

Accumulated other comprehensive (income)/loss:

 

 

 

 

 

Unamortized net actuarial (gain)/loss

 

(537

)

(579

)

 

We expect to recognize an amortization of net actuarial gain of $24 thousand in 2010.  Net periodic postretirement benefit cost for the years ended December 31 includes the following components:

 

(In thousands)

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Service cost

 

$

76

 

$

76

 

$

151

 

Interest cost

 

110

 

106

 

135

 

Recognized net actuarial gain (loss)

 

(36

)

(38

)

 

Net periodic postretirement benefit cost

 

$

150

 

$

144

 

$

286

 

 

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Table of Contents

 

The change in benefit obligation for the years ended December 31 includes the following components:

 

(In thousands)

 

2009

 

2008

 

 

 

 

 

 

 

Benefit obligation at the beginning of the year

 

$

1,863

 

$

2,339

 

Service cost

 

76

 

76

 

Interest cost

 

110

 

106

 

Actuarial loss/(gain)

 

6

 

(627

)

Benefits paid

 

(32

)

(30

)

Benefit obligation at the end of the year

 

$

2,023

 

$

1,863

 

 

The weighted-average discount rate used to determine net periodic postretirement benefit cost was 6.0% at December 31, 2009 and 6.5% at December 31, 2008.

 

The expected future benefits payments for the plan are as follows:

 

(in thousands)

 

 

 

2010

 

$

38

 

2011

 

34

 

2012

 

40

 

2013

 

72

 

2014

 

98

 

2015 — 2019

 

686

 

 

For purposes of determining the cost and obligation for pre-Medicare postretirement medical benefits, a 13.9% annual rate of increase in the per capita cost of covered benefits (i.e., health care trend rate) was assumed for the plan in 2008, declining to a rate of 5.35% in 2016.  Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans.  A one percent change in the assumed health care cost trend rate would have had the following effects:

 

(In thousands)

 

1% Increase

 

1% Decrease

 

 

 

 

 

 

 

Effect on total of service and interest cost components

 

$

13

 

$

(11

)

Effect on postretirement benefit obligation

 

$

156

 

$

(130

)

 

19.          Environmental Remediation and Contingencies

 

We are subject to extensive federal, state and local environmental laws, regulations and permit conditions (and interpretations thereof), including those relating to the discharge of materials into the air, water and ground, the generation, storage, handling, use, transportation and disposal of hazardous materials, and the health and safety of our employees.  These laws, regulations, and permits require us to incur significant capital and other costs, including costs to obtain and maintain expensive pollution control equipment.  They may also require us to make operational changes to limit actual or potential impacts to the environment.  A violation of these laws, regulations or permit conditions can result in substantial fines, natural resource damages, criminal sanctions, permit revocations and/or facility shutdowns.  In addition, environmental laws and regulations (and interpretations thereof) change over time, and any such changes, more vigorous enforcement policies or the discovery of currently unknown conditions may require substantial additional environmental expenditures.

 

We are also subject to potential liability for the investigation and cleanup of environmental contamination at each of the properties that we own or operate and at off-site locations where we arranged for the disposal of hazardous wastes.  For instance, soil and groundwater contamination has been identified

 

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Table of Contents

 

in the past at our Illinois campus.  If any of these sites are subject to investigation and/or remediation requirements, we may be responsible under the Comprehensive Environmental Response, Compensation and Liability Act or other environmental laws for all or part of the costs of such investigation and/or remediation, and for damages to natural resources.  We may also be subject to related claims by private parties alleging property damage or personal injury due to exposure to hazardous or other materials at or from such properties.  While costs to address contamination or related third-party claims could be significant, based upon currently available information, we are not aware of any material liability relating to contamination or such third party claims.  We have not accrued any amounts for environmental matters as of December 31, 2009.  The ultimate costs of any liabilities that may be identified or the discovery of additional contaminants could adversely impact our results of operation or financial condition.

 

In addition, the hazards and risks associated with producing and transporting our products (such as fires, natural disasters, explosions, abnormal pressures and spills) may result in releases of hazardous substances, and may result in claims from governmental authorities or third parties relating to actual or alleged personal injury, property damage, or damages to natural resources.  We maintain insurance coverage against some, but not all, potential losses caused by our operations. Our coverage includes, but is not limited to, physical damage to assets, employer’s liability, comprehensive general liability, automobile liability and workers’ compensation.  We do not carry environmental insurance.  We believe that our insurance is adequate for our industry, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage.  The occurrence of events which result in significant personal injury or damage to our property, natural resources or third parties that is not covered by insurance could have a material adverse impact on our results of operations and financial condition.

 

Our air emissions are subject to the federal Clean Air Act, as amended, and similar state laws which generally require us to obtain and maintain air emission permits for our ongoing operations as well as for any expansion of existing facilities or any new facilities.  Obtaining and maintaining those permits requires us to incur costs, and any future more stringent standards may result in increased costs and may limit or interfere with our operating flexibility.  In addition, the permits ultimately issued may impose conditions which are more costly to implement than we had anticipated.  These costs could have a material adverse effect on our financial condition and results of operations.  Because other ethanol manufacturers in the U.S. are and will continue to be subject to similar laws and restrictions, we do not currently believe that our costs to comply with current or future environmental laws and regulations will adversely affect our competitive position among domestic producers.  However, because ethanol is produced and traded internationally, these costs could adversely affect us in our efforts to compete with foreign producers not subject to such stringent requirements.

 

Federal and state environmental authorities have been investigating alleged excess volatile organic compounds emissions and other air emissions from many U.S. ethanol plants, including our Illinois facilities.  The investigation relating to our Illinois wet mill facility is still pending, and we could be required to install additional air pollution control equipment or take other measures to control air pollutant emissions at that facility.  If authorities require us to install controls, we would anticipate that costs would be higher than the approximately $3.4 million we incurred in connection with a similar investigation at our Nebraska facility due to the larger size of the Illinois wet mill facility.  In addition, if the authorities determine our emissions were in violation of applicable law, we would likely be required to pay fines that could be material.  In February 2008, we received a $3.0 million indemnification payment from the former owner of our Nebraska facility relating to the cost of installing environmental controls at that facility in connection with an April 2005 consent decree with state authorities.

