Attached files

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EX-10.34 - LIMITED LIABILITY AGR - Pacific Ethanol, Inc.peix_10k-ex1034.htm
EX-32.1 - CERTIFICATION - Pacific Ethanol, Inc.peix_10k-ex3201.htm
EX-23.1 - CONSENT - Pacific Ethanol, Inc.peix_10k-ex2301.htm
EX-31.1 - CERTIFICATION - Pacific Ethanol, Inc.peix_10k-ex3101.htm
EX-31.2 - CERTIFICATION - Pacific Ethanol, Inc.peix_10k-ex3102.htm
EX-21.1 - SUBSIDIARIES - Pacific Ethanol, Inc.peix_10k-ex2101.htm


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, 2010

OR

¨
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: 000-21467

PACIFIC ETHANOL, INC.
(Exact name of registrant as specified in its charter)

Delaware
41-2170618
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)

400 Capitol Mall, Suite 2060, Sacramento, California
95814
(Address of principal executive offices)
(Zip Code)

Registrant’s telephone number, including area code: (916) 403-2123

 
Securities registered pursuant to Section 12(b) of the Act:
 
Title of Class
Name of Exchange on Which Registered
Common Stock, $0.001 par value
The Nasdaq Stock Market LLC
(Nasdaq Capital Market)

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  ¨  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  ¨  No  x

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  x  No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.    Yes  ¨  No  ¨

Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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.   ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or 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  ¨
Accelerated filer  ¨
Non-accelerated filer  ¨ (Do not check if a smaller reporting company)
Smaller reporting company  x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨  No  x

The aggregate market value of the voting common equity held by nonaffiliates of the registrant computed by reference to the closing sale price of such stock, was approximately $50.0 million as of June 30, 2010, the last business day of the registrant’s most recently completed second fiscal quarter. The registrant has no non-voting common equity.

The number of shares of the registrant’s common stock, $0.001 par value, outstanding as of March 31, 2011 was 108,430,832.
 
DOCUMENTS INCORPORATED BY REFERENCE:

Part III incorporates by reference certain information from the registrant’s definitive proxy statement (the “Proxy Statement”) for the 2011 Annual Meeting of Stockholders to be filed on or before April 30, 2011.
 


 
 

 

TABLE OF CONTENTS
Page
 
PART I
 
Item 1.
Business.
1
Item 1A.
Risk Factors.
15
Item 1B.
Unresolved Staff Comments.
26
Item 2.
Properties.
26
Item 3.
Legal Proceedings.
27
Item 4.
(Removed and Reserved).
29
     
 
PART II
 
Item 5.
Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
30
Item 6.
Selected Financial Data.
31
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
31
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
49
Item 8.
Financial Statements and Supplementary Data.
49
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
49
Item 9A.
Controls and Procedures.
49
Item 9B.
Other Information.
51
     
 
PART III
 
Item 10.
Directors, Executive Officers and Corporate Governance.
52
Item 11.
Executive Compensation.
52
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
52
Item 13.
Certain Relationships and Related Transactions, and Director Independence.
52
Item 14.
Principal Accounting Fees and Services.
52
     
 
PART IV
 
Item 15.
Exhibits, Financial Statement Schedules.
52
     
Index to Consolidated Financial Statements
  F-1
Index to Exhibits
 
Signatures
 
Exhibits Filed with this Report
 
 
 

 
 

 

 
CAUTIONARY STATEMENT
 
All statements included or incorporated by reference in this Annual Report on Form 10-K, other than statements or characterizations of historical fact, are forward-looking statements. Examples of forward-looking statements include, but are not limited to, statements concerning projected net sales, costs and expenses and gross margins; our accounting estimates, assumptions and judgments; our success in pending litigation; the demand for ethanol and its co-products; the competitive nature of and anticipated growth in our industry; production capacity and goals; our ability to consummate acquisitions and integrate their operations successfully; and our prospective needs for additional capital. These forward-looking statements are based on our current expectations, estimates, approximations and projections about our industry and business, management’s beliefs, and certain assumptions made by us, all of which are subject to change. Forward-looking statements can often be identified by words such as “anticipates,” “expects,” “intends,” “plans,” “predicts,” “believes,” “seeks,” “estimates,” “may,” “will,” “should,” “would,” “could,” “potential,” “continue,” “ongoing,” similar expressions and variations or negatives of these words. These statements are not guarantees of future performance and are subject to risks, uncertainties and assumptions that are difficult to predict. Therefore, our actual results could differ materially and adversely from those expressed in any forward-looking statements as a result of various factors, some of which are listed under “Risk Factors” in Item 1A of this report. These forward-looking statements speak only as of the date of this report. We undertake no obligation to revise or update publicly any forward-looking statement for any reason, except as otherwise required by law.
 
 
 
 
 
 
 

 
 

 

PART I
 
Item 1.
Business.
 
Business Overview
 
Background
 
We are the leading marketer and producer of low carbon renewable fuels in the Western United States.
 
Since our inception in 2005, we have conducted ethanol marketing operations through our subsidiary Kinergy Marketing, LLC, or Kinergy, through which we market and sell ethanol produced by third parties. In 2006, we began constructing the first of our four then wholly-owned ethanol production facilities, or Pacific Ethanol Plants, and were continuously engaged in plant construction until the fourth facility was completed in 2008. We funded, and until recently directly operated, four wholly-owned production facilities through a subsidiary holding company and four other indirect subsidiaries. We refer to these five subsidiaries as the Plant Owners.
 
In 2006, we completed our Madera, California facility and began producing ethanol and its co-products at the facility, and also acquired a 42% interest in Front Range Energy, LLC, or Front Range, which owns an ethanol production facility in Windsor, Colorado. In 2007, we entered into credit agreements to borrow up to $325.0 million to fund the construction of, or refinance indebtedness in respect of, up to five ethanol production facilities and provide working capital as each production facility became operational. Later in 2007, the credit facility was reduced to $250.8 million for up to four ethanol production facilities. A portion of this indebtedness was used to refinance outstanding indebtedness in respect of the Madera facility as well as other facilities under construction. In 2007, we began production at the Columbia facility in Boardman, Oregon and in 2008, we began production at the Magic Valley facility in Burley, Idaho and another facility in Stockton, California. See “—Pacific Ethanol Plants” below.
 
Our net sales increased significantly from $87.6 million in 2005 to $703.9 million in 2008 as the Pacific Ethanol Plants began production in 2006, 2007 and 2008, with all facilities producing and selling ethanol in the last quarter of 2008. During these periods, we also sold additional volume under ethanol marketing arrangements with third party suppliers. However, our net sales dropped considerably to $316.6 million in 2009 as we idled production at three of the Pacific Ethanol Plants for most of 2009, as discussed further below.
 
Our average ethanol sales price peaked at $2.28 per gallon in 2006, stayed relatively stable for 2007 and 2008, but declined to $1.80 per gallon in 2009. In 2007, our average price of corn, the primary raw material for our ethanol production, began increasing dramatically, ultimately rising by over 125% from $2.44 per bushel in 2006 to $5.52 per bushel in 2008. As a result, our gross margins, which peaked at 11.0% in 2006, began declining in 2007, reaching negative 4.7% in 2008. Our average price of corn declined to $3.98 per bushel in 2009, but lower ethanol prices and overhead and depreciation expenses with no corresponding sales from the idled facilities resulted in a gross margin of negative 7.0% in 2009.
 
From 2006 until the fourth quarter of 2008, when the fourth Pacific Ethanol Plant was completed, we maintained a cost structure commensurate with our construction activities, including substantial project overhead and staffing. Upon completion of the fourth Pacific Ethanol Plant, we sought to alter our cost structure to one more suitable for an operating company. However, beginning in 2008, we began experiencing significant financial constraints and adverse market conditions, and our working capital lines of credit for the Pacific Ethanol Plants were insufficient given substantially higher corn prices and other input costs in the production process.
 

 
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In late 2008 and early 2009, we idled production at three of the Pacific Ethanol Plants due to adverse market conditions and lack of adequate working capital. Adverse market conditions and our financial constraints continued, resulting in an inability to meet our debt service requirements. We and the ethanol industry, as a whole, experienced significant adverse conditions through most of 2009 as a result of elevated corn prices, reduced demand for transportation fuel and declining ethanol prices, resulting in prolonged negative operating margins. In response to these adverse conditions, as well as severe working capital and liquidity constraints, we reduced production significantly and implemented many cost-saving initiatives.
 
On May 17, 2009, each of the Plant Owners filed voluntary petitions for relief under chapter 11 of Title 11 of the United States Code, or Bankruptcy Code, in the United States Bankruptcy Court for the District of Delaware, or Bankruptcy Court, in an effort to restructure their indebtedness, or Chapter 11 Filings. The Plant Owners continued to operate their businesses and manage their properties as debtors and debtors-in-possession during the pendency of the bankruptcy proceedings.
 
On June 3, 2009, the Bankruptcy Court approved the Plant Owners’ post petition financing facility provided by WestLB, AG, New York Branch, or West LB, and the banks and financial institutions that are from time to time lender parties to the Amended and Restated Debtor-in-Possession Credit Agreement dated June 3, 2009, or as amended, the Post Petition Credit Agreement. The post petition credit facility was intended to fund the Plant Owners’ working capital and general corporate needs in the ordinary course of business and allow them to pay these and other amounts as required or permitted to be paid under the terms of the Post Petition Credit Agreement, including the administrative costs associated with the Chapter 11 Filings.
 
On March 26, 2010, the Plant Owners filed a joint plan of reorganization with the Bankruptcy Court. On April 16, 2010, the Plant Owners filed an amended joint plan of reorganization, or the Plan, with the Bankruptcy Court, which was structured in cooperation with a number of the Plant Owners’ secured lenders. The Bankruptcy Court confirmed the Plan at a hearing on June 8, 2010. On June 29, 2010, or Effective Date, the Plant Owners emerged from bankruptcy under the terms of the Plan.
 
 
On the Effective Date, approximately $294.4 million in prepetition and post petition secured indebtedness of the Plant Owners was restructured under a Credit Agreement entered into on June 25, 2010 among the Plant Owners, as borrowers, and West LB and other lenders, or Credit Agreement. Under the Plan, the Plant Owners’ existing prepetition and post petition secured indebtedness of approximately $294.4 million was restructured to consist of approximately $50.0 million in three-year term loans and a new three-year revolving credit facility of up to $35.0 million to fund working capital requirements of New PE Holdco, LLC, or New PE Holdco.
 
Under the Plan, on the Effective Date, all of the ownership interests in the Plant Owners were transferred to New PE Holdco, wholly-owned as of that date by some of the prepetition lenders of the Plant Owners and the new lenders to the post-emergence companies under the Credit Agreement. As a result, the Pacific Ethanol Plants are now wholly-owned by New PE Holdco.
 
Also on the Effective Date, we entered into a Call Option Agreement with New PE Holdco and a number of owners of membership interests in New PE Holdco, whereby we had the right to acquire from the owners membership interests in New PE Holdco in an amount up to 25% of the total membership interests in New PE Holdco for a total price of $30 million in cash (or $1,200,000 for each one percent of membership interest in New PE Holdco).
 

 
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On the Effective Date, we also entered into an Asset Management Agreement with the Plant Owners under which we agreed to provide management services to the Plant Owners whereby we will effectively operate and maintain the Pacific Ethanol Plants on behalf of the Plant Owners. These services generally include, but are not limited to, administering each Plant Owners’ compliance with the Credit Agreement and related financing documents and performing billing, collection, record keeping and other administrative and ministerial responsibilities for each facility. We have agreed to supply all labor and personnel required to perform its services under the agreement, including, but not limited to, the labor and personnel required to operate and maintain the production facilities.
 
Recent Developments
 
On October 6, 2010, we raised $35.0 million through the issuance of $35.0 million in principal amount of senior convertible notes, or Initial Convertible Notes, and warrants to purchase an aggregate of 20,588,235 shares of our common stock, or Initial Warrants. See “Management’s Discussion and Analysis of Financial Condition and Results Operations—Liquidity and Capital Resources—Convertible Notes.” On that same date we sold our 42% interest in Front Range for $18.5 million in cash, paid off our outstanding indebtedness to Lyles United, LLC and Lyles Mechanical Co. in the aggregate amount of approximately $17.0 million and purchased a 20% ownership interest, which represents the single largest interest, in New PE Holdco for an aggregate purchase price of $23.3 million. Of the 20% ownership interest in New PE Holdco we acquired on October 6, 2010, a 12% ownership interest in New PE Holdco was acquired under the Call Option Agreement with New PE Holdco described above.
 
On January 7, 2011, we issued $35.0 million in principal amount of senior convertible notes, or Convertible Notes, in exchange for the Initial Convertible Notes and issued warrants to purchase an aggregate of 20,588,235 shares of our common stock, or Warrants, in exchange for the Initial Warrants. See “Management’s Discussion and Analysis of Financial Condition and Results Operations—Liquidity and Capital Resources—Convertible Notes.”
 
Current Operations
 
We currently manage the production of ethanol at the Pacific Ethanol Plants under the terms of an asset management agreement with the Plant Owners, all of which are now subsidiaries of New PE Holdco. We also market ethanol and its co-products, including wet distillers grain, or WDG, produced by the Pacific Ethanol Plants under the terms of separate marketing agreements with the Plant Owners whose facilities are operational. We also market ethanol and its co-products to other third parties, and provide transportation, storage and delivery of ethanol through third-party service providers in the Western United States, primarily in California, Nevada, Arizona, Oregon, Colorado, Idaho and Washington.
 
We have extensive customer relationships throughout the Western United States and extensive supplier relationships throughout the Western and Midwestern United States. Our customers are integrated oil companies and gasoline marketers who blend ethanol into gasoline. We supply ethanol to our customers either from the Pacific Ethanol Plants located within the regions we serve, or with ethanol procured in bulk from other producers. In some cases, we have marketing agreements with ethanol producers to market all of the output of their facilities. Additionally, we have customers who purchase our co-products for animal feed and other uses.
 
The Pacific Ethanol Plants produce ethanol and its co-products and are comprised of the four facilities described immediately below, three of which are currently operational. See “—Pacific Ethanol Plants” below. If market conditions continue to improve, we may resume operations at the Madera, California facility, subject to the approval of New PE Holdco.
 

 
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Facility Name
 
 
Facility Location
 
 
Estimated Annual Capacity
(gallons)
 
 
Current Operating Status
Magic Valley
 
Burley, ID
 
60,000,000
 
Operating
Columbia
 
Boardman, OR
 
40,000,000
 
Operating
Stockton
 
Stockton, CA
 
60,000,000
 
Operating
Madera
 
Madera, CA
 
40,000,000
 
Idled
 
Company History
 
We are a Delaware corporation formed in February 2005. Our main Internet address is http://www.pacificethanol.net. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, amendments to those reports and other Securities and Exchange Commission, or SEC, filings are available free of charge through our website as soon as reasonably practicable after the reports are electronically filed with, or furnished to, the SEC. Our common stock trades on The NASDAQ Capital Market under the symbol “PEIX.” The inclusion of our Internet address in this report does not include or incorporate by reference into this report any information contained on our website.
 
Business Strategy
 
Our primary goal is to maintain and advance our position as the leading marketer and producer of low carbon renewable fuels in the Western United States. We view the key elements of our business and growth strategy to achieve this objective in short- and long-term perspectives, which include:
 
Short-Term Strategy
 
 
·
Expand ethanol production and marketing revenues, ethanol markets and distribution infrastructure. We plan to increase our ethanol production and marketing revenues by expanding our relationships with third-party ethanol producers and our ethanol customers to increase sales volumes of ethanol throughout the Western United States at profitable margins. In addition, we plan to maintain and increase sales to animal feed customers in the local markets we serve for WDG. We also plan to expand the market for ethanol by continuing to work with the federal government and state governments to encourage the adoption of policies and standards that promote ethanol as a component in transportation fuels. In addition, we plan to expand our distribution infrastructure by increasing our ability to provide transportation, storage and related logistical services to our customers throughout the Western United States.
 
 
·
Operation of Pacific Ethanol Plants. We provide day-to-day operational expertise to manage the Pacific Ethanol Plants under an asset management agreement. We intend to continue operating the Pacific Ethanol Plants in a part owner-operator capacity. Further, if the idled Pacific Ethanol Plant and other third party facilities become operational, we intend to expand our business by providing management services to those facilities.
 
 
·
Focus on cost efficiencies. We operate the Pacific Ethanol Plants in markets where we believe local characteristics create an opportunity to capture a significant production and shipping cost advantage over competing ethanol production facilities. We believe a combination of factors will enable us to achieve this cost advantage, including:
 
 
o
Locations near fuel blending facilities will enable lower ethanol transportation costs and allow timing and logistical advantages over competing locations which require ethanol to be shipped over much longer distances.

 
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o
Locations adjacent to major rail lines will enable the efficient delivery of corn in large unit trains from major corn-producing regions.
 
 
o
Locations near large concentrations of dairy and/or beef cattle will enable delivery of WDG over short distances without the need for costly drying processes.
 
In addition to these location-related efficiencies, we believe that we can continue to increase operating efficiencies by incorporating advanced design elements into the production facilities to take advantage of state-of-the-art technical and operational efficiencies.
 
Long-Term Strategy
 
 
·
Increase our ownership interest in New PE Holdco. We intend to increase our ownership interest in New PE Holdco as opportunities arise to purchase additional interests from other members and as financial resources and business prospects make the acquisition of additional ownership interests in New PE Holdco advisable.
 
 
·
Explore new technologies and renewable fuels. We are evaluating a number of technologies that may increase the efficiency of our ethanol production facilities and reduce our use of carbon-based fuels. For example, we have installed a reactor system at the Columbia facility from Pursuit Dynamics PLC and we are continuing trials for the purpose of verifying the stated benefits. In addition, we are exploring the feasibility of using different and potentially abundant and cost-effective feedstocks, including cellulosic feed stock, to supplement corn as the raw material used in the production of ethanol. As capital resources become available, we intend to continue pursuing these opportunities, including continuing our efforts to build a cellulosic ethanol demonstration facility in the Northwest United States at the Columbia site. On January 29, 2008, the United States Department of Energy awarded us $24.3 million in matching funds to assist in this project.
 
 
·
Evaluate and pursue acquisition opportunities. We intend to evaluate and pursue opportunities to acquire additional ethanol production, storage and distribution facilities and related infrastructure as financial resources and business prospects make the acquisition of these facilities advisable. In addition, we may also seek to acquire facility sites under development.
 
Competitive Strengths
 
We believe that our competitive strengths include the following:
 
 
·
Our customer and supplier relationships. We have developed extensive business relationships with our customers and suppliers. In particular, we have developed extensive business relationships with major and independent un-branded gasoline suppliers who collectively control the majority of all gasoline sales in California and other Western states. In addition, we have developed extensive business relationships with ethanol and grain suppliers throughout the Western and Midwestern United States.
 
 
·
Our ethanol distribution network. We believe that we have a competitive advantage due to our experience in marketing to the segment of customers in major metropolitan and rural markets in the Western United States. We have developed an ethanol distribution network for delivery of ethanol by truck to virtually every significant fuel terminal as well as to numerous smaller fuel terminals throughout California and other Western states. Fuel terminals have limited storage capacity and we have been successful in securing storage tanks at many of the terminals we service. In addition, we have an extensive network of third-party delivery trucks available to deliver ethanol throughout the Western United States.

 
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·
Our operational expertise. We began managing ethanol production facilities in 2006. We believe that we have obtained operational expertise and know-how that can be used to continue operating the Pacific Ethanol Plants and provide operational services to third party facilities.
 
 
·
Our strategic locations. We believe that our focus on developing and acquiring ethanol production facilities in markets where local characteristics create the opportunity to capture a significant production and shipping cost advantage over competing ethanol production facilities provides us with competitive advantages, including transportation cost, delivery timing and logistical advantages as well as higher margins associated with the local sale of WDG and other co-products.
 
 
·
Our low carbon-intensity ethanol. With the recently enacted California Low Carbon Fuels Standard for transportation fuels, carbon emission standards placed on ethanol produced in California are currently higher than in other states, significantly favoring low carbon-intensity fuels. The ethanol produced in California by the Pacific Ethanol Plants and certain other California producers, all of which is marketed through Kinergy, has a lower carbon-intensity rating than either gasoline or ethanol produced in the mid-west, and is therefore a superior product for our California customers.
 
 
·
Modern technologies. The Pacific Ethanol Plants use the latest production technologies to take advantage of state-of-the-art technical and operational efficiencies in order to achieve lower operating costs and more efficient production of ethanol and its co-products and reduce our use of carbon-based fuels.
 
 
·
Our experienced management. Neil M. Koehler, our President and Chief Executive Officer, has over 20 years of experience in the ethanol production, sales and marketing industry. Mr. Koehler is a Director of the California Renewable Fuels Partnership, a Director of the Renewable Fuels Association, or RFA, and is a frequent speaker on the issue of renewable fuels and ethanol marketing and production. In addition to Mr. Koehler, we have seasoned managers with many years of experience in the ethanol, fuel and energy industries leading our various departments. We believe that the experience of our management over the past two decades and our ethanol marketing operations have enabled us to establish valuable relationships in the ethanol industry and understand the business of marketing and producing ethanol and its co-products.
 
We believe that these advantages will allow us to capture an increasing share of the total market for ethanol and its co-products.
 
Industry Overview and Market Opportunity
 
Overview of Ethanol Market
 
The primary applications for fuel-grade ethanol in the United States include:
 
 
·
Octane enhancer. On average, regular unleaded gasoline has an octane rating of 87 and premium unleaded gasoline has an octane rating of 91. In contrast, pure ethanol has an average octane rating of 113. Adding ethanol to gasoline enables refiners to produce greater quantities of lower octane blend stock with an octane rating of less than 87 before blending. In addition, ethanol is commonly added to finished regular grade gasoline as a means of producing higher octane mid-grade and premium gasoline.

 
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·
Renewable fuels. Ethanol is blended with gasoline in order to enable gasoline refiners to comply with a variety of governmental programs, in particular, the national Renewable Fuel Standard, or RFS, program which was enacted to promote alternatives to fossil fuels. See “—Governmental Regulation.”
 
 
·
Fuel blending. In addition to its performance and environmental benefits, ethanol is used to extend fuel supplies. As the need for automotive fuel in the United States increases and the dependence on foreign crude oil and refined products grows, the United States is increasingly seeking domestic sources of fuel. Much of the ethanol blending throughout the United States is done for the purpose of extending the volume of fuel sold at the gasoline pump.
 
The ethanol fuel industry is greatly dependent upon tax policies and environmental regulations that favor the use of ethanol in motor fuel blends in the United States. See “—Governmental Regulation.” Ethanol blends have been either wholly or partially exempt from the federal excise tax on gasoline since 1978. The current federal excise tax on gasoline is $0.184 per gallon and is paid at the terminal by refiners and marketers. If the fuel is blended with ethanol, the blender may claim a $0.45 per gallon tax credit for each gallon of ethanol used in the mixture. Federal law also requires the sale of oxygenated fuels in a number of carbon monoxide non-attainment Metropolitan Statistical Areas, or MSAs, during at least four winter months, typically November through February.
 
In addition, the Energy Independence and Security Act of 2007, which was signed into law in December 2007, significantly increased the prior national RFS. The national RFS significantly increases the mandated use of renewable fuels to approximately 14.0 billion gallons in 2011 and 15.0 billion gallons in 2012, and rises incrementally and peaks at 36.0 billion gallons by 2022. We believe that these increases will bolster demand for ethanol.
 
Effective January 1, 2010, the State of California implemented a Low Carbon Fuels Standard for transportation fuels. The California Governor’s office estimates that the standard will have the effect of increasing current renewable fuels use in California by three to five times by 2020. The State of Oregon implemented a state-wide renewable fuels standard effective January 2008. This standard requires a 10% ethanol blend in every gallon of gasoline and is expected to cause the use of approximately 160 million gallons of ethanol per year in Oregon.
 
According to the RFA, the domestic ethanol industry produced approximately 13.2 billion gallons of ethanol in 2010, an increase of approximately 22% from the approximately 10.8 billion gallons of ethanol produced in 2009. We believe that the ethanol market in California alone represented approximately 10% of the national market. However, the Western United States has relatively few ethanol facilities and local ethanol production levels are substantially below the local demand for ethanol. The balance of ethanol is shipped via rail from the Midwest to the Western United States. Gasoline and diesel fuel that supply the major fuel terminals are shipped in pipelines throughout portions of the Western United States. Unlike gasoline and diesel fuel, however, ethanol is not shipped in these pipelines because ethanol has an affinity for mixing with water already present in the pipelines. When mixed, water dilutes ethanol and creates significant quality control issues. Therefore, ethanol must be trucked from rail terminals to regional fuel terminals, or blending racks.
 
We believe that approximately 90% of the ethanol produced in the United States is made in the Midwest from corn. According to the DOE, ethanol is typically blended at 5.7% to 10% by volume, but is also blended at up to 85% by volume for vehicles designed to operate on 85% ethanol. The Environmental Protection Agency, or EPA, recently increased the allowable blend of ethanol in gasoline from 10% to 15%. Compared to gasoline, ethanol is generally considered to be cleaner burning and contains higher octane. We anticipate that the increasing demand for transportation fuels coupled with limited opportunities for gasoline refinery expansions and the growing importance of reducing CO2 emissions through the use of renewable fuels will generate additional growth in the demand for ethanol in the Western United States.

 
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Ethanol prices, net of tax incentives offered by the federal government, are generally positively correlated to fluctuations in gasoline prices. In addition, we believe that ethanol prices in the Western United States are typically $0.15 to $0.20 per gallon higher than in the Midwest due to the freight costs of delivering ethanol from Midwest production facilities.
 
According to the DOE, total annual gasoline consumption in the United States is approximately 139 billion gallons and total annual ethanol consumption represented less than 10% of this amount in 2010. We believe that the domestic ethanol industry has substantial potential for growth to initially reach at least 10% of the total annual gasoline consumption in the United States, or approximately 14 billion gallons of ethanol annually and thereafter up to 36 billion gallons of ethanol annually required under the national RFS by 2022, subject to an annual EPA review to adjust targets based on availability of commercially produced advanced and cellulose biofuels.
 
While we believe that the overall national market for ethanol will grow, we believe that the market for ethanol in specific geographic areas including California could experience either increases or decreases in demand depending on, among other factors, the preferences of petroleum refiners and state policies. See “Risk Factors.”
 
Overview of Ethanol Production Process
 
The production of ethanol from starch- or sugar-based feedstocks has been refined considerably in recent years, leading to a highly-efficient process that we believe now yields substantially more energy from ethanol and its co-products than is required to make the products. The modern production of ethanol requires large amounts of corn, or other high-starch grains, and water as well as chemicals, enzymes and yeast, and denaturants including unleaded gasoline or liquid natural gas, in addition to natural gas and electricity.
 
In the dry milling process, corn or other high-starch grains are first ground into meal and then slurried with water to form a mash. Enzymes are then added to the mash to convert the starch into the simple sugar, dextrose. Ammonia is also added for acidic (pH) control and as a nutrient for the yeast. The mash is processed through a high temperature cooking procedure, which reduces bacteria levels prior to fermentation. The mash is then cooled and transferred to fermenters, where yeast is added and the conversion of sugar to ethanol and CO2 begins.
 
After fermentation, the resulting “beer” is transferred to distillation, where the ethanol is separated from the residual “stillage.” The ethanol is concentrated to 190 proof using conventional distillation methods and then is dehydrated to approximately 200 proof, representing 100% alcohol levels, in a molecular sieve system. The resulting anhydrous ethanol is then blended with about 5% denaturant, which is usually gasoline, and is then ready for shipment to market.
 
The residual stillage is separated into a coarse grain portion and a liquid portion through a centrifugation process. The soluble liquid portion is concentrated to about 40% dissolved solids by an evaporation process. This intermediate state is called condensed distillers solubles, or syrup. The coarse grain and syrup portions are then mixed to produce WDG or can be mixed and dried to produce dried distillers grains with solubles, or DDGS. Both WDG and DDGS are high-protein animal feed products.

 
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Overview of Distillers Grains Market
 
Most distillers grains are produced in the Midwest, where producers dry the grains before shipping. Successful and profitable delivery of DDGS from the Midwest to markets in the Western United States faces a number of challenges, including drying of distiller grains which may increase the energy cost to dry the grains and reduce the quality of the feed product, and longer distance to market, which may increase the handling and transportation costs to deliver the grains to market. By not drying the distillers grains and by shipping WDG locally, we believe that we will be able to better preserve the feed value of this product, as the WDG retains a higher percentage of nutrients than DDGS.
 
Historically, the market price for distillers grains has generally tracked the value of corn. We believe that the market price of DDGS is determined by a number of factors, including the market value of corn, soybean meal and other competitive ingredients, the performance or value of DDGS in a particular feed formulation and general market forces of supply and demand. The market price of distillers grains is also often influenced by nutritional models that calculate the feed value of distillers grains by nutritional content, as well as reliability of consistent supply.
 
Customers
 
We purchase ethanol from the Pacific Ethanol Plants and other third-parties and resell ethanol to various customers in the Western United States. We also arrange for transportation, storage and delivery of ethanol purchased by our customers through our agreements with third-party service providers. In addition, we purchase WDG from the Pacific Ethanol Plants and sell WDG to customers comprised of dairies and feedlots located near the Pacific Ethanol Plants.
 
During 2010 and 2009, we produced or purchased ethanol from third parties and resold an aggregate of approximately 272 million and 173 million gallons of fuel-grade ethanol to approximately 57 and 60 customers, respectively. Sales to our two largest customers in 2010 and 2009 represented approximately 24% and 32%, of our net sales, respectively. These customers, each of whom accounted for 10% or more of our net sales in 2010 and 2009, were Chevron Products USA and Valero Energy Corporation, or Valero. Sales to each of our other customers represented less than 10% of our net sales in each of 2010 and 2009.
 
Most of the major metropolitan areas in the Western United States have fuel terminals served by rail, but other major metropolitan areas and more remote smaller cities and rural areas do not. We believe that we have a competitive advantage due to our experience in marketing to the segment of customers in major metropolitan and rural markets in the Western United States. We manage the complicated logistics of shipping ethanol purchased from third-parties from the Midwest by rail to intermediate storage locations throughout the Western United States and trucking the ethanol from these storage locations to blending racks where the ethanol is blended with gasoline. We believe that by establishing an efficient service for truck deliveries to these more remote locations, we have differentiated ourselves from our competitors. In addition, by producing ethanol in the Western United States, we believe that we will benefit from our ability to increase spot sales of ethanol from this additional supply following ethanol price spikes caused from time to time by rail delays in delivering ethanol from the Midwest to the Western United States. In addition to producing ethanol, we produce ethanol co-products, including WDG. We endeavor to position WDG as the protein feed of choice for cattle based on its nutritional composition, consistency of quality and delivery, ease of handling and its mixing ability with other feed ingredients. We are one of the few WDG producers with production facilities located in the Western United States and we primarily sell our WDG to dairy farmers in close proximity to the Pacific Ethanol Plants.

 
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Suppliers
 
Our marketing operations are dependent upon various third-party producers of fuel-grade ethanol. In addition, we provide ethanol transportation, storage and delivery services through third-party service providers with whom we have contracted to receive ethanol at agreed upon locations from our suppliers and to store and/or deliver the ethanol to agreed upon locations on behalf of our customers. These contracts generally run from year-to-year, subject to termination by either party upon advance written notice before the end of the then current annual term.
 
During 2010 and 2009, we purchased fuel-grade ethanol and corn, the largest component in producing ethanol, from our suppliers. Purchases from our three largest suppliers in 2010 represented approximately 60% of our total ethanol and corn purchases. Purchases from our four largest suppliers in 2009 represented approximately 55% of our total ethanol and corn purchases. Purchases from each of our other suppliers represented less than 10% of total ethanol and corn purchases in each of 2010 and 2009.
 
The ethanol production operations of the Pacific Ethanol Plants are dependent upon various raw materials suppliers, including suppliers of corn, natural gas, electricity and water. The cost of corn is the most important variable cost associated with the production of ethanol. An ethanol facility must be able to efficiently ship corn from the Midwest via rail and cheaply and reliably truck ethanol to local markets. We believe that our existing grain receiving facilities at the Pacific Ethanol Plants are some of the most efficient grain receiving facilities in the United States. We source corn for the Pacific Ethanol Plants using standard contracts, including spot purchase, forward purchase and basis contracts. When resources are available to do so, we seek to limit the exposure of the Pacific Ethanol Plants to raw material price fluctuations by purchasing forward a portion of their corn requirements on a fixed price basis and by purchasing corn and other raw materials future contracts. In addition, to help protect against supply disruptions, the Pacific Ethanol Plants may maintain inventories of corn.
 
Pacific Ethanol Plants
 
The table below provides an overview of the Pacific Ethanol Plants owned by New PE Holdco and operated by us. Three of the Pacific Ethanol Plants are currently operational. If market conditions continue to improve, we may resume operations at the Madera, California facility, subject to the approval of New PE Holdco.
 
 
 
Madera
Facility
 
Columbia
Facility
Magic
Valley
Facility
 
Stockton
Facility
Location
Madera, CA
Boardman, OR
Burley, ID
Stockton, CA
Quarter/Year operations began
4th Qtr., 2006
3rd Qtr., 2007
2nd Qtr., 2008
3rd Qtr., 2008
Operating status
Idled
Operating
Operating
Operating
Annual design basis ethanol production capacity (in millions of gallons)
35
35
50
50
Approximate maximum annual ethanol production capacity (in millions of gallons)
40
40
60
60
Ownership by New PE Holdco
100%
100%
100%
100%
Primary energy source
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Estimated annual WDG production capacity (in thousands of tons)
293
293
418
418
 
Commodity Risk Management
 
We may seek to employ one or more risk mitigation techniques when sufficient working capital is available. We may seek to mitigate our exposure to commodity price fluctuations by purchasing forward a portion of our corn and natural gas requirements through fixed-price or variable-price contracts with our suppliers, as well as entering into derivative contracts for ethanol, corn and natural gas prices. To mitigate ethanol inventory price risks, we may sell a portion of our production forward under fixed- or index-price contracts, or both. We may hedge a portion of the price risks by selling exchange-traded futures contracts. Proper execution of these risk mitigation strategies can reduce the volatility of our gross profit margins.

 
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Marketing Arrangements
 
In addition to our marketing agreements with the Plant Owners whose facilities are operational to market all of the ethanol produced at those Pacific Ethanol Plants, we have exclusive ethanol marketing agreements with third-party ethanol producers, including Calgren Renewable Fuels, LLC and Front Range, to market and sell their entire ethanol production volumes. Calgren Renewable Fuels, LLC owns and operates an ethanol production facility in Pixley, California with annual production capacity of 55 million gallons. Front Range owns and operates an ethanol production facility in Windsor, Colorado with annual production capacity of 50 million gallons. We intend to evaluate and pursue opportunities to enter into marketing arrangements with other ethanol producers as business prospects make these marketing arrangements advisable.
 
Competition
 
We operate in the highly competitive ethanol marketing and production industry. The largest ethanol producers in the United States are Archer Daniels Midland Company, or ADM, and Valero, collectively with over 20% of the total installed capacity of ethanol in the United States. In addition, there are many mid-size producers with several plants under ownership, smaller producers with one or two plants, and several ethanol marketers that create significant competition. Overall, we believe there are over 200 ethanol facilities in the United States with an installed capacity of approximately 13.5 billion gallons and many brokers and marketers with whom we compete for sales of ethanol and its co-products.
 
We believe that our competitive strengths include our strategic locations in the Western United States, our extensive ethanol distribution network, our extensive customer and supplier relationships, our use of modern technologies at our production facilities and our experienced management. We believe that these advantages will allow us to capture an increasing share of the total market for ethanol and its co-products and earn favorable margins on ethanol and its co-products that we produce.
 
Our strategic focus on particular geographic locations designed to exploit cost efficiencies may nevertheless result in higher than expected costs as a result of more expensive raw materials and related shipping costs, including corn, which generally must be transported from the Midwest. If the costs of producing and shipping ethanol and its co-products over short distances are not advantageous relative to the costs of obtaining raw materials from the Midwest, then the planned benefits of our strategic locations may not be realized.
 
Governmental Regulation
 
Our business is subject to federal, state and local laws and regulations relating to the protection of the environment and in support of the corn and ethanol industries. These laws, their underlying regulatory requirements and their enforcement, some of which are described below, impact, or may impact, our existing and proposed business operations by imposing:
 
 
·
restrictions on our existing and proposed business operations and/or the need to install enhanced or additional controls;
 
 
·
the need to obtain and comply with permits and authorizations;

 
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·
liability for exceeding applicable permit limits or legal requirements, in some cases for the remediation of contaminated soil and groundwater at our facilities, contiguous and adjacent properties and other properties owned and/or operated by third parties; and
 
 
·
specifications for the ethanol we market and produce.
 
In addition, some of the governmental regulations to which we are subject are helpful to our ethanol marketing and production business. The ethanol fuel industry is greatly dependent upon tax policies and environmental regulations that favor the use of ethanol in motor fuel blends in North America. Some of the governmental regulations applicable to our ethanol marketing and production business are briefly described below.
 
Federal Excise Tax Exemption
 
The current federal excise tax on gasoline is $0.184 per gallon, and is paid at the terminal by refiners and marketers. If the fuel is blended with ethanol, the blender may claim a $0.45 per gallon tax credit for each gallon of ethanol used in the mixture. The expiration date of the federal excise tax exemption is December 31, 2011.
 
Clean Air Act Amendments of 1990
 
In November 1990, a comprehensive amendment to the Clean Air Act of 1977, or Clean Air Act, established a series of requirements and restrictions for gasoline content designed to reduce air pollution in identified problem areas of the United States. The two principal components affecting motor fuel content are the oxygenated fuels program, which is administered by states under federal guidelines, and a federally supervised reformulated gasoline, or RFG, program.
 
Oxygenated Fuels Program
 
Federal law requires the sale of oxygenated fuels in a number of carbon monoxide non-attainment MSAs during at least four winter months, typically November through February. Any additional MSAs not in compliance for a period of two consecutive years may also be included in the program. The EPA Administrator is afforded flexibility in requiring a shorter or longer period of use depending upon available supplies of oxygenated fuels or the level of non-attainment. This law currently affects the Los Angeles area, where over 150 million gallons of ethanol are blended with gasoline each winter.
 