 

We have made, and expect to continue making, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits, including compliance with the U.S. Environmental Protection Agency’s (“EPA”) National Emissions Standard for Hazardous Air

 

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Table of Contents

 

Pollutants, or NESHAP, for industrial, commercial and institutional boilers and process heaters.  This NESHAP was issued but subsequently vacated.  The vacated version of the rule required us to implement maximum achievable control technology at our Illinois wet mill facility to reduce hazardous air pollutant emissions from our boilers.  We expect the EPA will revise the rule to impose more stringent requirements than were contained in the vacated version.  In the absence of a final EPA NESHAP for industrial, commercial and institutional boilers and process heaters, we are working with state authorities to determine what technology will be required at our Illinois wet mill facility and when such technology must be installed.  We currently cannot estimate the amount that will be needed to comply with any future federal or state technology requirement regarding air emissions from our boilers.

 

We currently generate revenue from the sale of carbon dioxide, which is a co-product of the ethanol production process at each of our Illinois and Nebraska facilities.  New laws or regulations relating to the production, disposal or emissions of carbon dioxide may require us to incur significant additional costs and may also adversely affect our ability to continue generating revenue from carbon dioxide sales.

 

20.          Income Taxes

 

The provision for income taxes for the years ended December 31 consists of the following:

 

(In thousands)

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Current expense (benefit)

 

$

(6,193

)

$

(10,616

)

$

5,749

 

Deferred expense (benefit)

 

(2,845

)

3,118

 

(5,852

)

Interest income (expense)

 

82

 

26

 

(374

)

Total income tax expense (benefit)

 

$

(8,956

)

$

(7,472

)

$

(477

)

 

Reconciliation of differences between the statutory U.S. federal income tax rate and our effective tax rate follows for the years ended December 31:

 

(In thousands)

 

2009

 

%

 

2008

 

%

 

2007

 

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income tax provision (benefit) at federal statutory rate

 

$

(19,325

)

35.0

 

$

(19,099

)

35.0

 

$

11,663

 

35.0

 

Increase/(decrease) in taxes resulting from:

 

 

 

 

 

 

 

 

 

 

 

 

 

State and local taxes, net of federal benefit

 

(2,079

)

3.7

 

(1,994

)

3.7

 

947

 

2.8

 

FIN 48 recognition of previously unrecognized uncertain tax positions

 

142

 

(0.2

)

 

 

(8,089

)

(24.3

)

Tax exempt interest income

 

 

 

 

 

(2,592

)

(7.8

)

Goodwill

 

(678

)

1.2

 

(927

)

1.7

 

 

 

Increase (decrease) in valuation allowances

 

10,064

 

(18.2

)

16,142

 

(29.6

)

(1,563

)

(4.7

)

Deferred tax adjustments

 

 

 

(270

)

0.5

 

 

 

Non-deductible reorganization expense

 

1,869

 

(3.4

)

 

 

 

 

Indemnification proceeds

 

 

 

(1,185

)

2.2

 

 

 

Other

 

1,051

 

(1.9

)

(139

)

0.2

 

(843

)

(2.4

)

Income tax expense/(benefit)

 

$

(8,956

)

16.2

 

$

(7,472

)

13.7

 

$

(477

)

(1.4

)

 

Deferred income taxes included in our Consolidated Balance Sheets reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and the carrying amount for income tax return purposes.

 

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Significant components of our deferred tax assets and liabilities are as follows at December 31:

 

(In thousands)

 

2009

 

2008

 

 

 

 

 

 

 

Current deferred tax asset

 

$

3,305

 

$

1,593

 

Valuation allowance

 

(2,326

)

 

Net current deferred tax asset

 

$

979

 

$

1,593

 

 

 

 

 

 

 

Current deferred tax liability

 

$

979

 

$

507

 

 

 

 

 

 

 

Long-term deferred tax liabilities:

 

 

 

 

 

Basis of property, plant and equipment

 

$

4,759

 

$

5,389

 

Benefit obligations

 

61

 

15

 

Partnership investment

 

4,744

 

4,306

 

Accumulated other comprehensive income

 

1,031

 

 

Other

 

207

 

 

Long-term deferred tax liability

 

$

10,802

 

$

9,710

 

 

 

 

 

 

 

Long-term deferred tax assets:

 

 

 

 

 

Capital losses

 

$

13,739

 

$

12,324

 

Unrealized loss on bankruptcy

 

9,633

 

 

Investment in marketing alliances

 

1,213

 

3,377

 

Accumulated other comprehensive income

 

 

1,324

 

Other

 

 

531

 

State NOL’s

 

1,568

 

 

Stock-based compensation

 

5,793

 

7,055

 

Valuation allowance

 

(24,080

)

(17,345

)

Long-term deferred tax assets

 

$

7,866

 

$

7,266

 

 

 

 

 

 

 

Net long-term deferred tax asset (liability)

 

$

(2,936

)

$

(2,444

)

 

The deferred tax provision for 2009, 2008 and 2007 does not reflect the tax effect of $(0.5) million, $(1.1) million and $0.5 million, respectively, resulting from the pension and other postretirement liability components included in accumulated other comprehensive income.

 

At December 31, 2009 and 2008, the Company has recorded valuation allowance of $26.4  million and $17.3 million, respectively, on its deferred tax assets to reduce the deferred tax assets to the amount that management believes is more likely than not to be realized.  Management considered the scheduled reversal of deferred tax liabilities and tax planning strategies in making this assessment.  The deferred tax assets subject to the valuation allowance primarily include tax benefits associated with capital loss on securities, stock-based compensation, excess tax basis over corresponding book basis in available-for-sale securities, and state income tax net operating loss carryforwards.

 

At December 31, 2009 and 2008, we had deferred state tax benefits of $1.6 million and $0.5 million, respectively,  relating to state net operating loss carryforwards, which are available to offset future state taxable income through 2030.  Due to uncertainties regarding realization of the tax benefits, a valuation allowance of $1.9 million has been applied against the deferred state tax benefits at December 31, 2009.