Reformulated Gasoline Program
 
The Clean Air Act Amendments of 1990 established special standards effective January 1, 1995 for the most polluted ozone non-attainment areas: Los Angeles Area, Baltimore, Chicago Area, Houston Area, Milwaukee Area, New York City Area, Hartford, Philadelphia Area and San Diego, with provisions to add other areas in the future if conditions warrant. California’s San Joaquin Valley, the location of both the Madera and Stockton facilities, was added in 2002. At the outset of the RFG program there were a total of 96 MSAs not in compliance with clean air standards for ozone, which represents approximately 60% of the national market.
 
The RFG program also includes a provision that allows individual states to “opt into” the federal program by request of the governor, to adopt standards promulgated by California that are stricter than federal standards, or to offer alternative programs designed to reduce ozone levels. Nearly the entire Northeast and middle Atlantic areas from Washington, D.C. to Boston not under the federal mandate have “opted into” the federal standards.

 
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These state mandates in recent years have created a variety of gasoline grades to meet different regional environmental requirements. The RFG program accounts for about 30% of nationwide gasoline consumption. California refiners blend a minimum of 2.0% oxygen by weight, which is the equivalent of 5.7% ethanol in every gallon of gasoline, or roughly 1.0 billion gallons of ethanol per year in California alone.
 
National Energy Legislation
 
In addition, the Energy Independence and Security Act of 2007, which was signed into law in December 2007, significantly increased the prior national RFS. The national RFS significantly increases the mandated use of renewable fuels to approximately 14.0 billion gallons in 2011 and 15.0 billion gallons in 2012, and rises incrementally and peaks at 36.0 billion gallons by 2022.
 
E15 (a blend of gasoline and ethanol)
 
On October 13, 2010, the EPA partially granted a waiver request application submitted under Section 211(f)(4) of the Clean Air Act. This partial waiver allows fuel and fuel additive manufacturers to introduce into commerce gasoline that contains greater than 10 volume percent of ethanol, up to 15 volume percent of ethanol, or E15, for use in some motor vehicles once other conditions are fulfilled. This waiver only applies to vehicles from model year 2001 and beyond. It is important to remember that there are a number of additional steps that must be completed – some of which are not under EPA control – to allow the sale and distribution of E15. These include, but are not limited to, submission of a complete E15 fuels registration application by industry, and changes to some states’ laws to allow for the use of E15.
 
State Energy Legislation and Regulations
 
State energy legislation and regulations may affect the demand for ethanol. California recently passed legislation regulating the total emissions of CO2 from vehicles and other sources. In 2006, the State of Washington passed a statewide renewable fuel standard effective December 1, 2008. The State of Oregon implemented a state-wide renewable fuels standard effective January 2008. This standard requires a 10% ethanol blend in every gallon of gasoline and is expected to cause the use of approximately 160 million gallons of ethanol per year in Oregon. We believe other states may also enact their own renewable fuel standards.
 
In January 2007, California’s Governor signed an executive order directing the California Air Resources Board to implement California’s Low Carbon Fuels Standard for transportation fuels. The Governor’s office estimates that the standard will have the effect of increasing current renewable fuels use in California by three to five times by 2020.
 
The State of California has established a policy to support ethanol produced in California with the California Ethanol Producer Incentive Program, or CEPIP, a producer incentive which offers up to $0.25 per gallon when ethanol production profitability is less than prescribed levels determined by the California Energy Commission, or CEC. The Pacific Ethanol Plants located in California are eligible for the CEPIP, and the Stockton facility is currently participating in the program. This program began in late 2010 and is to continue for four years. No assurances can be given that the California legislature will continue to fund the CEPIP or that the CEC will not alter the program thresholds, participant eligibility or other policy choices that may impact the ability of the Pacific Ethanol Plants located in California to be eligible for the CEPIP.

 
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Additional Environmental Regulations
 
In addition to the governmental regulations applicable to the ethanol marketing and production industries described above, our business is subject to additional federal, state and local environmental regulations, including regulations established by the EPA, the Regional Water Quality Control Board, the San Joaquin Valley Air Pollution Control District and the California Air Resources Board. We cannot predict the manner or extent to which these regulations will harm or help our business or the ethanol production and marketing industry in general.
 
Employees
 
As of March 31, 2011, we had approximately 145 full-time employees. We believe that our employees are highly-skilled, and our success will depend in part upon our ability to retain our employees and attract new qualified employees, many of whom are in great demand. We have never had a work stoppage or strike, and no employees are presently represented by a labor union or covered by a collective bargaining agreement. We consider our relations with our employees to be good.
 
 
 
 
 
 

 
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Item 1A.
Risk Factors.
 
Risks Related to our Business
 
We have incurred significant losses and negative operating cash flow in the past and we will likely incur significant losses and negative operating cash flow in the foreseeable future. Continued losses and negative operating cash flow will hamper our operations and prevent us from expanding our business.
 
We have incurred significant losses and negative operating cash flow in the past. For 2009 and 2008, we incurred net losses of approximately $308.7 million and $199.2 million, respectively. For 2009 and 2008, we incurred negative operating cash flow of approximately $6.3 million and $55.2 million, respectively. We reported net income of $69.5 million for 2010, primarily due to a $119.4 million net gain in connection with the completion of the bankruptcy proceedings of our former indirect wholly-owned subsidiaries. We believe that we will likely incur significant losses and negative operating cash flow in the foreseeable future. We expect to rely on cash on hand, cash, if any, generated from our operations and cash, if any, generated from any future financing activities, if any, to fund all of the cash requirements of our business. Continued losses and negative operating cash flow may hamper our operations and impede us from expanding our business. Continued losses and negative operating cash flow are also likely to make our capital raising needs more acute while limiting our ability to raise additional financing on favorable terms.
 
We may not have cash on hand to satisfy our obligations under the Convertible Notes when required under the terms of the Convertible Notes.
 
We are obligated to make principal and interest payments under the Convertible Notes prior to the maturity of the Convertible Notes and the entire outstanding principal amount of the Convertible Notes will become due and payable by us at maturity. We currently anticipate paying all amounts due under the Convertible Notes in shares of our common stock. However, we may be prohibited from satisfying our obligations under the Convertible Notes in shares of our common stock in a number of circumstances. Our ability to pay the amounts due under the Convertible Notes in cash will be subject to our liquidity position at the time. We cannot assure you that we will have sufficient financial resources or be able to arrange financing to pay the amounts due under the Convertible Notes in cash on any date that we would be required to do so under the terms of the Convertible Notes. While we could seek to obtain third-party financing to pay for any amounts due in cash, third-party financing may not be available on commercially reasonable terms, if at all.
 
We may not have the ability to redeem the Convertible Notes when required under the terms of the Convertible Notes.
 
Holders of the Convertible Notes may require us to redeem for cash all or a portion of their Convertible Notes upon the occurrence of an event of default under the Convertible Notes or change of control events. Our ability to redeem the Convertible Notes in cash, if we are required to do so, is subject to our liquidity position at the time. We cannot assure you that we will have sufficient financial resources or be able to arrange financing to pay the redemption price of the Convertible Notes on any date that we would be required to do so under the terms of the Convertible Notes. While we could seek to obtain third-party financing to pay for any amounts due in cash upon these events, third-party financing may not be available on commercially reasonable terms, if at all.

 
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Provisions of the Convertible Notes could discourage an acquisition of us by a third party.
 
A number of provisions of the Convertible Notes could make it more difficult or more expensive for a third party to acquire us. Upon the occurrence of transactions constituting a change of control, holders of the Convertible Notes will have the right, at their option, to require us to redeem all or a portion of their Convertible Notes in cash. In addition, under the terms of the Convertible Notes, we may not enter into specified mergers or acquisitions unless, among other things, the surviving person or entity assumes our obligations under the Convertible Notes or the holders of the Convertible Notes waive their right to have the surviving person or entity assume our obligations under the Convertible Notes. These provisions may make it more difficult or discourage a takeover of Pacific Ethanol.
 
We are a minority member of New PE Holdco with limited control over that entity’s business decisions. We are therefore dependent upon the business judgment and conduct of the board of directors of that entity. As a result, our interests may not be as well served as if we were in control of New PE Holdco, which could adversely affect its contribution to our results of operations and our business prospects related to that entity.
 
New PE Holdco owns, and we operate, the Pacific Ethanol Plants. We own 20% of New PE Holdco, which represents a minority interest in that entity. New PE Holdco is managed by a board of directors. Although we have representation on the board of directors, we do not control the actions of the board of directors and are therefore largely dependent upon its business judgment and conduct. As a result, our interests may not be as well served as if we were in control of New PE Holdco. Accordingly, the contribution by New PE Holdco to our results of operations and our business prospects related to that entity may be adversely affected by our lack of control over that entity.
 
The termination of the asset management agreement and marketing agreements to which we are a party relating to the Pacific Ethanol Plants would lead to a significant decline in our sales and profitability.
 
A significant amount of our revenues are derived from an asset management agreement with the Plant Owners under which we manage the production and operations of the Pacific Ethanol Plants. The asset management agreement has a term of six months and automatically renews for successive six month terms unless terminated by either party by giving notice 60 days prior to the end of any six month period. We also derive revenues from our activities related to the marketing of the ethanol and WDG produced by the Pacific Ethanol Plants under the terms of separate marketing agreements with the Plant Owners whose facilities are operational. If the asset management agreement or the marketing agreements are terminated for any reason, our revenues and financial condition will decline.
 
We recognized impairment charges in 2009 and may recognize additional impairment charges in the future.
 
For 2009, we recognized asset impairment charges in the aggregate amount of $252.4 million. These impairment charges primarily related to our previously wholly-owned ethanol facilities. We performed our forecast of expected future cash flows of these facilities over their estimated useful lives. The forecasts of expected future cash flows are heavily dependent upon management’s estimates and probability analysis of various scenarios including market prices for ethanol, our primary product, and corn, our primary production input. Both ethanol and corn costs have fluctuated significantly in the past year, therefore these estimates are highly subjective and are management’s best estimates at this time. During 2010, as a result of the sale of our 42% ownership interest in Front Range, we incurred an additional loss on the difference between our cost basis of the investment in Front Range and the price at which we sold our investment. We may also incur additional impairments in the future on current or future long-lived assets.

 
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The results of operations of the Pacific Ethanol Plants and their ability to operate at a profit is largely dependent on managing the spreads among the prices of corn, natural gas, ethanol and WDG, the prices of which are subject to significant volatility and uncertainty.
 
The results of operations of the Pacific Ethanol Plants are highly impacted by commodity prices, including the spreads between the cost of corn and natural gas that they must purchase, and the price of ethanol and WDG that they sell. Prices and supplies are subject to and determined by market forces over which we have no control, such as weather, domestic and global demand, shortages, export prices, and various governmental policies in the United States and around the world. As a result of price volatility for these commodities, our operating results may fluctuate substantially. Increases in corn prices or natural gas or decreases in ethanol or WDG prices may make it unprofitable to operate the Pacific Ethanol Plants. No assurance can be given that corn and natural gas can be purchased at, or near, current or any particular prices and that ethanol or WDG will sell at, or near, current or any particular prices. Consequently, our results of operations and financial position may be adversely affected by increases in the price of corn or natural gas or decreases in the price of ethanol or WDG.
 
In early 2006, the spread between ethanol and corn prices was at an historically high level, driven in large part by oil companies removing a competitive product, methyl tertiary butyl ether (MTBE), from the fuel stream and replacing it with ethanol in a relatively short time period. However, since that time, this spread has fluctuated widely and narrowed significantly. Fluctuations are likely to continue to occur. A sustained narrow spread or any further reduction in the spread between ethanol and corn prices, whether as a result of sustained high or increased corn prices or sustained low or decreased ethanol prices, would adversely affect our results of operations and financial position. Further, combined revenues from sales of ethanol and WDG could decline below the marginal cost of production, which could cause us to suspend production of ethanol and WDG at some or all of the Pacific Ethanol Plants.
 
Increased ethanol production may cause a decline in ethanol prices or prevent ethanol prices from rising, and may have other negative effects, adversely impacting our results of operations, cash flows and financial condition.
 
We believe that the most significant factor influencing the price of ethanol has been the substantial increase in ethanol production in recent years. Domestic ethanol production capacity has increased steadily from an annualized rate of 1.5 billion gallons per year in January 1999 to 13.2 billion gallons in 2010 according to the RFA. See “Business—Governmental Regulation.” However, increases in the demand for ethanol may not be commensurate with increases in the supply of ethanol, thus leading to lower ethanol prices. Demand for ethanol could be impaired due to a number of factors, including regulatory developments and reduced United States gasoline consumption. Reduced gasoline consumption has occurred in the past and could occur in the future as a result of increased gasoline or oil prices.
 
The market price of ethanol is volatile and subject to large fluctuations, which may cause our profitability or losses to fluctuate significantly.
 
The market price of ethanol is volatile and subject to large fluctuations. The market price of ethanol is dependent upon many factors, including the supply of ethanol and the price of gasoline, which is in turn dependent upon the price of petroleum which is highly volatile and difficult to forecast. For example, our average sales price of ethanol increased by 9% in 2010 after decreasing by 20% in 2009 from the prior year’s average sales price per gallon. Fluctuations in the market price of ethanol may cause our profitability or losses to fluctuate significantly.

 
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Disruptions in ethanol production infrastructure may adversely affect our business, results of operations and financial condition.
 
Our business depends on the continuing availability of rail, road, port, storage and distribution infrastructure. In particular, due to limited storage capacity at the Pacific Ethanol Plants and other considerations related to production efficiencies, the Pacific Ethanol Plants depend on just-in-time delivery of corn. The production of ethanol also requires a significant and uninterrupted supply of other raw materials and energy, primarily water, electricity and natural gas. The prices of electricity and natural gas have fluctuated significantly in the past and may fluctuate significantly in the future. Local water, electricity and gas utilities may not be able to reliably supply the water, electricity and natural gas that the Pacific Ethanol Plants will need or may not be able to supply those resources on acceptable terms. Any disruptions in the ethanol production infrastructure, whether caused by labor difficulties, earthquakes, storms, other natural disasters or human error or malfeasance or other reasons, could prevent timely deliveries of corn or other raw materials and energy and may require the Pacific Ethanol Plants to halt production which could have a material adverse effect on our business, results of operations and financial condition.
 
We and the Pacific Ethanol Plants may engage in hedging transactions and other risk mitigation strategies that could harm our results of operations.
 
In an attempt to partially offset the effects of volatility of ethanol prices and corn and natural gas costs, the Pacific Ethanol Plants may enter into contracts to fix the price of a portion of their ethanol production or purchase a portion of their corn or natural gas requirements on a forward basis. In addition, we may engage in other hedging transactions involving exchange-traded futures contracts for corn, natural gas and unleaded gasoline from time to time. The financial statement impact of these activities is dependent upon, among other things, the prices involved and our ability to sell sufficient products to use all of the corn and natural gas for which forward commitments have been made. 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, in the case of exchange-traded contracts, where there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices paid or received by us. As a result, our results of operations and financial position may be adversely affected by fluctuations in the price of corn, natural gas, ethanol and unleaded gasoline.
 
Operational difficulties at the Pacific Ethanol Plants could negatively impact sales volumes and could cause us to incur substantial losses.
 
Operations at the Pacific Ethanol Plants are subject to labor disruptions, unscheduled downtimes and other operational hazards inherent in the ethanol production industry, including equipment failures, fires, explosions, abnormal pressures, blowouts, pipeline ruptures, transportation accidents and natural disasters. Some of these operational hazards may cause personal injury or loss of life, severe damage to or destruction of property and equipment or environmental damage, and may result in suspension of operations and the imposition of civil or criminal penalties. Insurance obtained by the Pacific Ethanol Plants may not be adequate to fully cover the potential operational hazards described above or the Pacific Ethanol Plants may not be able to renew this insurance on commercially reasonable terms or at all.
 
Moreover, the production facilities at the Pacific Ethanol Plants may not operate as planned or expected. All of these facilities are designed to operate at or above a specified production capacity. The operation of these facilities is and will be, however, subject to various uncertainties. As a result, these facilities may not produce ethanol and its co-products at expected levels. In the event any of these facilities do not run at their expected capacity levels, our business, results of operations and financial condition may be materially and adversely affected.

 
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The United States ethanol industry is highly dependent upon myriad federal and state legislation and regulation and any changes in legislation or regulation could have a material adverse effect on our results of operations and financial condition.
 
The elimination or reduction of federal excise tax incentives could have a material adverse effect on our results of operations and our financial condition.
 
The amount of ethanol production capacity in the United States exceeds the mandated usage of renewable biofuels. Ethanol consumption above mandated amounts is primarily based upon the economic benefit derived by blenders, including benefits received from federal excise tax incentives. Therefore, the production of ethanol is made significantly more competitive by federal tax incentives. The federal excise tax incentive program, which is scheduled to expire on December 31, 2011, allows gasoline distributors who blend ethanol with gasoline to receive a federal excise tax rate reduction for each blended gallon they sell regardless of the blend rate. The current federal excise tax on gasoline is $0.184 per gallon, and is paid at the terminal by refiners and marketers. If the fuel is blended with ethanol, the blender may claim a $0.45 per gallon tax credit for each gallon of ethanol used in the mixture. The 2008 Farm Bill enacted into law reduced federal excise tax incentives from $0.51 per gallon in 2008 to $0.45 per gallon in 2009. The federal excise tax incentive program might not be renewed prior to its expiration on December 31, 2011, or if renewed, it may be renewed on terms significantly less favorable than current tax incentives. The elimination or significant reduction in the federal excise tax incentive program could reduce discretionary blending and have a material adverse effect on our results of operations and our financial condition.
 
Various studies have criticized the efficiency of ethanol in general, and corn-based ethanol in particular, which could lead to the reduction or repeal of incentives and tariffs that promote the use and domestic production of ethanol or otherwise negatively impact public perception and acceptance of ethanol as an alternative fuel.
 
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 and as potentially depleting water resources. Other studies have suggested that ethanol negatively impacts consumers by causing higher prices for dairy, meat and other foodstuffs from livestock that consume corn. If these views gain acceptance, support for existing measures promoting the use and domestic production of corn-based ethanol could decline, leading to a reduction or repeal of these measures. These views could also negatively impact public perception of the ethanol industry and acceptance of ethanol as a component for blending in transportation fuel.
 
Waivers or repeal of the national RFS’s minimum levels of renewable fuels included in gasoline could have a material adverse effect on our results of operations.
 
Shortly after passage of the Energy Independence and Security Act of 2007, which increased the minimum mandated required usage of ethanol, a Congressional sub-committee held hearings on the potential impact of the national RFS on commodity prices. While no action was taken by the sub-committee towards repeal of the national RFS, any attempt by Congress to re-visit, repeal or grant waivers of the national RFS could adversely affect demand for ethanol and could have a material adverse effect on our results of operations and financial condition.
 
While the Energy Independence and Security Act of 2007 imposes the national RFS, it does not mandate only the use of ethanol.
 
The Energy Independence and Security Act of 2007 imposes the national RFS, but does not mandate only the use of ethanol. While the RFA expects that ethanol should account for the largest share of renewable fuels produced and consumed under the national RFS, the national RFS is not limited to ethanol and also includes biodiesel and any other liquid fuel produced from biomass or biogas.

 
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The ethanol production and marketing industry is extremely competitive. Many of the significant competitors of the Pacific Ethanol Plants have greater production and financial resources than New PE Holdco does and one or more of these competitors could use their greater resources to gain market share at the expense of New PE Holdco. In addition, a number of New PE Holdco’s suppliers may circumvent the marketing services we provide to New PE Holdco, causing our sales and profitability to decline.
 
The ethanol production and marketing industry is extremely competitive. Many of New PE Holdco’s and our significant competitors in the ethanol production and marketing industry, including ADM, Valero and Green Plains Renewable Energy, have substantially greater production and/or financial resources than we do. As a result, our competitors may be able to compete more aggressively and sustain that competition over a longer period of time than New PE Holdco or we could. Successful competition will require a continued high level of investment in marketing and customer service and support. New PE Holdco’s and our limited resources relative to many significant competitors may cause New PE Holdco to fail to anticipate or respond adequately to new developments and other competitive pressures. This failure could reduce New PE Holdco’s and our competitiveness and cause a decline in market share, sales and profitability. Even if sufficient funds are available, we and New PE Holdco may not be able to make the modifications and improvements necessary to compete successfully.
 
We and New PE Holdco also face increasing competition from international suppliers. Currently, international suppliers produce ethanol primarily from sugar cane and have cost structures that are generally substantially lower than the cost structures of the Pacific Ethanol Plants. Any increase in domestic or foreign competition could cause the Pacific Ethanol Plants to reduce their prices and take other steps to compete effectively, which could adversely affect their and our results of operations and financial condition.
 
In addition, some of New PE Holdco’s and our suppliers are potential competitors and, especially if the price of ethanol reaches historically high levels, they may seek to capture additional profits by circumventing our marketing services in favor of selling directly to our customers. If one or more of our major suppliers, or numerous smaller suppliers, circumvent our marketing services, our sales and profitability may decline.
 
The high concentration of our sales within the ethanol marketing and production industry could result in a significant reduction in sales and negatively affect our profitability if demand for ethanol declines.
 
We expect to be completely focused on the marketing and production of ethanol and its co-products for the foreseeable future. We may be unable to shift our business focus away from the marketing and production of ethanol to other renewable fuels or competing products. Accordingly, an industry shift away from ethanol or the emergence of new competing products may reduce the demand for ethanol. A downturn in the demand for ethanol would likely materially and adversely affect our sales and profitability.
 
The volatility in the financial and commodities markets and sustained weakening of the economy could further significantly impact our business and financial condition and may limit our ability to raise additional capital.

 
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As widely reported, financial markets in the United States and the rest of the world have experienced extreme disruption, including, among other things, extreme volatility in securities and commodities prices, as well as severely diminished liquidity and credit availability. As a result, we believe that our ability to access capital markets and raise funds required for our operations may be severely restricted at a time when we need to do so, which could have a material adverse effect on our ability to meet our current and future funding requirements and on our ability to react to changing economic and business conditions. We are not able to predict the duration or severity of any current or future disruption in financial markets, fluctuations in the price of crude oil or other adverse economic conditions in the United States. However, if economic conditions worsen, it is likely that these factors would have a further adverse effect on our results of operations and future prospects and may limit our ability to raise additional capital.
 
In addition to the ethanol produced by the Pacific Ethanol Plants, we also depend on a small number of third-party suppliers for a significant portion of the total amount of ethanol that we sell. If any of these suppliers does not continue to supply us with ethanol in adequate amounts, we may be unable to satisfy the demands of our customers and our sales, profitability and relationships with our customers will be adversely affected.
 
In addition to the ethanol produced by the Pacific Ethanol Plants, we also depend on a small number of third-party suppliers for a significant portion of the ethanol that we sell. We expect to continue to depend for the foreseeable future upon a small number of third-party suppliers for a significant portion of the total amount of the ethanol that we sell. Our third-party suppliers are primarily located in the Midwestern United States. The delivery of ethanol from these suppliers is therefore subject to delays resulting from inclement weather and other conditions. If any of these suppliers is unable or declines for any reason to continue to supply us with ethanol in adequate amounts, we may be unable to replace that supplier and source other supplies of ethanol in a timely manner, or at all, to satisfy the demands of our customers. If this occurs, our sales, profitability and our relationships with our customers will be adversely affected.
 
We and New PE Holdco may be adversely affected by environmental, health and safety laws, regulations and liabilities.
 
We and New PE Holdco are subject to various federal, state and local environmental laws and regulations, 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 and the employees of the Pacific Ethanol Plants. In addition, some of these laws and regulations require the Pacific Ethanol Plants to operate under permits that are subject to renewal or modification. These laws, regulations and permits can often require expensive pollution control equipment or operational changes to limit actual or potential impacts to the environment. A violation of these laws and regulations or permit conditions can result in substantial fines, natural resource damages, criminal sanctions, permit revocations and/or facility shutdowns. In addition, we and the Pacific Ethanol Plants have made, and expect to make, significant capital expenditures on an ongoing basis to comply with increasingly stringent environmental laws, regulations and permits.
 
We and New PE Holdco may be liable for the investigation and cleanup of environmental contamination at each of the properties that New PE Holdco owns or that we operate, including the Pacific Ethanol Plants, and at off-site locations where we arrange for the disposal of hazardous substances. If these substances have been or are disposed of or released at sites that undergo investigation and/or remediation by regulatory agencies, we may be responsible under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or other environmental laws for all or part of the costs of investigation and/or remediation, and for damages to natural resources. We may also be subject to related claims by private parties alleging property damage and personal injury due to exposure to hazardous or other materials at or from those properties. Some of these matters may require us to expend significant amounts for investigation, cleanup or other costs.

 
21

 

 
In addition, new laws, new interpretations of existing laws, increased governmental enforcement of environmental laws or other developments could require us to make significant additional expenditures. Continued government and public emphasis on environmental issues can be expected to result in increased future investments for environmental controls at the Pacific Ethanol Plants. Present and future environmental laws and regulations, and interpretations of those laws and regulations, applicable to New PE Holdco’s and our operations, more vigorous enforcement policies and discovery of currently unknown conditions may require substantial expenditures that could have a material adverse effect on our results of operations and financial condition.
 
The hazards and risks associated with producing and transporting our products (including fires, natural disasters, explosions and abnormal pressures and blowouts) may also result in personal injury claims or damage to property and third parties. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. However, we could sustain losses for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. Events that result in significant personal injury or damage to our property or third parties or other losses that are not fully covered by insurance could have a material adverse effect on our results of operations and financial condition.
 
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 future success will depend on, among other factors, our ability to retain our current key personnel and attract and retain qualified future key personnel, particularly executive management. Failure to attract or retain key personnel could have a material adverse effect on our business and results of operations.
 
We depend on a small number of customers for the majority of our sales. A reduction in business from any of these customers could cause a significant decline in our overall sales and profitability.
 
The majority of our sales are generated from a small number of customers. During each of 2010 and 2009, sales to our two largest customers, each of whom accounted for 10% or more of our net sales, represented approximately 24% and 32%, respectively. We expect that we will continue to depend for the foreseeable future upon a small number of customers for a significant portion of our sales. Our agreements with these customers generally do not require them to purchase any specified amount of ethanol or dollar amount of sales or to make any purchases whatsoever. Therefore, in any future period, our sales generated from these customers, individually or in the aggregate, may not equal or exceed historical levels. If sales to any of these customers cease or decline, we may be unable to replace these sales with sales to either existing or new customers in a timely manner, or at all. A cessation or reduction of sales to one or more of these customers could cause a significant decline in our overall sales and profitability.
 
Our lack of long-term ethanol orders and commitments by our customers could lead to a rapid decline in our sales and profitability.
 
We cannot rely on long-term ethanol orders or commitments by our customers for protection from the negative financial effects of a decline in the demand for ethanol or a decline in the demand for our marketing services. The limited certainty of ethanol orders can make it difficult for us to forecast our sales and allocate our resources in a manner consistent with our actual sales. Moreover, our expense levels are based in part on our expectations of future sales and, if our expectations regarding future sales are inaccurate, we may be unable to reduce costs in a timely manner to adjust for sales shortfalls. Furthermore, because we depend on a small number of customers for a significant portion of our sales, the magnitude of the ramifications of these risks is greater than if our sales were less concentrated. As a result of our lack of long-term ethanol orders and commitments, we may experience a rapid decline in our sales and profitability.

 
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Risks Related to Ownership of our Common Stock
 
We have received a delisting notice from The NASDAQ Stock Market. Our common stock may be involuntarily delisted from trading on The NASDAQ Capital Market if we fail to regain compliance with the minimum closing bid price requirement of $1.00 per share. A delisting of our common stock is likely to reduce the liquidity of our common stock and may inhibit or preclude our ability to raise additional financing and may also materially and adversely impact our credit terms with our vendors.
 
The quantitative listing standards of The NASDAQ Stock Market, or NASDAQ, require, among other things, that listed companies maintain a minimum closing bid price of $1.00 per share. We failed to satisfy this threshold for 30 consecutive trading days and on June 30, 2010, we received a letter from NASDAQ indicating that the bid price of our common stock for the last 30 consecutive trading days had closed below the minimum $1.00 per share required for continued listing under NASDAQ Listing Rule 5550(a)(2). We were provided an initial period of 180 calendar days, or until December 27, 2010, during which to regain compliance. We failed to regain compliance by December 27, 2010 but, due to our transition from The NASDAQ Global Market to The NASDAQ Capital Market, we were provided a final additional period of 180 calendar days, or until June 27, 2011, during which to regain compliance. The letter states that the NASDAQ staff will provide written notification that we have achieved compliance if at any time before June 27, 2011, the bid price of our common stock closes at $1.00 per share or more for a minimum of 10 consecutive business days unless the NASDAQ staff exercises its discretion to extend this 10 day period. If we do not regain compliance by June 27, 2011, the NASDAQ staff will provide written notice that our common stock is subject to delisting. Given the increased market volatility arising in part from economic turmoil resulting from the ongoing credit crisis, the challenging environment in the biofuels industry and our lack of liquidity, we may be unable to regain compliance with the closing bid price requirement by June 27, 2011. A delisting of our common stock is likely to reduce the liquidity of our common stock and may inhibit or preclude our ability to raise additional financing and may also materially and adversely impact our credit terms with our vendors.
 
The conversion into shares of common stock of convertible securities, including the Convertible Notes and our Series B Cumulative Convertible Preferred Stock, and the exercise of outstanding options and warrants to purchase our common stock could substantially dilute your investment, impede our ability to obtain additional financing, and cause us to incur additional expenses.
 
The conversion into shares of common stock of our Convertible Notes and Series B Cumulative Convertible Preferred Stock, or Series B Preferred Stock, warrants to purchase our common stock, and outstanding options to acquire our common stock issued to employees, directors and others, could result in substantial dilution in the interests of our other stockholders. In addition, the terms on which we may obtain additional financing may be adversely affected by the existence and potentially dilutive impact of the Convertible Notes, Series B Preferred Stock, warrants and options. Moreover, holders of the Convertible Notes, Series B Preferred Stock, and certain warrants have registration rights with respect to the common stock underlying those securities, the registration of which will likely cause us to incur substantial expenses.
 
The voting power and value of your investment could decline if our Convertible Notes are converted and our Warrants are exercised at a reduced price due to our issuance of lower-priced shares or market declines which trigger rights of the holders of our Convertible Notes to receive additional shares of our common stock.

 
23

 

 
We have issued a significant amount of Convertible Notes and Warrants, the conversion or exercise of which could have a substantial negative impact on the price of our common stock and could result in a dramatic decrease in the value of your investment. The initial conversion price of our Convertible Notes is subject to market-price protection that may cause the conversion price of the Convertible Notes to be reduced in the event of a decline in the market price of our common stock. In addition, the conversion price of our Convertible Notes and the exercise price of the Warrants will be subject to downward anti-dilution adjustments in most cases, from time to time, if we issue securities at a purchase, exercise or conversion price that is less than the then-applicable conversion price of our outstanding Convertible Notes or exercise price of the Warrants. Consequently, the voting power and value of your investment in each of these events would decline if the Convertible Notes or the Warrants are converted or exercised for shares of our common stock at lower prices as a result of the declining market-price or sales of our securities are made below the conversion price of the Convertible Notes and/or the exercise price of the Warrants.
 
The market-price protection feature of our Convertible Notes could also allow the Convertible Notes to become convertible into a greatly increased number of additional shares of our common stock, particularly if a holder of the Convertible Notes sequentially converts portions of the Note into shares of our common stock at alternate conversion prices and resells those shares into the market. If a holder of the Convertible Notes sequentially converts portions of the Convertible Notes into shares of our common stock or if we issue shares of common stock in lieu of cash payments of principal and interest on the Convertible Notes, each at alternate conversion prices, and the holder of the Convertible Notes resells those shares into the market, then the market price of our common stock could decline due to the additional shares available in the market, particularly in the event of any thin trading volume of our common stock. Consequently, if a holder of the Convertible Notes repeatedly converts portions of the Convertible Notes or we repeatedly issue shares of common stock in lieu of cash payments of principal and interest on the Convertible Notes at alternate conversion prices and then the holder resells those underlying shares into the market, a continuous downward spiral of the market price of our common stock could occur that would benefit a holder of our Convertible Notes at the expense of other existing or potential holders of our common stock, potentially creating a divergence of interests between a holder of our Convertible Notes and investors who purchase the shares of common stock resold by a holder of the Convertible Notes following conversion of the Convertible Notes.
 
The market price of our common stock and the value of your investment could substantially decline if our Convertible Notes or Series B Preferred Stock are converted into shares of our common stock, if we issue shares of our common stock in payment of principal and interest on our Convertible Notes and if our options and warrants are exercised for shares of our common stock and all of these shares of common stock are resold into the market, or if a perception exists that a substantial number of shares will be issued upon conversion of our Convertible Notes or Series B Preferred Stock, upon the payment of principal and interest on the Convertible Notes or upon exercise of our warrants or options and then resold into the market.
 
If the conversion prices at which the principal balances of the Convertible Notes or Series B Preferred Stock are converted, the issuance prices at which shares of common stock in payment of principal and interest on the Convertible Notes are issued, and the exercise prices at which our warrants and options are exercised are lower than the price at which you made your investment, immediate dilution of the value of your investment will occur. In addition, sales of a substantial number of shares of common stock issued upon conversion of the Convertible Notes or Series B Preferred Stock, in lieu of cash payments of principal and interest on the Convertible Notes and upon exercise of our warrants and options, or even the perception that these sales could occur, could adversely affect the market price of our common stock, which would mean that the Convertible Notes would be convertible into an increased number of shares of our common stock in cases where, as described elsewhere in these Risk Factors, the conversion price is based upon a discount from the market price of our common stock. You could, therefore, experience a substantial decline in the value of your investment as a result of both the actual and potential conversion of our outstanding Convertible Notes or Series B Preferred Stock, issuance of shares of common stock in lieu of cash payments of principal and interest on the Convertible Notes and exercise of our outstanding warrants or options.

 
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The issuance of shares of common stock upon the conversion of the Convertible Notes or Series B Preferred Stock, upon the payment of principal and interest on the Convertible Notes and upon the exercise of outstanding options and warrants could result in a change of control of Pacific Ethanol.
 
As of March 31, 2011, we had outstanding options, warrants, Convertible Notes (including shares issuable as interest in lieu of cash payments calculated at an interest rate of 8% per annum, compounded monthly, from the closing date of the issuance of the Initial Convertible Notes through the maturity date of the Convertible Notes) and Series B Preferred Stock that were exercisable for or convertible into approximately 85,389,291 shares of common stock based upon an assumed conversion price of $0.57 for the Convertible Notes and existing exercise prices for the warrants and options. In addition, as discussed elsewhere in these Risk Factors, the number of shares exercisable under outstanding warrants and convertible under outstanding Convertible Notes and Series B Preferred Stock may be subject to increase in the event of our future issuance of securities or a decline in the market price of our common stock. A change of control of Pacific Ethanol could occur if a significant number of shares are issued to the holders of our outstanding options, warrants, Convertible Notes or Series B Preferred Stock. If a change of control occurs, then the stockholders who historically have controlled Pacific Ethanol would no longer have the ability to exert significant control over matters that could include the election of our directors, changes in the size and composition of our board of directors, and mergers and other business combinations involving Pacific Ethanol. Instead, one or more other stockholders could gain the ability to exert this type of control and may also, through control of our board of directors and voting power, be able to control a number of decisions, including decisions regarding the qualification and appointment of officers, dividend policy, access to capital (including borrowing from third-party lenders and the issuance of additional equity securities), and the acquisition or disposition of assets.
 
As a result of our issuance of shares of Series B Preferred Stock, our common stockholders may experience numerous negative effects and most of the rights of our common stockholders will be subordinate to the rights of the holders of our Series B Preferred Stock.
 
As a result of our issuance of shares of Series B Preferred Stock, our common stockholders may experience numerous negative effects, including dilution from any dividends paid in preferred stock and antidilution adjustments. In addition, rights in favor of the holders of our Series B Preferred Stock include seniority in liquidation and dividend preferences; substantial voting rights; and numerous protective provisions. Also, our outstanding Series B Preferred Stock could have the effect of delaying, deferring and discouraging another party from acquiring control of Pacific Ethanol.
 
Our stock price is highly volatile, which could result in substantial losses for investors purchasing shares of our common stock and in litigation against us.
 
The market price of our common stock has fluctuated significantly in the past and may continue to fluctuate significantly in the future. The market price of our common stock may continue to fluctuate in response to one or more of the following factors, many of which are beyond our control:

 
·
our ability to maintain contracts that are critical to our operations, including the asset management agreement with the Plant Owners that provide us with the ability to operate the Pacific Ethanol Plants;
 
·
our ability to obtain and maintain normal terms with vendors and service providers;
 
·
fluctuations in the market price of ethanol and its co-products;

 
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·
the volume and timing of the receipt of orders for ethanol from major customers;
 
·
competitive pricing pressures;
 
·
our ability to produce, sell and deliver ethanol on a cost-effective and timely basis;
 
·
the introduction and announcement of one or more new alternatives to ethanol by our competitors;
 
·
changes in market valuations of similar companies;
 
·
stock market price and volume fluctuations generally;
 
·
the relative small public float of our common stock;
 
·
regulatory developments or increased enforcement;
 
·
fluctuations in our quarterly or annual operating results;
 
·
additions or departures of key personnel;
 
·
our inability to obtain financing; and
 
·
future sales of our common stock or other securities.
 
Furthermore, we believe that the economic conditions in California and other Western states, as well as the United States as a whole, could have a negative impact on our results of operations. Demand for ethanol could also be adversely affected by a slow-down in overall demand for oxygenate and gasoline additive products. The levels of our ethanol production and purchases for resale will be based upon forecasted demand. Accordingly, any inaccuracy in forecasting anticipated revenues and expenses could adversely affect our business. The failure to receive anticipated orders or to complete delivery in any quarterly period could adversely affect our results of operations for that period. Quarterly results are not necessarily indicative of future performance for any particular period, and we may not experience revenue growth or profitability on a quarterly or an annual basis.
 
The price at which you purchase shares of our common stock may not be indicative of the price that will prevail in the trading market. You may be unable to sell your shares of common stock at or above your purchase price, which may result in substantial losses to you and which may include the complete loss of your investment. In the past, securities class action litigation has often been brought against a company following periods of high stock price volatility. We may be the target of similar litigation in the future. Securities litigation could result in substantial costs and divert management’s attention and our resources away from our business.
 
Any of the risks described above could have a material adverse effect on our sales and profitability and the price of our common stock.
 