 

At December 31, 2009, we had a capital loss carryforward of $13.7 million that is available to offset future consolidated capital gains.  Due to uncertainties regarding the realization of the capital loss carryforward, a valuation allowance of $13.7 million has been applied against the deferred tax benefit at December 31, 2009.

 

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Table of Contents

 

We adopted the provisions of FIN 48 on January 1, 2007.  As of December 31, 2009 and 2008, the Company had unrecognized tax benefits of $0.9 million, none of which would impact the effective tax rate, if recognized.  Unrecognized tax benefits are recorded in other current liabilities at December 31, 2009 and other long-term liabilities at December 31, 2008 to conform to the balance sheet presentation requirements of FIN 48.

 

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

 

 

 

2009

 

2008

 

Balance at January 1

 

$

874

 

$

 

Additions based on tax positions related to the current year

 

 

 

Reductions based on tax positions taken in previous years

 

 

 

Additions based on tax positions taken in previous years

 

2,297

 

874

 

Settlements

 

(2,297

)

 

Reductions for lapse of statute of limitations

 

 

 

Balance at December 31

 

$

874

 

$

874

 

 

We include the interest expense or income, as well as potential penalties on unrecognized tax benefits, as components of income tax expense in the condensed consolidated statement of operations.  The total amount of accrued interest related to uncertain tax positions at December 31, 2009 was $19 thousand, net of the deferred tax benefit.

 

The Company files a federal and various state income tax returns. Our federal income tax returns for 2006 to 2008 are open tax years under the statue of limitations.  Our federal income tax returns for 2008 is under examination.  We file in numerous state and foreign jurisdictions with varying statues of limitations open from 2005 to 2009.

 

In December 2004, the FASB issued Staff Position No. FAS 109-1, Application of SFAS 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities provided by the American Jobs Creation Act of 2004.  The Company did not recognize any tax benefits related to the qualified domestic production credit for the years ended December 31, 2009 or 2008.  For the year ended December 31, 2007, the Company recognized $0.3 million in tax benefits related to the qualified domestic production credit.

 

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Table of Contents

 

21.          Accumulated Other Comprehensive Income (Loss)

 

The components of accumulated other comprehensive loss, net of tax, at December 31, are as follows:

 

(In thousands)

 

Pension and
post-retirement
liabilities

 

Available-for-sale
securities

 

Accumulated
Other
Comprehensive
Income (Loss)

 

Balance at December 31, 2006

 

$

(1,074

)

$

 

$

(1,074

)

Pension and postretirement liability adjustment, net of tax of $475

 

750

 

 

750

 

Balance at December 31, 2007

 

(324

)

 

(324

)

Pension and postretirement liability adjustment, net of tax of $1,112

 

(1,746

)

 

(1,746

)

Balance at December 31, 2008

 

(2,070

)

 

(2,070

)

Pension and postretirement liability adjustment, net of tax of $494

 

773

 

 

773

 

Unrealized holding gain on available-for-sale securities, net of tax of $1,860

 

 

2,909

 

2,909

 

Balance at December 31, 2009

 

$

(1,297

)

$

2,909

 

$

1,612

 

 

22.          Stockholder Rights Plan

 

On December 12, 2005, the Board of Directors adopted a stockholder rights plan under which each common shareholder was issued one preferred share purchase right for each share of common stock outstanding prior to the 144A equity offering.  In addition, each share of common stock issued in the offering or after the consummation of the offering will be issued with an accompanying preferred share purchase right.  Each right will entitle the holder, under certain circumstances, to purchase one one-thousandth of a share of the Company’s Series A participating cumulative preferred stock, par value $0.001 per share, at an initial purchase price of $60.00 per one one-thousandth of a share of Series A participating cumulative preferred stock.  The Company may exchange the rights at a ratio of one share of common stock for each right at any time after a person or group acquires beneficial ownership of 20% or more of its common stock but before such party acquires beneficial ownership of 50% or more of its common stock.  The Company may also redeem the rights at its discretion at a price of $0.001 per right at any time before a person or party has acquired beneficial ownership of 20% or more of its common stock.  The rights will expire on November 30, 2015, unless earlier exchanged or redeemed.  Each share of Series A participating cumulative preferred stock that is purchased upon exercise of a right entitles the holder to receive an aggregate quarterly dividend payment of $1.00 or 1,000 times the cash and noncash dividends declared per share of common stock, whichever is greater.  As of December 31, 2009, there were no Series A participating preferred stock rights that had been exercised.

 

23.          Stock-Based Compensation Plans

 

As of December 31, 2009, we maintained one stock-based compensation plan, the Aventine Renewable Energy Holdings, Inc. 2003 Stock Incentive Plan (the “Plan”).  Effective January 1, 2006, the Company adopted ASC 718, utilizing the modified prospective transition method.  ASC 718 requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including stock options and non-vested stock, based on their fair values at the time of grant.

 

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Table of Contents

 

The Plan was adopted by the Board of Directors (the “Board”) effective May 30, 2003, and was amended on each of September 6, 2005, December 12, 2005, March 22, 2007 and April 16, 2007.  The Plan provides for the grant of awards in the form of stock options, restricted shares or units, stock appreciation rights and other equity-based awards to directors, officers, employees and consultants at the discretion of the Board or the Compensation Committee of the Board.  The term of awards granted under the plan is determined by the Board or by the Compensation Committee of the Board, and cannot exceed ten years from the date of grant.  The maximum number of shares of common stock that may be issued under the Plan is limited to 6,701,172, provided that no more than 750,000 shares may be granted in the form of stock options or stock appreciation rights to any “covered employee” (as defined under Section 162(m) of the Internal Revenue Code) in any calendar year.  Unless terminated sooner, the Plan will continue in effect until May 29, 2013.