Item 1B.
Unresolved Staff Comments.
 
None.
 
Item 2.
Properties.
 
Our corporate headquarters, located in Sacramento, California, consists of a 10,000 square foot office under a lease expiring in 2013. The location of the Pacific Ethanol Plants are in Madera, California, at which a 137 acre facility is located; Boardman, Oregon, at which a 25 acre facility is located; Burley, Idaho, at which a 160 acre facility is located; and Stockton, California, at which a 30 acre facility is located. The properties in Madera, California and Burley, Idaho are owned by the Plant Owners. The properties in Boardman, Oregon and Stockton, California are leased by the Plant Owners under leases expiring in 2026 and 2022, respectively. See “Business—Production Facilities.”
 
 
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Item 3. 
 Legal Proceedings.
 
We are subject to legal proceedings, claims and litigation arising in the ordinary course of business. While the amounts claimed may be substantial, the ultimate liability cannot presently be determined because of considerable uncertainties that exist. Therefore, it is possible that the outcome of those legal proceedings, claims and litigation could adversely affect our quarterly or annual operating results or cash flows when resolved in a future period. However, based on facts currently available, management believes such matters will not materially and adversely affect our financial position, results of operations or cash flows.
 
Delta-T Corporation
 
On August 18, 2008, Delta-T Corporation filed suit in the United States District Court for the Eastern District of Virginia, or the First Virginia Federal Court case, naming Pacific Ethanol, Inc. as a defendant, along with its former subsidiaries Pacific Ethanol Stockton, LLC, Pacific Ethanol Imperial, LLC, Pacific Ethanol Columbia, LLC, Pacific Ethanol Magic Valley, LLC and Pacific Ethanol Madera, LLC. The suit alleged breaches of the parties’ Engineering, Procurement and Technology License Agreements, breaches of a subsequent term sheet and letter agreement and breaches of indemnity obligations. The complaint sought specified contract damages of approximately $6.5 million, along with other unspecified damages. All of the defendants moved to dismiss the First Virginia Federal Court case for lack of personal jurisdiction and on the ground that all disputes between the parties must be resolved through binding arbitration, and, in the alternative, moved to stay the First Virginia Federal Court case pending arbitration. In January 2009, these motions were granted by the Court, compelling the case to arbitration with the American Arbitration Association, or AAA. By letter dated June 10, 2009, the AAA notified the parties to the arbitration that the matter was automatically stayed as a result of the Chapter 11 Filings.
 
On March 18, 2009, Delta-T Corporation filed a cross-complaint against Pacific Ethanol, Inc. and Pacific Ethanol Imperial, LLC in the Superior Court of the State of California in and for the County of Imperial. The cross-complaint arose out of a suit by OneSource Distributors, LLC against Delta-T Corporation. On March 31, 2009, Delta-T Corporation and Bateman Litwin N.V, a foreign corporation, filed a third-party complaint in the United States District Court for the District of Minnesota naming Pacific Ethanol, Inc. and Pacific Ethanol Imperial, LLC as defendants. The third-party complaint arose out of a suit by Campbell-Sevey, Inc. against Delta-T Corporation. On April 6, 2009, Delta-T Corporation filed a cross-complaint against Pacific Ethanol, Inc. and Pacific Ethanol Imperial, LLC in the Superior Court of the State of California in and for the County of Imperial. The cross-complaint arose out of a suit by GEA Westfalia Separator, Inc. against Delta-T Corporation. Each of these actions allegedly related to the aforementioned Engineering, Procurement and Technology License Agreements and Delta-T Corporation’s performance of services thereunder. The third-party suit and the cross-complaints asserted many of the factual allegations in the First Virginia Federal Court case and sought unspecified damages.
 
On June 19, 2009, Delta-T Corporation filed suit in the United States District Court for the Eastern District of Virginia, or the Second Virginia Federal Court case, naming Pacific Ethanol, Inc. as the sole defendant. The suit alleged breaches of the parties’ Engineering, Procurement and Technology License Agreements, breaches of a subsequent term sheet and letter agreement, and breaches of indemnity obligations. The complaint sought specified contract damages of approximately $6.5 million, along with other unspecified damages.

 
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In connection with the Chapter 11 Filings, the Plant Owners moved the Bankruptcy Court to enter a preliminary injunction in favor of the Plant Owners and Pacific Ethanol, Inc. staying and enjoining all of the aforementioned litigation and arbitration proceedings commenced by Delta-T Corporation. On August 6, 2009, the Bankruptcy Court ordered that the litigation and arbitration proceedings commenced by Delta-T Corporation be stayed and enjoined until September 21, 2009 or further order of the court, and that the Plant Owners, Pacific Ethanol, Inc. and Delta-T Corporation complete mediation by September 20, 2009 for purposes of settling all disputes between the parties. Following mediation, the parties reached an agreement under which a stipulated order was entered in the Bankruptcy Court on September 21, 2009, providing for a complete mutual release and settlement of any and all claims between Delta-T Corporation and the Plant Owners, a complete reservation of rights as between Pacific Ethanol, Inc. and Delta-T Corporation, and a stay of all proceedings by Delta-T Corporation against Pacific Ethanol, Inc. until December 31, 2009.
 
On March 1, 2010, Delta-T Corporation resumed active litigation of the Second Virginia Federal Court case by filing a motion for entry of a default judgment. Also on March 1, 2010, Pacific Ethanol, Inc. filed a motion for extension of time for its first appearance in the Second Virginia Federal Court case and also filed a motion to dismiss Delta-T Corporation’s complaint based on the mandatory arbitration clause in the parties’ contracts, and alternatively to stay proceedings during the pendency of arbitration. These motions were argued on March 31, 2010. The Court ruled on the motions in May 2010, denying Delta-T Corporation’s motion for entry of a default judgment, and compelling the case to arbitration with the AAA. 
 
On May 25, 2010, Delta-T Corporation filed a Voluntary Petition in the Bankruptcy Court for the Eastern District of Virginia under Chapter 7 of the Bankruptcy Code. We believe that Delta-T Corporation has liquidated its assets and abandoned its claims against us.
 
Barry Spiegel – State Court Action
 
On December 22, 2005, Barry J. Spiegel, a former shareholder and director of Accessity, filed a complaint in the Circuit Court of the 17th Judicial District in and for Broward County, Florida (Case No. 05018512), or the State Court Action, against Barry Siegel, Philip Kart, Kenneth Friedman and Bruce Udell, or collectively, the Individual Defendants. Messrs. Udell and Friedman are former directors of Accessity and Pacific Ethanol. Mr. Kart is a former executive officer of Accessity and Pacific Ethanol. Mr. Siegel is a former director and former executive officer of Accessity and Pacific Ethanol.
 
The State Court Action relates to the Share Exchange Transaction and purports to state the following five counts against the Individual Defendants: (i) breach of fiduciary duty, (ii) violation of the Florida Deceptive and Unfair Trade Practices Act, (iii) conspiracy to defraud, (iv) fraud, and (v) violation of Florida’s Securities and Investor Protection Act. Mr. Spiegel based his claims on allegations that the actions of the Individual Defendants in approving the Share Exchange Transaction caused the value of his Accessity common stock to diminish and is seeking approximately $22.0 million in damages. On March 8, 2006, the Individual Defendants filed a motion to dismiss the State Court Action. Mr. Spiegel filed his response in opposition on May 30, 2006. The court granted the motion to dismiss by Order dated December 1, 2006, on the grounds that, among other things, Mr. Spiegel failed to bring his claims as a derivative action.
 
On February 9, 2007, Mr. Spiegel filed an amended complaint which purports to state the following five counts: (i) breach of fiduciary duty, (ii) fraudulent inducement, (iii) violation of Florida’s Securities and Investor Protection Act, (iv) fraudulent concealment, and (v) breach of fiduciary duty of disclosure. The amended complaint included Pacific Ethanol as a defendant. On March 30, 2007, Pacific Ethanol filed a motion to dismiss the amended complaint. Before the court could decide that motion, on June 4, 2007, Mr. Spiegel amended his complaint, which purports to state two counts: (a) breach of fiduciary duty, and (b) fraudulent inducement. The first count is alleged against the Individual Defendants and the second count is alleged against the Individual Defendants and Pacific Ethanol. The amended complaint was, however, voluntarily dismissed on August 27, 2007, by Mr. Spiegel as to Pacific Ethanol.

 
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Mr. Spiegel sought and obtained leave to file another amended complaint on June 25, 2009, which renewed his case against Pacific Ethanol, and named three additional individual defendants, and asserted the following three counts: (x) breach of fiduciary duty, (y) fraudulent inducement, and (z) aiding and abetting breach of fiduciary duty. The first two counts are alleged solely against the Individual Defendants. With respect to the third count, Mr. Spiegel has named Pacific Ethanol California, Inc. (formerly known as Pacific Ethanol, Inc.), as well as William L. Jones, Neil M. Koehler and Ryan W. Turner. Messrs. Jones and Turner are directors of Pacific Ethanol. Mr. Turner is a former officer of Pacific Ethanol. Mr. Koehler is a director and officer of Pacific Ethanol. Pacific Ethanol and the Individual Defendants filed a motion to dismiss the count against them, and the court granted the motion. Plaintiff then filed another amended complaint, and Defendants once again moved to dismiss. The motion was heard on February 17, 2010, and the court, on March 22, 2010, denied the motion requiring Pacific Ethanol and Messrs. Jones, Koehler and Turner to answer the complaint and respond to discovery requests.
 
Barry Spiegel – Federal Court Action
 
On December 28, 2006, Barry J. Spiegel, filed a complaint in the United States District Court, Southern District of Florida (Case No. 06-61848), or the Federal Court Action, against the Individual Defendants and Pacific Ethanol. The Federal Court Action relates to the Share Exchange Transaction and purports to state the following three counts: (i) violations of Section 14(a) of the Securities Exchange Act of 1934, as amended, or Exchange Act, and SEC Rule 14a-9 promulgated thereunder, (ii) violations of Section 10(b) of the Exchange Act and Rule 10b-5 promulgated thereunder, and (iii) violation of Section 20(A) of the Exchange Act. The first two counts are alleged against the Individual Defendants and Pacific Ethanol and the third count is alleged solely against the Individual Defendants. Mr. Spiegel bases his claims on, among other things, allegations that the actions of the Individual Defendants and Pacific Ethanol in connection with the Share Exchange Transaction resulted in a share exchange ratio that was unfair and resulted in the preparation of a proxy statement seeking shareholder approval of the Share Exchange Transaction that contained material misrepresentations and omissions. Mr. Spiegel is seeking in excess of $15.0 million in damages.
 
Mr. Spiegel amended the Federal Court Action on March 5, 2007, and Pacific Ethanol and the Individual Defendants filed a Motion to Dismiss the amended pleading on April 23, 2007. Plaintiff Spiegel sought to stay his own federal case, but the Motion was denied on July 17, 2007. The court required Mr. Spiegel to respond to our Motion to Dismiss. On January 15, 2008, the court rendered an Order dismissing the claims under Section 14(a) of the Exchange Act on the basis that they were time barred and that more facts were needed for the claims under Section 10(b) of the Exchange Act. The court, however, stayed the entire case pending resolution of the State Court Action.
 
Item 4.  
(Removed and Reserved).
 
Not applicable.

 
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PART II
 
Item 5.
Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
 
Market Information
 
Our common stock has traded on The NASDAQ Capital Market under the symbol “PEIX” since May 3, 2010. Between October 10, 2005 and May 3, 2010, our common stock traded on The NASDAQ Global Market (formerly, The NASDAQ National Market). The table below shows, for each fiscal quarter indicated, the high and low sales prices for shares of our common stock. This information has been obtained from NASDAQ. The prices shown reflect inter-dealer prices, without retail mark-up, mark-down or commission, and may not necessarily represent actual transactions.

 
Price Range
 
High
Low
Year Ended December 31, 2010:
   
First Quarter (January 1 – March 31)
$    2.75
$    0.71
Second Quarter (April 1 – June 30)
$    1.60
$    0.45
Third Quarter (July 1 – September 30)
$    1.25
$    0.37
Fourth Quarter (October 1 – December 31)
$    1.14
$    0.58
     
Year Ended December 31, 2009:
   
First Quarter
$    0.68
$    0.20
Second Quarter
$    0.84
$    0.28
Third Quarter
$    0.67
$    0.30
Fourth Quarter
$    1.06
$    0.35
 
Security Holders
 
As of March 31, 2011, we had 108,430,832 shares of common stock outstanding and held of record by approximately 500 stockholders. These holders of record include depositories that hold shares of stock for brokerage firms which, in turn, hold shares of stock for numerous beneficial owners. On March 31, 2011, the closing sale price of our common stock on The NASDAQ Capital Market was $0.63 per share.
 
Dividend Policy
 
We have never paid cash dividends on our common stock and do not intend to pay cash dividends on our common stock in the foreseeable future. We anticipate that we will retain any earnings for use in the continued development of our business.
 
Our current and future debt financing arrangements may limit or prevent cash distributions from our subsidiaries to us, depending upon the achievement of certain financial and other operating conditions and our ability to properly service our debt, thereby limiting or preventing us from paying cash dividends. In addition, the holders of our outstanding Series B Preferred Stock are entitled to dividends of 7% per annum, payable quarterly, none of which have been paid for the years ended December 31, 2010 and 2009 or thereafter through the filing of this report. Accumulated and unpaid dividends in respect of our preferred stock must be paid prior to the payment of any dividends to our common stockholders.
 
Recent Sales of Unregistered Securities
 
None.

 
30

 

 
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
 
We granted to certain employees and directors shares of restricted stock under our 2006 Stock Incentive Plan pursuant to Restricted Stock Agreements dated and effective as of their respective grant dates by and between us and those employees and directors.
 
We were obligated to withhold minimum withholding tax amounts with respect to vested shares of restricted stock and upon future vesting of shares of restricted stock granted to our employees. Each employee was entitled to pay the minimum withholding tax amounts to us in cash or to elect to have us withhold a vested amount of shares of restricted stock having a value equivalent to our minimum withholding tax requirements, thereby reducing the number of shares of vested restricted stock that the employee ultimately receives. If an employee failed to timely make such election, we automatically withheld the necessary shares of vested restricted stock.
 
In October 2010, in connection with satisfying our withholding requirements, we withheld an aggregate of 66,935 shares of our common stock and remitted a cash payment to cover the minimum withholding tax amounts, thereby effectively repurchasing from the employees the 66,935 shares of common stock at a deemed purchase price equal to $0.95 per share for an aggregate purchase price of $64,258.
 
Item 6. 
 Selected Financial Data.
 
Not applicable.
 
Item 7.  
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes to consolidated financial statements included elsewhere in this report. This report and our consolidated financial statements and notes to consolidated financial statements contain forward-looking statements, which generally include the plans and objectives of management for future operations, including plans and objectives relating to our future economic performance and our current beliefs regarding revenues we might generate and profits we might earn if we are successful in implementing our business and growth strategies. The forward-looking statements and associated risks may include, relate to or be qualified by other important factors, including:

 
·
fluctuations in the market price of ethanol and its co-products;
 
·
the projected growth or contraction in the ethanol and co-product markets in which we operate;
 
·
our strategies for expanding, maintaining or contracting our presence in these markets;
 
·
our ability to successfully manage and operate third party ethanol production facilities;
 
·
anticipated trends in our financial condition and results of operations; and
 
·
our ability to distinguish ourselves from our current and future competitors.
 
You are cautioned not to place undue reliance on any forward-looking statements, which speak only as of the date of this report, or in the case of a document incorporated by reference, as of the date of that document. We do not undertake to update, revise or correct any forward-looking statements, except as required by law.
 
Any of the factors described immediately above or in the “Risk Factors” section above could cause our financial results, including our net income or loss or growth in net income or loss to differ materially from prior results, which in turn could, among other things, cause the price of our common stock to fluctuate substantially.

 
31

 

 
Overview
 
We are the leading marketer and producer of low carbon renewable fuels in the Western United States.
 
Since our inception in 2005, we have conducted ethanol marketing operations through our subsidiary, Kinergy Marketing, LLC, or Kinergy, through which we market and sell ethanol produced by third parties. In 2006, we began constructing the first of our four then wholly-owned ethanol production facilities, or Pacific Ethanol Plants, and were continuously engaged in plant construction until the fourth facility was completed in 2008. We funded, and until recently directly operated, the Pacific Ethanol Plants through a subsidiary holding company and four other indirect subsidiaries, or Plant Owners.
 
In late 2008 and early 2009, we idled production at three of the Pacific Ethanol Plants due to adverse market conditions and lack of adequate working capital. Adverse market conditions and our financial constraints continued, resulting in an inability to meet our debt service requirements, and in May 2009, the Plant Owners each filed voluntary petitions for relief under chapter 11 of Title 11 of the United States Code, or Bankruptcy Code, in the United States Bankruptcy Court for the District of Delaware, or Bankruptcy Court.
 
On March 26, 2010, the Plant Owners filed a joint plan of reorganization with the Bankruptcy Court, which was structured in cooperation with a number of the Plant Owners’ secured lenders. On June 29, 2010, or the Effective Date, the Plant Owners declared effective their amended joint plan of reorganization, or the Plan, and emerged from bankruptcy. Under the Plan, on the Effective Date, all of the ownership interests in the Plant Owners were transferred to a newly-formed holding company, New PE Holdco, LLC, or New PE Holdco, wholly-owned as of that date by some of the prepetition lenders and new lenders of the Plant Owners. As a result, the Pacific Ethanol Plants are now wholly-owned by New PE Holdco.
 
On October 6, 2010, we raised $35.0 million through the issuance of $35.0 million in principal amount of senior convertible notes, or Initial Convertible Notes, and warrants to purchase an aggregate of 20,588,235 shares of our common stock, or Initial Warrants. See “—Liquidity and Capital Resources—Convertible Notes.” On that same date we sold our 42% interest in Front Range Energy, LLC, or Front Range, for $18.5 million in cash, paid off our outstanding indebtedness to Lyles United, LLC and Lyles Mechanical Co., or collectively Lyles, in the aggregate amount of approximately $17.0 million and purchased a 20% ownership interest, which represents the single largest interest, in New PE Holdco for an aggregate purchase price of $23.3 million.
 
On January 7, 2011, we issued $35.0 million in principal amount of senior convertible notes, or Convertible Notes, in exchange for the Initial Convertible Notes and issued warrants to purchase an aggregate of 20,588,235 shares of our common stock, or Warrants, in exchange for the Initial Warrants. See “—Liquidity and Capital Resources—Convertible Notes.”
 
We currently manage the production of ethanol at the Pacific Ethanol Plants under the terms of an asset management agreement with the Plant Owners. We also market ethanol and its co-products, including wet distillers grain, or WDG, produced by the Pacific Ethanol Plants under the terms of separate marketing agreements with the Plant Owners whose facilities are operational. We also market ethanol and its co-products to other third parties, and provide transportation, storage and delivery of ethanol through third-party service providers in the Western United States, primarily in California, Nevada, Arizona, Oregon, Colorado, Idaho and Washington.
 
We have extensive customer relationships throughout the Western United States and extensive supplier relationships throughout the Western and Midwestern United States. Our customers are integrated oil companies and gasoline marketers who blend ethanol into gasoline. We supply ethanol to our customers either from the Pacific Ethanol Plants located within the regions we serve, or with ethanol procured in bulk from other producers. In some cases, we have marketing agreements with ethanol producers to market all of the output of their facilities. Additionally, we have customers who purchase our co-products for animal feed and other uses.