 

Upon adoption of ASC 718, the Company elected to value its share-based payment awards granted beginning in fiscal year 2006 using a form of the Black-Scholes option-pricing model (the “Option Pricing Model”).  The Option Pricing Model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable.  The determination of fair value of share-based payment awards on the date of grant using the Option Pricing Model is affected by our stock price as well as the input of other subjective assumptions, of which the most significant are, expected stock price volatility, the expected pre-vesting forfeiture rate and the expected option term (the amount of time from the grant date until the options are exercised or expire).  Expected volatility is normally calculated based upon actual historical stock price movements over the expected option term.  Since we had no considerable history of stock price volatility as a public company at the time of the grants, we calculated volatility by considering, among other things, the expected volatilities of public companies engaged in similar industries.  Pre-vesting forfeitures prior to June 30, 2008 were estimated using a 3% forfeiture rate.  We adjusted the forfeiture rate to 6.4%, 10.7%, 14.2%, and 20.0% as of July 1, 2008, January 1, 2009, July 1, 2009, and October 1, 2009, respectively,  to reflect our experience with actual forfeitures. The expected option term is calculated using the “simplified” method permitted by SAB 107.  Our options have characteristics significantly different from those of traded options, and changes in the assumptions can materially affect the fair value estimates.

 

Beginning in 2007, the Company commenced an ongoing long-term incentive program under the Plan.  It is anticipated that this program will provide regular annual grants of performance shares.  Performance shares are stock units that will be converted to common shares, to the extent earned, at the end of a three-year performance cycle.  Under the performance share program, each participant is given a target award expressed as a number of shares, with a payout opportunity ranging from 0% to 150% of the target, depending on the performance relative to pre-determined goals.  Under ASC 718, an accounting estimate of the number of these shares that are expected to vest is made and these shares are then expensed utilizing the grant-date fair value of the shares from the date of grant through the end of the performance cycle period.

 

The first performance cycle began on January 1, 2007, and ends on December 31, 2009.  The performance goals for the January 1, 2007 to December 31, 2009 performance cycle relate to the growth of the Company as measured by actual equity gallons produced.  On May 25, 2007, the Company issued 94,500 performance shares at the target award level to various participants under the Plan.  In 2008, we determined that we did not expect to meet the minimum performance criteria relative to the pre-determined goals for the January 1, 2007 to December 31, 2009 performance cycle, as we would not achieve the requisite minimum production of equity gallons to qualify for a payout.  As a result, all of the expense totaling $0.8 million previously recorded relative to this performance measurement was reversed in 2008.  No expense relative to this performance cycle was recorded in 2009.

 

Under the performance share program, a second performance cycle was established whose performance criteria relates to the relative performance between the Company and VeraSun Energy Corporation using the metric of EBITDA (as defined) divided by produced denatured gallons of ethanol.

 

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Table of Contents

 

This second performance cycle runs from the fourth quarter of 2007 until the third quarter of 2010.  The performance measurement is compared against a base year defined as the fourth quarter of 2006 through the third quarter of 2007.  On February 21, 2008, the Company issued 106,500 performance shares at the target award level to various participants under the Plan.  In 2008, we determined that we did not expect to meet the minimum performance criteria relative to the pre-determined goals for this performance cycle.  As a result, we did not record any expense in 2008.  No expense relative to this performance cycle was recorded in 2009, and with the liquidation of VeraSun in bankruptcy, it is not likely that any payout will result.

 

Pre-tax stock-based compensation expense for the year ended December 31, 2009 was approximately $2.5 million, of which $0.4 million was charged to cost of goods sold and $2.1 million was charged to selling, general and administrative expense.   This expense reduced earnings per share by $0.04 per basic share and $0.04 per diluted share for the year ended December 31, 2009.  Pre-tax stock-based compensation expense for the year ended December 31, 2008 was approximately $5.7 million, of which $0.1 million was charged to cost of goods sold and $5.6 million was charged to selling, general and administrative expense.  This expense reduced earnings per share by $0.08 per basic share and $0.08 per diluted share for the year ended December 31, 2008.  The Company recognized a tax benefit on its consolidated statement of operations from stock-based compensation expense in the amount of $0.6 million and $1.7 million, respectively, for the 12 month periods ended December 31, 2009 and 2008.  The Company recorded pre-tax stock-based compensation expense for the year ended December 31, 2009, 2008 and 2007 as follows:

 

 

 

Year Ended December 31,

 

(in millions)

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Stock-based compensation expense:

 

 

 

 

 

 

 

Non-qualified options

 

$

2.2

 

$

5.5

 

$

6.5

 

Restricted stock

 

$

0.2

 

$

0.3

 

$

0.2

 

Restricted stock units

 

$

0.1

 

$

0.3

 

$

0.1

 

Long-term incentive plan

 

$

0.0

 

$

(0.4

)

$

0.4

 

Total

 

$

2.5

 

$

5.7

 

$

7.2

 

 

As of December 31, 2009, the Company had not yet recognized compensation expense on the following non-vested awards:

 

(in millions)

 

Non-recognized
Compensation

 

Average Remaining
Recognition Period
(years)

 

 

 

 

 

 

 

Non-qualified options

 

$

2.0

 

0.9

 

Restricted stock

 

0.4

 

0.2

 

Restricted stock units

 

0.0

 

0.1

 

Long-term incentive plan

 

0.0

 

0.0

 

Total

 

$

2.4

 

0.8

 

 

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Table of Contents

 

The determination of the fair value of the stock option awards, using the Option Pricing Model for the years ended December 31, 2009, 2008 and 2007, incorporated the assumptions in the following table for stock options granted:

 

 

 

December 31,

 

 

 

2009

 

2008

 

2007

 

 

 

 

 

 

 

 

 

Expected stock price volatility

 

58

%

58

%

58

%

Expected life (in years)

 

6.5

 

6.5

 

6.5

 

Risk-free interest rate

 

2.17

%

4.52

%

4.76

%

Expected dividend yield

 

0

%

0

%

0

%

Weighted average fair value

 

$

0.10

 

$

4.16

 

$

9.76

 

 

The following table summarizes stock options outstanding and changes during the years ended December 31, 2009, 2008 and 2007:

 

 

 

Shares
(in thousands)

 

Weighted-
Average
Exercise
Price

 