 
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The Pacific Ethanol Plants produce ethanol and its co-products and are comprised of the four facilities described immediately below, three of which are currently operational. If market conditions continue to improve, we may resume operations at the Madera, California facility, subject to the approval of New PE Holdco.
 
 
Facility Name
 
Facility Location
Estimated Annual
Capacity
(gallons)
Current
Operating
Status
Magic Valley
Burley, ID
60,000,000
Operating
Columbia
Boardman, OR
40,000,000
Operating
Stockton
Stockton, CA
60,000,000
Operating
Madera
Madera, CA
40,000,000
Idled
 
Under the asset management agreement and marketing agreements, we manage the production and operations of the Pacific Ethanol Plants, market their ethanol and WDG and earn fees as follows:
 
 
·
ethanol marketing fees of approximately 1% of the net sales price;
 
 
·
corn procurement and handling fees of approximately $2.00 per ton;
 
 
·
WDG fees of approximately the greater of 5% of the third-party purchase price or $2.00 per ton; and
 
 
·
asset management fees of $75,000 per month for each operating facility and $40,000 per month for each idled facility.
 
We intend to maintain our position as the leading marketer and producer of low-carbon renewable fuels in the Western United States, in part by expanding our relationships with customers and third-party ethanol producers to market higher volumes of ethanol and by expanding the market for ethanol by continuing to work with state governments to encourage the adoption of policies and standards that promote ethanol as a fuel additive and transportation fuel. Further, we may seek to provide management services for other third-party ethanol production facilities in the Western United States.
 
Financial Performance Summary
 
Our net sales increased by 4%, or $11.7 million, to $328.3 million in 2010 from $316.6 million in 2009. Our net income increased by $382.1 million to $73.9 million in 2010 from a net loss of $308.2 million in 2009.
 
Factors that contributed to our results of operations for 2010 include:
 
 
·
Net sales. The increase in our net sales in 2010 as compared to 2009 was primarily due to the following combination of factors:
 
 
o
Higher sales volumes. Total volume of ethanol sold increased by 57% to 271.6 million gallons in 2010 from 172.7 million gallons in 2009. This increase in sales volume is primarily due to an increase in third party gallons sold, partially offset by decreased gallons sold from our ethanol production facilities. In 2010, gallons associated with Front Range were included in third party gallons sold, whereas in 2009, those gallons were included in gallons sold from our ethanol production facilities due to our deconsolidation of Front Range in 2010, as described below. Further, in 2010, two of the four Pacific Ethanol Plants were operating most of the year, whereas in 2009, only one Pacific Ethanol Plant was operating most of the year; and

 
33

 

 
 
o
Higher ethanol prices. Our average sales price of ethanol increased 9% to $1.96 per gallon in 2010 as compared to $1.80 per gallon in 2009.
 
 
·
Gross margin. Our gross margin increased to negative 0.2% for 2010 from negative 7.0% for 2009. The improvement in gross margin was a result of higher ethanol prices and lower depreciation expense in 2010, which were partially offset by an increase in corn costs. Depreciation was $8.0 million for 2010 as compared to $33.3 million for 2009. Our average price of corn increased by 8.8% to $4.33 per bushel in 2010 from $3.98 per bushel in 2009.
 
 
·
Selling, general and administrative expenses. Our selling, general and administrative expenses, or SG&A, decreased by $8.5 million to $13.0 million in 2010 as compared to $21.5 million in 2009 primarily as a result of decreases in professional fees, SG&A associated with Front Range, payroll and benefits, and other corporate expenses, which were partially offset by increases in bad debt expense and noncash compensation expense.
 
 
·
Impairments. We incurred no impairment charges for 2010 as compared to $252.4 million for 2009. In 2009, we recognized $252.4 million in asset impairments primarily related to the Pacific Ethanol Plants. Of the $252.4 million in asset impairments, $2.2 million related to impairment of the assets of our Imperial Valley facility prior to their disposal.
 
 
·
Loss on investment in Front Range. We sold our interest in Front Range in 2010 resulting in a loss of $12.1 million.
 
 
·
Loss on extinguishment of debt. We extinguished certain outstanding debt in 2010 in exchange for shares of our common stock. These transactions resulted in a loss of $2.2 million.
 
 
·
Gain from write-off of liabilities. We had no gain from the write-off of liabilities for 2010 as compared to a gain of $14.2 million in 2009. The gain in 2009 resulted from a write-off of liabilities related to our Imperial Valley facility.
 
 
·
Fair value adjustments on convertible notes and warrants. We issued convertible notes and warrants in 2010 for $35.0 million in cash. These instruments are recorded at fair value, resulting in a charge of $11.7 million in 2010.
 
 
·
Interest expense. Our interest expense decreased by $7.5 million to $6.3 million in 2010 from $13.8 million in 2009. This decrease is primarily due to restructuring and removal of the Plant Owners’ prepetition debt as well as certain other indebtedness that was extinguished during 2010.
 
 
·
Other income (expense). Our other income (expense) increased by $2.0 million to $0.3 million in 2010 from other expense of $1.7 million in 2009. This increase is primarily due to a gain of $1.6 million associated with our purchase of a 20% ownership interest in New PE Holdco.

 
34

 

 
 
·
Reorganization costs. Our reorganization costs decreased by $7.4 million to $4.2 million in 2010 from $11.6 million in 2009. This decrease is due to the wind down in 2010 of the Plant Owners’ bankruptcy proceedings that began in 2009.
 
 
·
Gain from bankruptcy exit. On June 29, 2010, the Plant Owners exited from bankruptcy, resulting in the removal of $119.4 million in net liabilities from our balance sheet. This amount was recorded as a gain in 2010.
 
Sales and Margins
 
Over the past four years, our sales mix has shifted significantly. We have generated sales by marketing ethanol produced by third parties and have also generated sales by producing our own ethanol. Our sales were initially generated solely through our marketing operations. Upon completion of the first of the Pacific Ethanol Plants, our sales included substantial sales generated from producing our own ethanol. We continue to generate sales through our marketing operations and also generate sales as a producer through our 20% ownership interest in New PE Holdco.
 
Our production facility cost structure also changed throughout the past four years as the Pacific Ethanol Plants were built and commenced operations, then later filed for bankruptcy protection, subsequently emerged from bankruptcy, and are now minority owned indirectly by us through our 20% ownership interest in New PE Holdco.
 
The shift in our sales mix greatly altered our dependency on certain market conditions from that based primarily on the market price of ethanol to that based significantly on the cost of corn, the principal input commodity for our production of ethanol. Accordingly, our profitability is dependent on the market price of ethanol and the cost of corn.
 
Average ethanol sales prices increased in 2010 as compared to 2009. The average Chicago Board of Trade, or CBOT, ethanol price increased by 8% to $1.83 in 2010 from $1.70 in 2009. The increase in the prevailing market price of ethanol was primarily due to the increase in crude oil prices in 2010.
 
Average corn prices also increased in 2010 as compared to 2009. Specifically, the average CBOT corn price increased by 15% in 2010 as compared to 2009. The increase in the prevailing market price of corn was the primary cause of the increase in our average corn price. The average CBOT corn price increased to $4.29 for 2010 from $3.74 for 2009.
 
We have three principal methods of selling ethanol: as a merchant, as a producer and as an agent. See “—Critical Accounting Policies—Revenue Recognition” below.
 
When acting as a merchant or as a producer, we generally enter into sales contracts to ship ethanol to a customer’s desired location. We support these sales contracts through purchase contracts with several third-party suppliers or through our own production. We manage the necessary logistics to deliver ethanol to our customers either directly from a third-party supplier or from our inventory via truck or rail. Our sales as a merchant or as a producer expose us to price risks resulting from potential fluctuations in the market price of ethanol and corn. Our exposure varies depending on the magnitude of our sales and purchase commitments compared to the magnitude of our existing inventory, as well as the pricing terms—such as market index or fixed pricing—of our contracts. We seek to mitigate our exposure to price risks by implementing appropriate risk management strategies.

 
35

 

 
When acting as an agent for third-party suppliers, we conduct back-to-back purchases and sales in which we match ethanol purchase and sale contracts of like quantities and delivery periods. When acting in this capacity, we receive a predetermined service fee and have little or no exposure to price risks resulting from potential fluctuations in the market price of ethanol.
 
We believe that our gross profit margins primarily depend on five key factors:
 
 
·
the market price of ethanol, which we believe will be impacted by the degree of competition in the ethanol market, the price of gasoline and related petroleum products, and government regulation, including tax incentives;
 
 
·
the market price of key production input commodities, including corn and natural gas;
 
 
·
the market price of WDG;
 
 
·
our ability to anticipate trends in the market price of ethanol, WDG, and key input commodities and implement appropriate risk management and opportunistic strategies; and
 
 
·
the proportion of our sales of ethanol produced at the Pacific Ethanol Plants to our sales of ethanol produced by unrelated third-parties.
 
We seek to optimize our gross profit margins by anticipating the factors above and, when resources are available, implementing hedging transactions and taking other actions designed to limit risk and address these factors. For example, we may seek to decrease inventory levels in anticipation of declining ethanol prices and increase inventory levels in anticipation of increasing ethanol prices. We may also seek to alter our proportion or timing, or both, of purchase and sales commitments.
 
Our limited resources to act upon the anticipated factors described above and/or our inability to anticipate these factors or their relative importance, and adverse movements in the factors themselves, could result in declining or even negative gross profit margins over certain periods of time. Our ability to anticipate these factors or favorable movements in these factors may enable us to generate above-average gross profit margins. However, given the difficulty associated with successfully forecasting any of these factors, we are unable to estimate our future gross profit margins.
 
Results of Operations
 
Accounting for the Results of New PE Holdco
 
Our consolidated financial statements include the financial statements of the Plant Owners for all periods except for the three months ended September 30, 2010. On June 29, 2010, the Plant Owners emerged from bankruptcy, and the ownership of the Plant Owners was transferred to New PE Holdco. Accordingly, for the three months ended September 30, 2010, we did not consolidate the Plant Owners’ financial results as we had no ownership interest in the Plant Owners during the period. Also, under the Plan, we removed the Plant Owners’ assets of $175.0 million and liabilities of $294.4 million from our balance sheet, resulting in a net gain of $119.4 million for 2010. On October 6, 2010, we purchased a 20% ownership interest in New PE Holdco, which gave us the single largest equity position in New PE Holdco. Based on our ownership interest as well as our asset management and marketing agreements with New PE Holdco, we determined that, beginning on October 6, 2010, we were the primary beneficiary of New PE Holdco, and as such, we resumed consolidating its financial results with our financial results beginning in the fourth quarter of 2010.

 
36

 

 
Accounting for the Results of Front Range
 
Effective January 1, 2010, we adopted the new guidance to Financial Accounting Standards Board, or FASB, Accounting Standards Codification, or ASC, 810, Consolidations, which resulted in us concluding that, under the FASB’s guidance, we were no longer the primary beneficiary of Front Range and, effective January 1, 2010, we prospectively adopted the guidance resulting in a deconsolidation of the financial results of Front Range. Upon deconsolidation, on January 1, 2010, we removed assets of $62.6 million and liabilities of $18.6 million from our consolidated balance sheet and recorded a cumulative debit adjustment to retained earnings of $1.8 million. The periods presented in this report prior to the effective date of the deconsolidation continue to include related balances associated with our prior ownership interest in Front Range. Effective January 1, 2010, we began accounting for our investment in Front Range under the equity method, with equity earnings recorded in other income (expense) in the consolidated statements of operations. On October 6, 2010, we sold our ownership interest in Front Range, resulting in a loss of $12.1 million on the sale for 2010, as we reduced the carrying value of our investment in Front Range to its fair value equal to the $18.5 million sale price.
 
Selected Financial Information
 
The following selected financial information should be read in conjunction with our consolidated financial statements and notes to our consolidated financial statements included elsewhere in this report, and the other sections of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in this report.
 
Certain performance metrics that we believe are important indicators of our results of operations include:
 
   
Years Ended
December 31,
       
   
2010
   
2009
   
Percentage Variance
 
Production gallons sold (in millions)
    69.4       86.4       (19.7% )
                         
Third party gallons sold (in millions)
    202.2       86.3       134.3%  
                         
Total gallons sold (in millions)
    271.6       172.7       57.3%  
                         
Average sales price per gallon
  $ 1.96     $ 1.80       8.9%  
Corn cost per bushel—CBOT equivalent(1)
  $ 4.33     $ 3.98       8.8%  
Co-product revenues as % of delivered cost of corn(2)
    21.3%       24.6%       (13.4% )
                         
Average CBOT ethanol price per gallon (3)
  $ 1.83     $ 1.70       7.6%  
Average CBOT corn price per bushel (3)
  $ 4.29     $ 3.74       14.7%  
 

 
(1)
We exclude transportation—or “basis”—costs in our corn costs to calculate a CBOT equivalent in order to more appropriately compare our corn costs to average CBOT corn prices.
 
(2)
Co-product revenues as % of delivered cost of corn shows our yield based on sales of WDG generated from ethanol we produced.
 
(3)
Prices for 2010 exclude the three months ended September 30, 2010, as the activities of the Pacific Ethanol Plants were not consolidated in our financial results.

 
37

 

 
Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009
 
     
Years Ended
     
Dollar
Variance
     
Percentage
Variance
     
Results as a Percentage
of Net Sales for the
Years Ended
 
     
December 31,
     
Favorable
      Favorable      
December 31,
 
     
2010
     
2009
     
(Unfavorable)
     
(Unfavorable)
     
2010
     
2009
 
     
(dollars in thousands)
                         
Net sales
  $ 328,332     $ 316,560     $ 11,772       3.7 %     100.0 %     100.0 %
Cost of goods sold
    329,143       338,607       9,464       2.8 %     100.2 %     107.0 %
Gross loss
    (811 )     (22,047 )     21,236       96.3 %     (0.2 )%     (7.0 )%
Selling, general and administrative expenses
    12,956       21,458       8,502       39.6 %     3.9 %     6.8 %
Asset impairments
          252,388       252,388       100.0 %           79.7 %
Loss from operations
    (13,767 )     (295,893 )     282,126       95.3 %     (4.2 )%     (93.5 )%
Loss on investment in Front Range
    (12,146 )           (12,146 )     *       (3.7 )%      
Loss on extinguishments of debt
    (2,159 )           (2,159 )     *       (0.7 )%      
Gain from write-off of liabilities
          14,232       (14,232 )     (100.0 )%           4.5 %
Fair value adjustments on convertible notes and warrants
    (11,736 )           (11,736 )     *       (3.6 )%      
Interest expense
    (6,261 )     (13,771 )     7,510       54.5 %     (1.9 )%     (4.4 )%
Other income (expense), net
    297       (1,666 )     1,963       117.8 %     0.1 %     (0.5 )%
Loss before reorganization costs, gain from bankruptcy exit, provision for income taxes and noncontrolling interest in variable interest entities
    (45,772 )     (297,098 )     251,326       84.6 %     (13.9 )%     (93.9 )%
Reorganization costs
    (4,153 )     (11,607 )     7,454       64.2 %     (1.3 )%     (3.7 )%
Gain from bankruptcy exit
    119,408             119,408       *       36.4 %      
Provision for income taxes
                                   
Net income (loss)
    69,483       (308,705 )     378,188       122.5 %     21.2 %     (97.5 )%
Net income attributed to noncontrolling interest in variable interest entities
    4,409       552       3,857       698.7 %     1.3 %     0.2 %
Net income (loss) attributed to Pacific Ethanol, Inc.
  $ 73,892     $ (308,153 )   $ 382,045       124.0 %     22.5 %     (97.3 )%
Preferred stock dividends
    (2,847 )     (3,202 )     355       11.1 %     (0.9 )%     (1.0 )%
Income (loss) available to common stockholders
  $ 71,045     $ (311,355 )   $ 382,400       122.8 %     21.6 %     (98.4 )%
_____________
*      Not meaningful.
 
Net Sales
 
The increase in our net sales for 2010 as compared to 2009 was primarily due to the increase in third party gallons sold and an increase in our average sales price per gallon, which were partially offset by a decrease in production gallons sold.
 
Total volume of production gallons sold decreased by 20%, or 17.0 million gallons, to 69.4 million gallons for 2010 as compared to 86.4 million gallons for 2009. The decrease in production gallons sold is primarily due to our deconsolidation of Front Range for all of 2010 and the deconsolidation of the Columbia and Magic Valley facilities for the three months ended September 30, 2010. Third-party gallons sold increased by 134%, or 115.9 million gallons, to 202.2 million gallons for 2010 as compared to 86.3 million gallons for 2009. The increase in third-party gallons sold is primarily due to increased sales under our third-party ethanol marketing arrangements, including gallons sold for Front Range for all of 2010 and gallons sold for the Columbia and Magic Valley facilities for the three months ended September 30, 2010.
 
Our average sales price per gallon increased 9% to $1.96 for 2010 from an average sales price per gallon of $1.80 for 2009. This increase in average sales price per gallon is also consistent with the average CBOT price per gallon, which increased 8% to $1.83 for 2010 from $1.70 for 2009.

 
38

 

 
Cost of Goods Sold and Gross Loss
 
Our gross loss improved to $0.8 million for 2010 from $22.0 million for 2009 primarily due to higher ethanol prices and lower depreciation expense. Our gross margin decreased to negative 0.2% for 2010 as compared to negative 7.0% for 2009.
 
The improvement in gross margin resulted from higher ethanol prices and lower depreciation expense in 2010, which were partially offset by an increase in corn costs. At the end of 2009, we recognized asset impairment charges, reducing our asset base and therefore reducing our future depreciation expenses. Total depreciation expense decline 76% to $8.0 million for 2010 from $33.3 million for 2009. In addition, in 2009, we included the gross profit of Front Range in our consolidated results, however these results are not included in our 2010 results.
 
These factors were partially offset by higher corn costs. Corn is the single largest component of the total cost of our ethanol production. Our average price of corn increased by 8.8% to $4.33 per bushel in 2010 from $3.98 per bushel in 2009.
 
We are eligible to participate in the California Ethanol Producer Incentive Program through the Pacific Ethanol Plants located in California. For the year ended December 31, 2010, we recorded $0.5 million as a reduction to cost of goods sold.
 
Selling, General and Administrative Expenses
 
Our SG&A decreased by $8.5 million to $13.0 million for 2010 as compared to $21.5 million for 2009. SG&A also decreased as a percentage of net sales due to relatively flat net sales. The decrease in the amount of SG&A is primarily due to the following factors:
 
 
·
professional fees decreased by $3.4 million due to cost saving efforts and a reduction of $2.1 million in professional fees associated with fewer debt restructuring efforts;
 
 
·
SG&A associated with Front Range decreased by $2.6 million as we no longer consolidate Front Range’s financial results;
 
 
·
payroll and benefits decreased by $2.4 million due to a reduction in the total number of employees as we reduced the number of administrative positions in 2009 in response to reduced ethanol production and related support needs;
 
 
·
other general corporate expenses, including rent, decreased by $0.8 million due to a reduction in office space and other cost saving efforts; and
 
 
·
SG&A associated with the Pacific Ethanol Plants decreased by $0.3 million as we did not consolidate their financial results with our own for the three months ended September 30, 2010.
 
These decreases were partially offset by the following factors:
 
 
·
an increase in bad debt expense of $0.8 million due to a significant recovery of a trade receivable in 2009 that did not recur in 2010; and
 
 
·
an increase in noncash compensation expense of $0.5 million in 2010 due primarily to an increase in restricted stock grants to our employees and directors.

 
39

 

 
Asset Impairments
 
Our asset impairments were $252.4 million in 2009. In accordance with FASB ASC 360, Property, Plant and Equipment, we performed an impairment analysis on our long-lived assets, including our ethanol production facilities and assets associated with our suspended plant construction project in the Imperial Valley near Calipatria, California, or the Imperial Project. Based on our probability-weighted cash flows for our long-lived assets, including the then current status of the Plant Owners’ restructuring efforts as they prepared to file a plan of reorganization, we determined that these assets must be assessed for impairment. The assessments resulted in a noncash impairment charge of $250.2 million, thereby initially reducing our property and equipment by that amount. Also in accordance with FASB ASC 360, we assessed for impairment our assets associated with our Imperial Project, which resulted in an impairment charge of $2.2 million in 2009.
 
Loss on Investment in Front Range
 
On September 27, 2010, we entered into an agreement to sell our entire interest in Front Range for $18.5 million in cash. The carrying value of our interest in Front Range prior to the sale was $30.6 million. As a result, we reduced our investment in Front Range to fair value, resulting in charge of $12.1 million. We closed the sale of our interest in Front Range on October 6, 2010.
 
Loss on Extinguishments of Debt
 
We were party to agreements designed to satisfy our then outstanding debt to Lyles. Under these agreements, we issued shares to a third party which acquired outstanding debt owed to Lyles in successive tranches. During 2010, under the terms of these agreements, we issued an aggregate of 24.1 million shares of common stock, resulting in an aggregate loss of $2.2 million.
 
Gain from Write-Off of Liabilities
 
We sold the assets associated with the Imperial Project in the fourth quarter of 2009. The resulting cash proceeds and the settlement of the remaining liabilities were deemed out of our control as they had been assigned to a trustee. As a result, we wrote-off the remaining liabilities, resulting in a gain of $14.2 million in 2009.
 
Fair Value Adjustments on Convertible Notes and Warrants
 
We issued senior convertible notes and warrants in 2010 for $35.0 million in cash. The senior convertible notes and warrants are recorded at fair value. We recorded a charge of $11.7 million related to the original issuance and subsequent fair value adjustments of these instruments. The following reconciliation summarizes the initial amounts recognized for the issuance of the senior convertible notes and warrants and subsequent amounts that are recorded in the statements of operations as fair value adjustments to senior convertible notes and warrants (in thousands):
 
   
Balance Sheet
   
Statements of Operations
 
   
Convertible
Notes
   
Warrants
   
Fair Value
Gain (Loss)
 
Issuance of $35.0 million on October 6, 2010
  $ 37,474     $ 7,445     $ (9,919 )
Write-off of issuance costs
                (2,910 )
Adjustments to fair value for the period
    634       (1,727 )     1,093  
Ending balance, December 31, 2010
  $ 38,108     $ 5,718     $ 11,736  
 


 
40

 
 
 
Interest Expense
 
Interest expense decreased by $7.5 million to $6.3 million in 2010 from $13.8 million in 2009. The decrease is primarily due to the completion of the Plant Owners’ bankruptcy proceedings, resulting in reduced debt on their balance sheet. In addition, other indebtedness owed to Lyles was extinguished during 2010, further reducing interest expense for 2010 as compared to 2009.
 
Other Income (Expense), Net
 
Other income (expense) increased by $2.0 million to $0.3 million in 2010 from other expense of $1.7 million in 2009. The increase in other income (expense) is primarily due to a gain of $1.6 million associated with our acquisition of a 20% ownership interest in New PE Holdco, as we paid for our ownership interest at a discount to the fair value of the net assets of New PE Holdco.
 
Reorganization Costs and Gain from Bankruptcy Exit
 
In accordance with FASB ASC 852, Reorganizations, revenues, expenses, realized gains and losses, and provisions for losses that can be directly associated with the reorganization and restructuring of our business must be reported separately as reorganization items in the statements of operations. We wrote-off a portion of our unamortized deferred financing fees on the debt which was considered to be unlikely to be repaid. During 2009, the Plant Owners settled a prepetition accrued liability with a vendor, resulting in a realized gain. Professional fees directly related to the reorganization include fees associated with advisors to the Plant Owners, unsecured creditors, secured creditors and administrative costs in complying with reporting rules under the Bankruptcy Code.
 
The Plant Owners’ reorganization costs consisted of the following (in thousands):
 
   
December 31,
 
   
2010
   
2009
 
Professional fees
  $ 4,026     $ 5,198  
Write-off of unamortized deferred financing fees
          7,545  
Settlement of accrued liability
          (2,008 )
DIP financing fees
          750  
Trustee fees
    127       122  
Total
  $ 4,153     $ 11,607  
 
As of the Effective Date, we no longer owned the Plant Owners. As a result, we removed the net liabilities from our consolidated financial statements, resulting in a net gain from bankruptcy exit of $119.4 million.
 
Net Loss Attributed to Noncontrolling Interest in Variable Interest Entities
 
Net loss attributed to noncontrolling interest in variable interest entities relate to the consolidated treatment of Front Range in 2009 and New PE Holdco for the three months ended December 31, 2010, both of which are variable interest entities, and represent the noncontrolling interest of others in the earnings of these entities. We consolidated their entire income statements for the applicable periods. However, because we owned less than 100% of each entity, we reduced our net income or increased our net loss for the noncontrolling interest, which represents the remaining ownership interest that we do not own.

 
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Preferred Stock Dividends
 
Shares of our Series B Cumulative Convertible Preferred Stock, or Series B Preferred Stock, are entitled to quarterly cumulative dividends payable in arrears in an amount equal to 7% per annum of the purchase price per share of the Series B Preferred Stock. We have accrued dividends of $2.8 million and $3.2 million for 2010 and 2009, respectively, resulting in total accrued and unpaid dividends of $6.0 million in respect of our Series B Preferred Stock.
 
Liquidity and Capital Resources
 
During 2010, we funded our operations primarily from cash provided by operations, borrowings under our credit facilities and proceeds from the issuance and sale of our Convertible Notes and Warrants. As of December 31, 2010, we had positive working capital of $10.1 million. As of December 31, 2010 and 2009, we had cash and cash equivalents of $8.7 million and $17.5 million, respectively.
 
Our current available capital resources consist of cash on hand and amounts available for borrowing under Kinergy’s credit facility. We expect that our future available capital resources will consist primarily of our remaining cash balances, amounts available for borrowing, if any, under Kinergy’s credit facility, cash generated from Kinergy’s ethanol marketing business, fees paid under our asset management agreement relating to our operation of the Pacific Ethanol Plants, distributions, if any, in respect of our ownership interest in New PE Holdco, and the remaining proceeds of any future debt and/or equity financings.
 
On June 30, 2010, we received a letter from The NASDAQ Stock Market, or NASDAQ, indicating that the bid price of our common stock for the last 30 consecutive trading days had closed below the minimum $1.00 per share required for continued listing. We were provided an initial period of 180 calendar days, or until December 27, 2010, during which to regain compliance. We failed to regain compliance by December 27, 2010 but, due to our transition from The NASDAQ Global Market to The NASDAQ Capital Market, we were provided a final additional period of 180 calendar days, or until June 27, 2011, during which to regain compliance. We may be unable to regain compliance with the closing bid price requirement by June 27, 2011. A delisting of our common stock is likely to reduce the liquidity of our common stock and may inhibit or preclude our ability to raise additional financing and may also materially and adversely impact our credit terms with our vendors. See “Risk Factors.”
 
We believe that current and future available capital resources, revenues generated from operations, and other existing sources of liquidity, including our credit facilities, will be adequate to meet our anticipated working capital and capital expenditure requirements for at least the next twelve months. If, however, we are unable to service the principal and/or interest payments under the Convertible Notes through the issuance of shares of our common stock, if our capital requirements or cash flow vary materially from our current projections, if unforeseen circumstances occur, or if we require a significant amount of cash to fund future acquisitions, we may require additional financing. Our failure to raise capital, if needed, could restrict our growth, or hinder our ability to compete.
 
Quantitative Year-End Liquidity Status
 
We believe that the following amounts provide insight into our liquidity and capital resources. The following selected financial information should be read in conjunction with our consolidated financial statements and notes to consolidated financial statements included elsewhere in this report, and the other sections of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in this report (dollars in thousands):
 

 
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As of and for the
Year Ended December 31,
       
   
2010
   
2009
   
Variance
 
Current assets
  $ 57,962     $ 48,776       18.8%  
Current liabilities
  $ 47,831     $ 96,431       (50.4% )
Property and equipment, net
  $ 168,976     $ 243,733       (30.7% )
Notes payable, net of current portion
  $ 84,981     $ 12,739       567.1%  
Cash used in operating activities
  $ (36,921 )   $ (6,302 )     (485.9% )
Working capital
  $ 10,131     $ (47,655 )     121.3%  
Working capital ratio
    1.21       0.51       137.3%  
 
Change in Working Capital and Cash Flows
 
Working capital increased from a deficit of $47.7 million at December 31, 2009 to positive working capital $10.1 million at December 31, 2010 as a result of an increase in current assets of $9.2 million and a significant decrease in current liabilities of $48.6 million.
 
Current assets increased primarily due to an increase in accounts receivable and inventories, as two additional Pacific Ethanol Plants were operating at the end of 2010 as compared to 2009. At December 31, 2009, only the Columbia facility was operating, whereas, at December 31, 2010, the Columbia, Magic Valley and Stockton facilities were operating.
 
Current liabilities decreased significantly primarily due to a significant reduction in current indebtedness which was extinguished during 2010 in connection with the Plant Owners’ emergence from bankruptcy, which was partially offset by our issuance of new indebtedness represented by the Convertible Notes.
 
Cash used in our operating activities of $36.9 million resulted primarily from our net income, net of an $83.3 million reduction for noncash items, a $13.8 million increase in accounts receivable, a $7.5 million increase in inventories and a $2.0 million decrease in accounts payable, which were partially offset by a reduction of $0.1 million in other net assets.
 
Cash used in our investing activities of $13.4 million resulted primarily from our $19.5 million net purchase of our interest in New PE Holdco, a $10.5 million impact from our deconsolidation of Front Range, a $1.3 million impact from the Plant Owners’ exit from bankruptcy and $0.6 million in additions to property and equipment, which were partially offset by the $18.5 million sale of our interest in Front Range.
 
Cash provided by our financing activities of $41.5 million resulted primarily from $35.0 million in proceeds from the issuance and sale of our Convertible Notes and Warrants, $17.5 million in proceeds from our other borrowings, $5.2 million in proceeds from our debtor-in-possession financing associated with the Plant Owners’ bankruptcy, which were partially offset by $13.3 million in principal payments on related party indebtedness and $2.9 million in debt issuance costs.
 
Convertible Notes
 
On October 6, 2010, we raised $35.0 million through the issuance and sale of $35.0 million in principal amount of Initial Notes and Initial Warrants to purchase an aggregate of 20,588,235 shares of our common stock. On January 7, 2011, under the terms of exchange agreements with the holders of the Initial Notes and Initial Warrants, we issued $35.0 million in principal amount of Convertible Notes in exchange for the Initial Notes and issued Warrants to purchase an aggregate of 20,588,235 shares of our common stock in exchange for the Initial Warrants.

 
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The transactions contemplated by the exchange agreements were entered into to, among other things, clarify previously ambiguous language in the Initial Notes and Initial Warrants, provide us with additional time to meet our registration obligations and to add additional flexibility to our ability to incur indebtedness subordinated to the Convertible Notes.
 
The Convertible Notes mature on January 6, 2012, subject to the right of the lenders to extend the date (i) if an event of default under the Convertible Notes has occurred and is continuing or any event shall have occurred and be continuing that with the passage of time and the failure to cure would result in an event of default under the Convertible Notes, and (ii) for a period of 20 business days after the consummation of specific types of transactions involving a change of control. The Convertible Notes bear interest at the rate of 8% per annum, which is compounded monthly. The interest rate will increase to 15% per annum upon the occurrence of an event of default.
 
The holders of the Convertible Notes are entitled to interest, amortization payments and other amounts. We are required to pay a late charge of 15% on any amount of principal or other amounts due which are not paid when due.
 
Interest on the Convertible Notes is payable in arrears on specified installment dates. If a holder elects to convert or redeem all or any portion of a Convertible Note prior to the maturity date, all interest that would have accrued on the amount being converted or redeemed through the maturity date will also be payable. If we elect to redeem all or any portion of a Convertible Note prior to the maturity date, all interest that would have accrued through the maturity date on the amount redeemed will also be payable.
 
We are obligated to make amortization payments with respect to the principal amount of each Convertible Note on each of the following dates, collectively, the Installment Dates: (i) March 7, 2011; (ii) May 2, 2011; and (iii) the first trading day of each calendar month thereafter. The amortizing portion of the principal of each Convertible Note, or Monthly Amortization Amount, will equal the fraction of each Convertible Note, the numerator of which is equal to the original outstanding principal amount of the Convertible Note and the denominator of which is equal to the number of Installment Dates remaining until the maturity date.
 
We may elect to pay the Monthly Amortization Amount and applicable interest in cash or shares of our common stock, at our election, subject to the satisfaction of certain conditions.
 
All amounts due under the Convertible Notes are convertible at any time, in whole or in part, at the option of the holders into shares of our common stock at a specified conversion price, or Conversion Price. The Convertible Notes were initially convertible into shares of our common stock at the initial Conversion Price of $0.85 per share, or Fixed Conversion Price. The Convertible Notes are now convertible into shares of our common stock at a price determined as follows:
 
 
·
If we have elected to make an amortization payment in shares of common stock and the date of conversion occurs during the 15 calendar day period following (and including) the applicable Installment Date, or Initial Period, the Conversion Price will equal the lesser of (i) the Fixed Conversion Price, and (ii) the average of the volume weighted average prices of our common stock for each of the five lowest trading days during the 20 trading day period immediately prior to the Initial Period.

 
·
If we have elected to make an amortization payment in shares of common stock and the date of conversion occurs during the period beginning on the 16th calendar day after the applicable Installment Date and ending on the day immediately prior to the next Installment Date or the maturity date, the Conversion Price will equal the lesser of (i) the Fixed Conversion Price, and (ii) the closing bid price of our common stock on the trading date immediately before the date of conversion.

 
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In addition, if an event of default has occurred and is continuing, the Conversion Price will be equal to the lesser of (i) the Fixed Conversion Price, and (ii) the closing bid price of our common stock on the trading date immediately before the date of conversion.
 
The Fixed Conversion Price is subject to “full ratchet” anti-dilution adjustment where if we were to issue or are deemed to have issued specified securities at a price lower than the then applicable Fixed Conversion Price, the Fixed Conversion Price will immediately decline to equal the price at which we issued or are deemed to have issued the securities. In addition, if we sell or issue any securities with “floating” conversion prices based on the market price of our common stock, the holder of a Convertible Note will have the right to substitute that “floating” conversion price for the Fixed Conversion Price upon conversion of all or part of the Convertible Note.
 
We have agreed to pay “buy-in” damages of the converting holder if we fail to timely deliver common stock upon conversion of the Convertible Notes.
 
New PE Holdco Term Debt and Working Capital Line of Credit
 
 
On the Effective Date, approximately $294.4 million in prepetition and post petition secured indebtedness of the Plant Owners was restructured under a Credit Agreement entered into on June 25, 2010 among the Plant Owners, as borrowers, and West LB, AG, New York Branch, and other lenders. Under the Plan, the Plant Owners’ existing prepetition and post petition secured indebtedness of approximately $294.4 million was restructured to consist of approximately $50.0 million in three-year term loans and a new three-year revolving credit facility of up to $35.0 million to fund working capital requirements.
 
Notes Payable to Related Parties
 
On March 31, 2009, our Chairman of the Board and our Chief Executive Officer provided funds in the aggregate amount of $2.0 million for general working capital purposes, in exchange for two unsecured promissory notes payable by us. Interest on the unpaid principal amounts accrues at a rate per annum of 8.00%. All principal and accrued and unpaid interest on the promissory notes was due and payable in March 2010. The maturity date of these notes was initially extended to January 5, 2011. On October 29, 2010, we repaid $750,000 of principal on these notes and all accrued and unpaid interest. On November 5, 2010, we further extended the maturity date of these notes to March 31, 2012.
 
Kinergy Operating Line of Credit
 
Kinergy maintains a credit facility in the aggregate amount of up to $20.0 million. The credit facility expires on December 31, 2013. Interest accrues under the credit facility at a rate equal to (i) the three-month London Interbank Offered Rate (LIBOR), plus (ii) a specified applicable margin ranging between 3.50% and 4.50%. The credit facility’s monthly unused line fee is 0.50% of the amount by which the maximum credit under the facility exceeds the average daily principal balance. Kinergy is also required to pay customary fees and expenses associated with the credit facility and issuances of letters of credit. In addition, Kinergy is responsible for a $3,000 monthly servicing fee. Payments that may be made by Kinergy to Pacific Ethanol as reimbursement for management and other services provided by Pacific Ethanol to Kinergy are limited to $750,000 per fiscal quarter in 2011, $800,000 per fiscal quarter in 2012, and $850,000 per fiscal quarter in 2013. Kinergy is required to meet specified EBITDA and fixed coverage ratio financial covenants under the credit facility and is prohibited from incurring any additional indebtedness (other than specific intercompany indebtedness) or making any capital expenditures in excess of $100,000 absent the lender’s prior consent. Kinergy’s obligations under the credit facility are secured by a first-priority security interest in all of its assets in favor of the lender. We have guaranteed all of Kinergy’s obligations under the credit facility.

 
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Critical Accounting Policies
 
Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of net sales and expenses for each period. The following represents a summary of our critical accounting policies, defined as those policies that we believe are the most important to the portrayal of our financial condition and results of operations and that require management’s most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effects of matters that are inherently uncertain.
 
Revenue Recognition
 
We recognize revenue when it is realized or realizable and earned. We consider revenue realized or realizable and earned when there is persuasive evidence of an arrangement, delivery has occurred, the sales price is fixed or determinable, and collection is reasonably assured.
 
We derive revenue primarily from sales of ethanol and related co-products. We recognize revenue when title transfers to our customers, which is generally upon the delivery of these products to a customer’s designated location. These deliveries are made in accordance with sales commitments and related sales orders entered into with customers either verbally or in written form. The sales commitments and related sales orders provide quantities, pricing and conditions of sales. In this regard, we engage in three basic types of revenue generating transactions:
 
 
·
As a producer. Sales as a producer consist of sales of our inventory produced at the Pacific Ethanol Plants.
 
 
·
As a merchant. Sales as a merchant consist of sales to customers through purchases from third-party suppliers in which we may or may not obtain physical control of the ethanol or co-products, though ultimately titled to us, in which shipments are directed from our suppliers to our terminals or direct to our customers but for which we accept the risk of loss in the transactions.
 
 
·
As an agent. Sales as an agent consist of sales to customers through purchases from third-party suppliers in which, depending upon the terms of the transactions, title to the product may technically pass to us, but the risks and rewards of inventory ownership remain with third-party suppliers as we receive a predetermined service fee under these transactions and therefore act predominantly in an agency capacity.
 