Weighted-
Average
Remaining
Life

(years)

 

Aggregate
Intrinsic Value
(in thousands)

 

Options outstanding — December 31, 2006

 

3,265

 

$

6.57

 

 

 

 

 

Granted

 

480

 

$

16.00

 

 

 

 

 

Exercised

 

(201

)

$

2.54

 

 

 

 

 

Cancelled or expired

 

(28

)

$

4.35

 

 

 

 

 

Options outstanding — December 31, 2007

 

3,516

 

$

8.10

 

7.4

 

$

7,911

 

Options exercisable — December 31, 2007

 

1,234

 

$

3.77

 

6.5

 

$

8,120

 

Granted

 

568

 

$

6.85

 

 

 

 

 

Exercised

 

 

 

 

 

 

 

Cancelled or expired

 

(190

)

$

14.31

 

 

 

 

 

Options outstanding — December 31, 2008

 

3,894

 

$

7.62

 

6.7

 

$

422

 

Options exercisable — December 31, 2008

 

2,059

 

$

4.83

 

5.7

 

$

405

 

Granted

 

50

 

$

0.18

 

 

 

 

 

Exercised

 

(85

)

$

0.23

 

 

 

 

 

Cancelled or expired

 

(1,274

)

$

13.02

 

 

 

 

 

Options outstanding — December 31, 2009

 

2,585

 

$

5.05

 

3.7

 

$

130

 

Options exercisable — December 31, 2009

 

2,070

 

$

3.86

 

2.7

 

$

121

 

 

The range of exercise prices of the exercisable options and outstanding options at December 31, 2009 are as follows:

 

Weighted-Average Exercise Price

 

Number of
Exercisable
Options

(in thousands)

 

Number of
Outstanding
Options

(in thousands)

 

Weighted-
Average
Remaining
Life
(years)

 

$0.23

 

879

 

929

 

1.7

 

$2.36 - $4.80

 

893

 

999

 

3.7

 

$7.05

 

64

 

222

 

7.3

 

$15.26 - $17.29

 

102

 

255

 

7.2

 

$22.15 - $22.50

 

132

 

180

 

4.3

 

Totals

 

2,070

 

2,585

 

3.7

 

 

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Table of Contents

 

In 2007, we awarded 70,531 shares of restricted stock under the Plan, with a weighted-average fair value at the date of grant of $15.40 per share.  These restricted shares vest 20% per year annually at the anniversary date of the grant.  We recorded compensation expense with respect to restricted stock awards of approximately $0.2 million in 2007 which is recognized on a straight-line basis over the five year vesting period of the restricted stock grants.  Restricted stock award activity for the years ended December 31, 2009, 2008 and 2007 is summarized below.

 

 

 

Shares
(in thousands)

 

Weighted- Average
Grant Date Fair Value
per Award

 

Unvested restricted stock awards — January 1, 2007

 

8.1

 

$

27.92

 

Granted

 

70.5

 

15.40

 

Vested

 

(2.7

)

27.93

 

Cancelled or expired

 

 

 

Unvested restricted stock awards — December 31, 2007

 

75.9

 

$

16.69

 

Granted

 

 

 

Vested

 

(16.8

)

17.41

 

Cancelled or expired

 

 

 

Unvested restricted stock awards — December 31, 2008

 

59.1

 

$

15.97

 

Granted

 

 

 

Vested

 

(16.8

)

17.41

 

Cancelled or expired

 

(3.0

)

17.29

 

Unvested restricted stock awards — December 31, 2009

 

39.3

 

$

15.26

 

 

Restricted stock units represent the right to receive a share of stock in the future, provided that the restrictions and conditions designated have been satisfied.  There were no restricted stock unit awards made by the Company prior to 2007.  Restricted stock unit award activity for the years ended December 31, 2009, 2008 and 2007 is summarized below:

 

 

 

Shares
(in thousands)

 

Weighted Average
Grant Date Fair
Value per Award

 

Unvested restricted stock unit awards — January 1, 2007

 

 

 

Granted

 

18.0

 

$

15.85

 

Vested

 

 

 

Cancelled or expired

 

 

 

Unvested restricted stock unit awards — December 31, 2007

 

18.0

 

$

15.85

 

Granted

 

46.5

 

$

6.88

 

Vested

 

(18.0

)

$

15.848

 

Cancelled or expired

 

 

 

Unvested restricted stock unit awards — December 31, 2008

 

46.5

 

$

6.88

 

Granted

 

 

 

Vested

 

(32.4

)

$

7.55

 

Cancelled or expired

 

 

 

Unvested restricted stock unit awards — December 31, 2009

 

14.1

 

$

5.33

 

 

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Table of Contents

 

24.          Commitments

 

We lease certain assets such as rail cars, terminal facilities, barges, buildings and equipment  from unaffiliated parties under non-cancelable operating leases.  Terms of the leases, including renewals, vary by lease.  Minimum future rental commitments under our operating leases having non-cancelable lease terms in excess of one year and which have not been rejected through bankruptcy totaled approximately $19.1 million as of December 31, 2009 and are payable as follows:

 

(in millions)

 

 

 

2010

 

$

3.1

 

2011

 

$

2.0

 

2012

 

$

1.9

 

2013

 

$

1.3

 

2014

 

$

1.2

 

Thereafter

 

$

9.6

 

 

Rental expense for operating leases was $9.2 million in 2009, $38.3 million in 2008 and $25.4 million in 2007.

 

At December 31, 2009, we have remaining commitments of $0.4 million for the construction of two new dry mill facilities in Aurora, Nebraska and Mt. Vernon, Indiana, excluding the $23.2 million of which $15.3 million is recorded in liabilities subject to compromise and $7.9 is recorded in long term liabilities.  We had no other commitments for capital expenditures at December 31, 2009.  On March 9, 2009, the Company received a notice from Kiewit  cancelling the engineering, construction and procurement contracts for Aurora West and Mt. Vernon, referencing our failure to make a recent payment under the change order agreements dated December 31, 2008.

 

At December 31, 2009, we had forward contracts to purchase approximately 198,000 tons of coal at a weighted average fixed price of $57.74 per ton, delivered.

 

At December 31, 2009, we have committed to purchase approximately 134.7 MMBtus of natural gas at a weighted average fixed price of $6.19 during 2010, delivered.

 

At December 31, 2009 we also had commitments to purchase approximately 1.4 million bushels of corn through December 2010, at an average price of $3.95 per bushel.  These commitments were negotiated in the normal course of business and represent a portion of our corn requirements, which we anticipate will exceed 73 million bushels in 2010.

 

We have contractual obligations, subject to certain conditions, to build a second 110 million gallon expansion in Mount Vernon, Indiana.  If we do not meet certain specified milestones or decide not to pursue the expansions, we could be subject to material penalties.

 

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Table of Contents

 

25.                               Earnings Per Share

 

The following table sets forth the computation of earnings per share for the years ended December 31:

 

 

 

2009

 

2008

 

2007

 

(In thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) available to common shares

 

$

(46,260

)

$

(47,096

)

$

33,799

 

 

 

 

 

 

 

 

 

Basic weighted-average common shares

 

42,968

 

42,136

 

41,886

 

Dilutive stock options (1)

 

 

 

465

 

Diluted weighted-average common and common equivalent shares

 

42,968

 

42,136

 

42,351

 

 

 

 

 

 

 

 

 

Earnings (loss) per common share—basic:

 

$

(1.08

)

$

(1.12

)

$

0.81

 

Earnings (loss) per common share—diluted:

 

$

(1.08

)

$

(1.12

)

$

0.80

 

 


(1)          To the extent that stock options are anti-dilutive, they are excluded from the calculation of diluted earnings/(loss) per share in accordance with ASC 260.

 

We had additional potential dilutive securities outstanding representing 2.6 million and 3.9 million common shares, respectively, for the years ended December 31, 2009 and 2008 that were not included in the computation of diluted earnings per share because the options were anti-dilutive.  For the year ended December 31, 2007, we had 1.2 million common shares that were not included in the computation of potentially dilutive securities because the options’ exercise price were greater than the average market price of the common shares.

 

26.                               Quarterly Results of Operations (Unaudited)

 

The following is a summary of the unaudited quarterly results of operations for the years ended December 31, 2009 and 2008:

 

 

 

March 31

 

June 30

 

September 30

 

December 31

 

2009

 

 

 

 

 

 

 

 

 

(In thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

Net sales

 

$

236,536

 

$

118,121

 

$

118,116

 

$

121,850

 

Gross profit (loss)

 

$

(21,428

)

$

105

 

$

7,835

 

$

22,207

 

Net income (loss)

 

$

(24,567

)

$

(48,935

)

$

13,886

 

$

13,356

 

 

 

 

 

 

 

 

 

 

 

Basic earnings per common share:

 

$

(0.57

)

$

(1.14

)

$

0.32

 

$

0.31

 

Diluted earnings per common share:

 

$

(0.57

)

$

(1.14

)

$

0.32

 

$

0.31

 

 

 

 

 

 

 

 

 

 

 

2008

 

 

 

 

 

 

 

 

 

(In thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

Net sales

 

$

509,948

 

$

601,591

 

$

599,520

 

$

537,242

 

Gross profit (loss)

 

$

24,083

 

$

32,860

 

$

(6,470

)

$

(41,512

)

Net income (loss)

 

$

(10,795

)

$

(1,918

)

$

2,486

 

$

(36,869

)

 

 

 

 

 

 

 

 

 

 

Basic earnings (loss) per common share:

 

$

(0.26

)

$

(0.05

)

$

0.06

 

$

(0.86

)

Diluted earnings (loss) per common share:

 

$

(0.26

)

$

(0.05

)

$

0.06

 

$

(0.86

)

 

27.                               Subsequent Events

 

On February 3, 2010 the U.S. Environmental Protection Agency announced final revisions to the National Renewable Fuel Standard program (commonly known as the RFS program or RFS-2). This rule

 

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makes changes to the Renewable Fuel Standard program as required by the Energy Independence and Security Act of 2007 (EISA). The revised statutory requirements establish new specific annual volume standards for cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel that must be used in transportation fuel. The revised statutory requirements also include new definitions and criteria for both renewable fuels and the feedstock used to produce them, including new greenhouse gas emission (GHG) thresholds as determined by lifecycle analysis. The regulatory requirements for RFS will apply to domestic and foreign producers and importers of renewable fuel used in the U.S.

 

This final action lays the foundation for achieving significant reductions of greenhouse gas emissions from the use and creation of renewable fuels, reductions of imported petroleum and further development and expansion of our nation’s renewable fuels sector.

 

This Rule sets the 2010 RFS volume standard at 12.95 billion gallons (bg). Further, for the first time, the EPA is setting volume standards for specific categories of renewable fuels including cellulosic, biomass-based diesel, and total advanced renewable fuels. For 2010, the cellulosic standard is set at 6.5 million gallons (mg); and the biomass based diesel standard is set at 1.15 bg, (combining the 2009 and 2010 standards as proposed).

 

In order to qualify for these new volume categories, fuels must demonstrate that they meet certain minimum greenhouse gas reduction standards, based on a lifecycle assessment, in comparison to the petroleum fuels they displace.  Generally, ethanol plants either meet the 20% reduction test or are grandfathered under special provisions.  For plants under construction on which construction commenced prior to December 19, 2007 (including the company’s Mt. Vernon and Aurora-West plants under construction) the plants must be completed within 36 months in order to meet the requirements to be grandfathered or comply with the GHG reduction standards which require the use of Advanced Technologies defined by the regulations.  The company is currently researching alternatives to assure these plants are compliant.

 

On February 23, 2010 the Board of Directors passed a resolution terminating the 2003 Stock Incentive Plan effective at the close of business on February 23, 2010.  If the proposed Plan of Reorganization is confirmed, all outstanding stock and option awards made under the 2003 Stock Incentive Plan will be cancelled on the Effective Date of emergence from bankruptcy.

 

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Report of Independent Registered Public Accounting Firm

 

The Board of Directors and Stockholders

Aventine Renewable Energy Holdings, Inc.

 

We have audited the accompanying consolidated balance sheets of Aventine Renewable Energy Holdings, Inc. (the Company) as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Aventine Renewable Energy Holdings, Inc. at December 31, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

 

The accompanying financial statements have been prepared assuming that Aventine Renewable Energy Holdings, Inc. will continue as a going concern. As more fully described in Note # 2 to the consolidated financial statements, the Company filed a voluntary petition for reorganization under Chapter 11 of the United States Bankruptcy Code on April 7, 2009, which raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to this matter are also described in Note # 2 to the consolidated financial statements. The consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of this uncertainty.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Aventine Renewable Energy Holding Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2010 expressed an unqualified opinion thereon.

 

/s/ Ernst & Young LLP

 

St. Louis, Missouri

February 23, 2010

 

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Report of Independent Registered Public Accounting Firm

 

The Board of Directors and Stockholders

Aventine Renewable Energy Holdings, Inc.

 

We have audited Aventine Renewable Energy Holdings, Inc.’s (the Company’s) internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Aventine Renewable Energy Holdings, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

In our opinion, Aventine Renewable Energy Holdings, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.

 

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We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Aventine Renewable Energy Holdings, Inc. as of December 31, 2009 and 2008 and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2009 of Aventine Renewable Energy Holdings, Inc. and our report dated February 23, 2010 expressed an unqualified opinion thereon that included an explanatory paragraph regarding Aventine Renewable Energy Holdings, Inc.’s ability to continue as a going concern.

 

 

/s/ Ernst & Young LLP

 

St. Louis, Missouri

February 23, 2010

 

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AVENTINE RENEWABLE ENERGY HOLDINGS, INC. AND SUBSIDIARIES

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

 

Description

 

Balance
Beginning of
Period

 

Charged to
Cost and
Expenses

 

Charged to
Other
Accounts

 

Deductions

 

Balance at
End of
Period

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

YEAR ENDED DECEMBER 31, 2009

 

 

 

 

 

 

 

 

 

 

 

Deducted from assets accounts:

 

 

 

 

 

 

 

 

 

 

 

Deferred tax valuation

 

$

17,345

 

$

10,064

 

$

(1,003

)

$

 

$

26,406

 

Allowance for doubtful accounts

 

$

272

 

$

2,171

 

$

 

$

(43

)

$

2,400

 

 

 

 

 

 

 

 

 

 

 

 

 

YEAR ENDED DECEMBER 31, 2008

 

 

 

 

 

 

 

 

 

 

 

Deducted from assets accounts:

 

 

 

 

 

 

 

 

 

 

 

Deferred tax valuation

 

$

1,203

 

$

16,142

 

$

 

$

 

$

17,345

 

Allowance for doubtful accounts

 

$

48

 

$

236

 

$

 

$

(12

)

$

272

 

 

 

 

 

 

 

 

 

 

 

 

 

YEAR ENDED DECEMBER 31, 2007:

 

 

 

 

 

 

 

 

 

 

 

Deducted from assets accounts:

 

 

 

 

 

 

 

 

 

 

 

Deferred tax valuation

 

$

3,537

 

$

2,334

 

$

 

$

 

$

1,203

 

Allowance for doubtful accounts

 

$

25

 

$

23

 

$

 

$

 

$

48

 

 



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EXHIBIT INDEX

 

Exhibit
Number

 

Description

 

 

 

3.1

 

Amended and Restated Certificate of Incorporation of Aventine Renewable Energy Holdings, Inc. (incorporated by reference to Exhibit 3.1 to Aventine’s Registration Statement on Form S-1 (333-132860) filed on March 30, 2006)

 

 

 

3.2

 

Amended and Restated Bylaws of Aventine Renewable Energy Holdings, Inc. (incorporated by reference to Exhibit 3.2 to Aventine’s Registration Statement on Form S-1/A (333-132860) filed on June 13, 2006)

 

 

 

4.1

 

Registration Rights Agreement dated as of December 12, 2005 among Aventine Renewable Energy Holdings, Inc., the Investor Holders and the Management Holders named therein (incorporated by reference to Exhibit 4.3 to Aventine’s Registration Statement on Form S-1 (333-132860) filed on March 30, 2006)

 

 

 

4.2

 

Indenture, dated as of March 27, 2007, among Aventine Renewable Energy Holdings, Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, N.A. and the form of note (incorporated by reference to Exhibit 4. 1 to Aventine’s Current Report on Form 8-K filed on April 2, 2007)

 

 

 

10.1

 

Lease Agreement, dated as of October 31, 2006 by and between the Indiana Port Commission and Aventine Renewable Energy — Mt. Vernon, LLC (the “Mt. Vernon Lease Agreement”) (incorporated by reference to Exhibit 10.1 to Aventine’s Annual Report on Form 10-K filed on March 5, 2007)

 

 

 

10.1.1

 

First Amendment to Mt. Vernon Lease Agreement, dated as of June 14, 2007 (incorporated by reference to Exhibit 10.1.1 to Aventine’s Annual Report on Form 10-K filed on March 5, 2008)

 

 

 

10.1.2

 

Second Amendment to Mt. Vernon Lease Agreement, dated as of October 18, 2007 (incorporated by reference to Exhibit 10.1.2 to Aventine’s Annual Report on Form 10-K filed on March 5, 2008)

 

 

 

10.1.3

 

Third Amendment to Mt. Vernon Lease Agreement, dated as of January 26, 2008 (incorporated by reference to Exhibit 10.1.3 to Aventine’s Annual Report on Form 10-K filed on March 5, 2008)

 

 

 

10.1.4

 

Fourth Amendment to Mt. Vernon Lease Agreement, dated as of June 19, 2008 (incorporated by reference to Exhibit 10.1.4 to Aventine’s Annual Report on Form 10-K filed on March 16, 2009)

 

 

 

10.1.5

 

Fifth Amendment to Mt. Vernon Lease Agreement, dated as of December 18, 2008 (incorporated by reference to Exhibit 10.1.5 to Aventine’s Annual Report on Form 10-K filed on March 16, 2009)

 

 

 

10.1.6

 

Sixth Amendment to Mt. Vernon Lease Agreement, dated as of February 12, 2009 (incorporated by reference to Exhibit 10.1.6 to Aventine’s Annual Report on Form 10-K filed on March 16, 2009)

 

 

 

10.1.7

 

Seventh Amendment to Mt. Vernon Lease Agreement, dated as of April 23, 2009 (incorporated by reference to Exhibit 10.1 of Aventine’s Quarterly Report on Form 10-Q filed on August 10, 2009)

 



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10.2

 

Rights Agreement dated as of December 19, 2005 between Aventine Renewable Energy Holdings. Inc. and American Stock Transfer & Trust Company, as Rights Agent (incorporated by reference to Exhibit 10.5 to Aventine’s Registration Statement on Form S-1 (333-132860) filed on March 30, 2006)

 

 

 

10.3

 

Non-Employee Director Compensation Schedule (incorporated by reference to Exhibit 10.12 to Aventine’s amended Registration Statement on Form S-1/A (333-132860) filed on June 13, 2006)*

 

 

 

10.4

 

Form of Performance Stock Unit Award Agreement (2003 Stock Incentive Plan) (incorporated by reference to Exhibit 10.1 to Aventine’s Current Report on Form 8-K filed on February 27, 2007)*

 

 

 

10.5

 

Form of Stock Option Award Agreement (2003 Stock Incentive Plan) (incorporated by reference to Exhibit 10.2 to Aventine’s Current Report on Form 8-K filed on February 27, 2007)*

 

 

 

10.6

 

Form of Restricted Stock Award Agreement (2003 Stock Incentive Plan) (incorporated by reference to Exhibit 10.3 to Aventine’s Current Report on Form 8-K filed on February 27, 2007)*

 

 

 

10.7

 

Form of Non-employee Director Restricted Stock Unit Award Agreement (2003 Stock Incentive Plan (incorporated by reference to Exhibit 10.4 to Aventine’s Current Report on Form 8-K filed on February 27, 2007)*

 

 

 

10.8

 

Purchase Agreement, dated as of March 21, 2007, among the Company, the subsidiary guarantors named therein and J.P. Morgan Securities, Inc., as representative of several initial purchasers (incorporated by reference to Exhibit 10.1 to Aventine’s Current Report on Form 8-K filed on March 27, 2007)

 

 

 

10.9

 

Credit Agreement, dated as of March 23, 2007, by and among Aventine Renewable Energy, Inc., Aventine Renewable Energy — Mt. Vernon, LLC and Aventine Renewable Energy — Aurora West, LLC, the other Loan Parties thereto, the lenders thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to Aventine’s Current Report on Form 8-K filed on March 26, 2007)

 

 

 

10.9.1

 

First amendment to Credit Agreement, dated as of March 10, 2009, by and among Aventine Renewable Energy, Inc., Aventine Renewable Energy — Mt. Vernon, LLC and Aventine Renewable Energy — Aurora West, LLC, the other Loan Parties thereto, the lenders thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.15.1 to Aventine’s Annual Report on Form 10-K filed March 16, 2009)

 

 

 

10.9.2

 

Letter agreement dated March 12, 2009, related to the Credit Agreement, dated as of March 23, 2007, by and among Aventine Renewable Energy, Inc., Aventine Renewable Energy — Mt. Vernon, LLC and Aventine Renewable Energy — Aurora West, LLC, the other Loan Parties thereto, the lenders thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.15.2 to Aventine’s Annual Report on Form 10-K filed March 16, 2009)

 

 

 

10.9.3

 

Letter agreement dated March 30, 2009, between the Company, Aventine Renewable Energy — Mt. Vernon, LLC, Aventine Renewable Energy — Aurora West, LLC, JPMorgan Chase Bank, N.A., (as administrative agent and a lender), and the other lenders to its Credit Agreement, dated as of March 23, 2007 (as amended) (incorporated by reference to Exhibit 10.1 to Aventine’s Current Report on Form 8-K filed on April 3, 2009)

 



Table of Contents

 

10.10

 

Aventine Renewable Energy Holdings, Inc. 2003 Stock Incentive Plan (Amended and Restated as of April 16, 2007) (incorporated by reference to Exhibit 10.1 to Aventine’s Current Report on Form 8-K filed on April 16, 2007)*

 

 

 

10.11

 

Settlement and Release Agreement, dated as of February 27, 2008, by and among the Company, The Williams Companies, Inc. and Williams Energy Services, LLC (incorporated by reference to Exhibit 10.21 to Aventine’s Annual Report on Form 10-K filed on March 5, 2008)

 

 

 

10.12

 

Debtor in Possession Credit Facility Term Sheet, dated as of April 7, 2009, by and among Brigade Leveraged Capital Structures Fund, Ltd., Nomura Corporate Research & Asset Management, Inc., as Investment Manager for and on behalf of certain lenders, Whitebox Hedged High Yield Partners, L.P., Pandora Select Partners, L.P. (as lenders), Aventine Renewable Energy, Inc., Aventine Renewable Energy — Mt Vernon, LLC, and Aventine Renewable Energy — Aurora West LLC on a joint and several basis as debtors in possession under chapter 11 of the United States Bankruptcy Code in jointly administered cases in the United States Bankruptcy Court for the District of Delaware and the Guarantors named therein (incorporated by reference to Exhibit 10.1 to Aventine’s Current Report on Form 8-K filed on April 13, 2009)

 

 

 

21.1

 

List of subsidiaries of the Registrant

 

 

 

23.1

 

Consent of Ernst & Young LLP

 

 

 

31.1

 

Certificate of Chief Executive Officer of Aventine Renewable Energy Holdings, Inc. pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934

 

 

 

31.2

 

Certificate of Chief Financial Officer of Aventine Renewable Energy Holdings, Inc. pursuant to Rule 13(a)-14(a) under the Securities Exchange Act of 1934

 

 

 

32.1

 

Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

 

 

32.2

 

Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 


*                                         Compensatory plan or arrangement.