Revenue from sales of third-party ethanol and its co-products is recorded net of costs when we are acting as an agent between the customer and supplier and gross when we are a principal to the transaction. Several factors are considered to determine whether we are acting as an agent or principal, most notably whether we are the primary obligor to the customer, whether we have inventory risk and related risk of loss or whether we add meaningful value to the vendor’s product or service. Consideration is also given to whether we have latitude in establishing the sales price or have credit risk, or both.
 
We record revenues based upon the gross amounts billed to our customers in transactions where we act as a producer or a merchant and obtain title to ethanol and its co-products and therefore own the product and any related, unmitigated inventory risk for the ethanol, regardless of whether we actually obtain physical control of the product. When we act in an agency capacity, we record revenues on a net basis, or our predetermined agency fees and any associated freight only, based upon the amount of net revenues retained in excess of amounts paid to suppliers.

 
46

 

 
Consolidation of Variable Interest Entities
 
We have determined that Front Range met the definition of a variable interest entity through our prior ownership interest in that entity. Since our initial acquisition of our ownership interest in Front Range through December 31, 2009, we determined that we were the primary beneficiary of Front Range and we were therefore required to treat Front Range as a consolidated subsidiary for financial reporting purposes rather than use equity investment accounting treatment. As a result, we consolidated the financial results of Front Range, including its entire balance sheet with the balance of the noncontrolling interest displayed as a component of equity, and its income statement after intercompany eliminations with an adjustment for the noncontrolling interest as net income (loss) attributed to noncontrolling interest in variable interest entity, through December 31, 2009.
 
Effective January 1, 2010, we adopted new accounting guidance. Under the new guidance, we concluded that we were no longer the primary beneficiary of Front Range. As a result, effective January 1, 2010, we deconsolidated the financial results of Front Range. Our conclusion that we were no longer the primary beneficiary of Front Range was based upon our determination that we did not have the power to direct most of the activities that most significantly impact Front Range’s economic performance. Some of those activities include efficient management and operations of its ethanol production facility, procurement of feedstock, sale of co-products and implementation of risk management strategies.
 
On October 6, 2010, we acquired a 20% ownership interest in New PE Holdco. We have determined that New PE Holdco is a variable interest entity. We also determined that we are the primary beneficiary of New PE Holdco and therefore we are required to consolidate the results of New PE Holdco in the same manner as we previously accounted for Front Range, as discussed above.
 
These determinations will be reviewed for appropriateness at each future reporting period.
 
Convertible Notes and Warrants Carried at Fair Value
 
We have elected the fair value alternative for our Convertible Notes in order to simply our accounting and reporting. We have also recorded our Warrants issued in connection with our Convertible Notes at fair value. We believe the valuation of the Convertible Notes and Warrants is a critical accounting estimate because valuation estimates obtained from third parties involve inputs other than quoted prices to value the conversion feature. Changes in such estimates, and in particular certain of the inputs to the valuation, can be volatile from period to period and may markedly impact the total mark-to-market on the Convertible Notes and Warrants recorded as fair value adjustments in our consolidated statements of operations.
 
We recorded fair value adjustments on convertible notes and warrants of $11.7 million for the year ended December 31, 2010.
 
Impairment of Long-Lived and Intangible Assets
 
Our long-lived assets have been primarily associated with the Pacific Ethanol Plants, reflecting the original cost of construction, adjusted for any prior impairment.

 
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We evaluate impairment of long-lived assets in accordance with FASB ASC 360. We assess the impairment of long-lived assets, including property and equipment and purchased intangibles subject to amortization, when events or changes in circumstances indicate that the fair value of each asset (or asset group) could be less than the net book value of the asset (or asset group). We assess long-lived assets for impairment by first determining the forecasted, undiscounted cash flows each asset (or asset group) is expected to generate plus the net proceeds expected from the sale of the asset (or asset group). If the amount of proceeds is less than the carrying value of the asset (or asset group), we then determine the fair value of the asset (or asset group). An impairment loss would be recognized when the fair value is less than the related net book value, and an impairment expense would be recorded in the amount of the difference. Forecasts of future cash flows are judgments based on our experience and knowledge of our operations and the industries in which we operate. These forecasts could be significantly affected by future changes in market conditions, the economic environment, including inflation, and the purchasing decisions of our customers.
 
We review our intangible assets with indefinite lives at least annually or more frequently if impairment indicators arise. In our review, we determine the fair value of these assets using market multiples and discounted cash flow modeling and compare it to the net book value of the acquired assets.
 
We recognized asset impairment charges associated with the Pacific Ethanol Plants and our Imperial Project in the aggregate amount of $252.4 million in 2009. We did not recognize any asset impairment charges in 2010.
 
Allowance for Doubtful Accounts
 
We sell ethanol primarily to gasoline refining and distribution companies and sell WDG to dairy operators and animal feed distributors. We had significant concentrations of credit risk from sales of our ethanol as of December 31, 2010 and 2009, as described in Note 1 to our consolidated financial statements included elsewhere in this report. However, those ethanol customers historically have had good credit ratings and historically we have collected amounts that were billed to those customers. Receivables from customers are generally unsecured. We continuously monitor our customer account balances and actively pursue collections on past due balances.
 
We maintain an allowance for doubtful accounts for balances that appear to have specific collection issues. Our collection process is based on the age of the invoice and requires attempted contacts with the customer at specified intervals. If after a specified number of days, we have been unsuccessful in our collection efforts, we consider recording a bad debt allowance for the balance in question. We would eventually write-off accounts included in our allowance when we have determined that collection is not likely. The factors considered in reaching this determination are the apparent financial condition of the customer, and our success in contacting and negotiating with the customer.
 
We recognized a recovery of bad debt expense of $0.2 million and $1.0 million for 2010 and 2009, respectively.

 
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Impact of New Accounting Pronouncements
 
On June 12, 2009, the FASB amended its guidance to ASC 810, Consolidations, surrounding a company’s analysis to determine whether any of its variable interest entities constitute controlling financial interests in a variable interest entity. This analysis identifies the primary beneficiary of a variable interest entity as the enterprise that has both of the following characteristics: (i) the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance, and (ii) the obligation to absorb losses of the entity that could potentially be significant to the variable interest entity. Additionally, an enterprise is required to assess whether it has an implicit financial responsibility to ensure that a variable interest entity operates as designed when determining whether it has the power to direct the activities of the variable interest entity that most significantly impact the entity’s economic performance. The new guidance also requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. Effective January 1, 2010, we adopted this guidance and concluded that we were no longer the primary beneficiary of Front Range. As a result, effective January 1, 2010, we deconsolidated the financial results of Front Range from our own.
 
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
 
Not applicable.
 
Item 8.
Financial Statements and Supplementary Data.
 
Reference is made to the financial statements, which begin at page F-1 of this report.
 
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
 
None.
 
Item 9A.
Controls and Procedures.
 
We conducted an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities and Exchange Act of 1934, as amended (“Exchange Act”), means controls and other procedures of a company that are designed to ensure that information required to be disclosed by the company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure controls and procedures also include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded as of December 31, 2010 that our disclosure controls and procedures were effective at a reasonable assurance level.
 
 
 
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Management’s Report on Internal Control Over Financial Reporting
 
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is 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. Our internal control over financial reporting includes those policies and procedures that:
 
 
(i)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
 
 
(ii)
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
 
 
(iii)
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material affect on our 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.
 
A material weakness is defined by the Public Company Accounting Oversight Board’s Audit Standard No. 5 as being a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis by the company’s internal controls.
 
Management assessed and evaluated the effectiveness of our internal control over financial reporting as of December 31, 2010. Based on the results of management’s assessment and evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of December 31, 2010, our internal control over financial reporting was effective.
 
In making its assessment of our internal control over financial reporting, management used criteria issued by the Committee of Sponsoring Organizations of the Treadway Commission in its Internal Control—Integrated Framework.
 
Management's report was not subject to attestation by our certified registered public accounting firm pursuant to rules established by the Securities and Exchange Commission that permit us to provide only management's report in this Annual Report on Form 10-K.
 

 
 
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Inherent Limitations on the Effectiveness of Controls
 
Management does not expect that our disclosure controls and procedures or our internal control over financial reporting will prevent or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control systems are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in a cost-effective control system, no evaluation of internal control over financial reporting can provide absolute assurance that misstatements due to error or fraud will not occur or that all control issues and instances of fraud, if any, have been or will be detected.
 
These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of a simple error or mistake. Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is based in part on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Projections of any evaluation of controls effectiveness to future periods are subject to risks. Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies or procedures.
 
Changes in Internal Control over Financial Reporting
 
There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Ex change Act) during the most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
 
Item 9B.
Other Information.
 
None.

 
51

 

PART III
 
Item 10.
Directors, Executive Officers and Corporate Governance.
 
The information under the captions “Information about our Board of Directors, Board Committees and Related Matters” and “Section 16(a) Beneficial Ownership Reporting Compliance,” appearing in the Proxy Statement, is hereby incorporated by reference.
 
Item 11.
Executive Compensation.
 
The information under the caption “Executive Compensation and Related Information,” appearing in the Proxy Statement, is hereby incorporated by reference.
 
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
 
The information under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information,” appearing in the Proxy Statement, is hereby incorporated by reference.
 
Item 13.
Certain Relationships and Related Transactions, and Director Independence.
 
The information under the captions “Certain Relationships and Related Transactions” and “Information about our Board of Directors, Board Committees and Related Matters—Director Independence” appearing in the Proxy Statement, is hereby incorporated by reference.
 
Item 14.
Principal Accounting Fees and Services.
 
The information under the caption “Audit Matters—Principal Accountant Fees and Services,” appearing in the Proxy Statement, is hereby incorporated by reference.
 
PART IV
 
Item 15.
Exhibits, Financial Statement Schedules.
 
(a)(1) Financial Statements
 
Reference is made to the financial statements listed on and attached following the Index to Consolidated Financial Statements contained on page F-1 of this report.
 
(a)(2) Financial Statement Schedules
 
None.
 
(a)(3) Exhibits
 
Reference is made to the exhibits listed on the Index to Exhibits.


 
52

 




 
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 

Report of Independent Registered Public Accounting Firm
F-2
   
Consolidated Balance Sheets as of December 31, 2010 and 2009
F-3
   
Consolidated Statements of Operations for the Years Ended December 31, 2010 and 2009
F-5
   
Consolidated Statements of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2010 and 2009
F-6
   
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010 and 2009
F-7
   
Notes to Consolidated Financial Statements
F-9
 

 

 
F-1

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Stockholders
Pacific Ethanol, Inc.
 
We have audited the accompanying consolidated balance sheets of Pacific Ethanol, Inc. (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements 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. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Pacific Ethanol, Inc. as of December 31, 2010 and 2009, and the results of its operations and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.
 
/s/ HEIN & ASSOCIATES LLP
 
Irvine, California
March 31, 2011




 
F-2

 

PACIFIC ETHANOL, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except shares and par value)

   
December 31,
 
ASSETS
 
2010
   
2009
 
             
Current Assets:
           
Cash and cash equivalents
  $ 8,736     $ 17,545  
Accounts receivable, net of allowance for doubtful accounts of $287 and $1,016, respectively
    25,855       12,765  
Inventories
    17,306       12,131  
Prepaid inventory
    2,715       3,192  
Other current assets
    3,350       3,143  
Total current assets
    57,962       48,776  
                 
Total property and equipment, net
    168,976       243,733  
Other Assets:
               
Intangible assets, net
    5,382       5,156  
Other assets
    1,763       1,154  
Total other assets
    7,145       6,310  
Total Assets (a)
  $ 234,083     $ 298,819  
__________
 
(a)
Assets of the consolidated variable interest entities that can only be used to settle obligations of those entities were $183,652 and $61,955 as of December 31, 2010 and 2009, respectively.


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


 
F-3

 

PACIFIC ETHANOL, INC.
CONSOLIDATED BALANCE SHEETS (CONTINUED)
(in thousands, except shares and par value)

   
December 31,
 
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
 
2010
   
2009
 
Current Liabilities:
           
Accounts payable – trade
  $ 6,472     $ 8,182  
Accrued liabilities
    3,236       7,063  
Other liabilities – related parties
          2,851  
Current portion – long-term debt (including $0 and $33,500 due to a related party, respectively, and $38,108 and $0 at fair value, respectively)
    38,108       77,364  
Derivative instruments
    15       971  
Total current liabilities
    47,831       96,431  
                 
Long-term debt, net of current portion
    84,981       12,739  
Accrued preferred dividends
    6,050       3,202  
Other liabilities
    7,406       1,828  
Liabilities subject to compromise
          242,417  
Total Liabilities (b)
    146,268       356,617  
Commitments and contingencies (Notes 1, 5, 6 and 12)
               
Stockholders’ Equity (Deficit):
               
Preferred stock, $0.001 par value; 10,000,000 shares authorized:
               
   Series A: 1,684,375 shares authorized; 0 shares issued and outstanding as of December 31, 2010 and 2009
           
   Series B: 2,109,772 shares authorized; 1,455,924 and 2,346,152 shares issued and outstanding as of December 31, 2010 and 2009, respectively; liquidation preference of $34,440 as of December 31, 2010
    1       2  
Common stock, $0.001 par value; 300,000,000 shares authorized; 90,427,009 and 57,469,598 shares issued and outstanding as of December 31, 2010 and 2009, respectively
    90       57  
Additional paid-in capital
    504,546       480,948  
Accumulated deficit
    (511,794 )     (581,076 )
Total Pacific Ethanol, Inc. Stockholders’ Equity (Deficit)
    (7,157 )     (100,069 )
Noncontrolling interest in variable interest entities
    94,972       42,271  
Total stockholders’ equity (deficit)
    87,815       (57,798 )
Total Liabilities and Stockholders’ Equity (Deficit)
  $ 234,083     $ 298,819  
___________
 
(b)
Liabilities of the variable interest entities for which creditors do not have recourse to the general credit of the Company were $74,939 and $18,613, as of December 31, 2010 and 2009, respectively.
 

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

 
F-4

 

PACIFIC ETHANOL, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)

   
Years Ended December 31,
 
   
2010
   
2009
 
Net sales
  $ 328,332     $ 316,560  
Cost of goods sold
    329,143       338,607  
Gross loss
    (811 )     (22,047 )
Selling, general and administrative expenses
    12,956       21,458  
Asset impairments
          252,388  
Loss from operations
    (13,767 )     (295,893 )
Loss on investment in Front Range
    (12,146 )      
Loss on extinguishments of debt
    (2,159 )      
Gain from write-off of liabilities
          14,232  
Fair value adjustments on convertible notes and warrants
    (11,736 )      
Interest expense, net
    (6,261 )     (13,771 )
Other expense, net
    297       (1,666 )
Loss before reorganization costs, gain from bankruptcy exit and provision for income taxes
    (45,772 )     (297,098 )
Reorganization costs
    (4,153 )     (11,607 )
Gain from bankruptcy exit
    119,408        
Provision for income taxes
           
Net income (loss)
    69,483       (308,705 )
Net loss attributed to noncontrolling interest in variable interest entities
    4,409       552  
Net income (loss) attributed to Pacific Ethanol, Inc.
  $ 73,892     $ (308,153 )
Preferred stock dividends
  $ (2,847 )   $ (3,202 )
Income (loss) available to common stockholders
  $ 71,045     $ (311,355 )
Income (loss) per share, basic
  $ 0.97     $ (5.45 )
Income (loss) per share, diluted
  $ 0.80     $ (5.45 )
Weighted-average shares outstanding, basic
    73,600       57,084  
Weighted-average shares outstanding, diluted
    93,647       57,084  


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

 
F-5

 

 
PACIFIC ETHANOL, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2010 and 2009
(in thousands)
 
   
Preferred Stock
   
Common Stock
   
Additional
Paid-In
    Accumulated     Non-controlling Interest in        
   
Shares
   
Amount
   
Shares
    Amount    
Capital
    Deficit     VIE    
Total
 
Balances, January 1, 2009
    2,346     $ 2       57,750     $ 58     $ 479,034     $ (269,721 )   $ 42,823     $ 252,196  
Stock-based compensation expense – restricted stock to employees and directors, net of cancellations
                (280 )     (1 )     1,914                   1,913  
Preferred stock dividends
                                  (3,202 )           (3,202 )
Net loss
                                  (308,153 )     (552 )     (308,705 )
Balances, December 31, 2009
    2,346     $ 2       57,470     $ 57     $ 480,948     $ (581,076 )   $ 42,271     $ (57,798 )
Deconsolidation of Front Range
        $           $     $     $ (1,763 )   $ (42,271 )   $ (44,034 )
Consolidation of New PE Holdco
                                        99,381       99,381  
Stock-based compensation expense – restricted stock to employees and directors, net of cancellations
                3,921       4       2,467                   2,471  
Conversion of preferred stock to common stock
    (890 )     (1 )     4,949       5       (4 )                  
Shares issued in debt extinguishments
                24,087       24       21,135                   21,159  
Preferred stock dividends
                                  (2,847 )           (2,847 )
Net income (loss)
                                  73,892       (4,409 )     69,483  
Balances, December 31, 2010
    1,456     $ 1       90,427     $ 90     $ 504,546     $ (511,794 )   $ 94,972     $ 87,815  

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


 
F-6

 

PACIFIC ETHANOL, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
 
   
For the Years Ended December 31,
 
   
2010
   
2009
 
Operating Activities:
           
Net income (loss)
  $ 69,483     $ (308,705 )
Adjustments to reconcile net income (loss) to cash used in operating activities:
               
Non-cash reorganization costs:
               
Gain on bankruptcy exit
    (119,408 )      
Write-off of unamortized deferred financing fees
          7,545  
Settlement of accrued liability
          (2,008 )
Loss on investment in Front Range, held for sale
    12,146        
Fair value adjustments on convertible notes and warrants
    11,736        
Loss on extinguishments of debt
    2,159        
Asset impairments
          252,388  
Bargain purchase of New PE Holdco
    (1,566 )      
Gain from write-off of liabilities
          (14,232 )
Depreciation and amortization of intangibles
    9,110       34,876  
Inventory valuation
    (490 )     873  
Gain on derivative instruments
    (1,049 )     (3,671 )
Amortization of deferred financing costs
    1,001       1,193  
Non-cash compensation
    2,471       1,924  
Equity earnings on Front Range
    928        
Bad debt recovery
    (184 )     (955 )
Changes in operating assets and liabilities:
               
Accounts receivable
    (13,789 )     12,015  
Restricted cash
          2,315  
Inventories
    (7,462 )     5,404  
Prepaid expenses and other assets
    (516 )     2,434  
Prepaid inventory
    477       (1,176 )
Accounts payable and accrued expenses
    (1,968 )     3,478  
Net cash used in operating activities
  $ (36,921 )   $ (6,302 )
Investing Activities:
               
Additions to property and equipment
  $ (643 )   $ (4,304 )
Proceeds from sale of investment in Front Range
    18,500        
Investment in New PE Holdco, net of cash acquired
    (19,494 )      
Net cash impact of deconsolidation of Front Range
    (10,486 )      
Net cash impact of bankruptcy exit
    (1,301 )      
Proceeds from sales of available-for-sale investments
          7,679  
Net cash provided by (used in) investing activities
  $ (13,424 )   $ 3,375  
Financing Activities:
               
Proceeds from convertible notes and warrants
  $ 35,000     $  
Payments for debt issuance costs
    (2,909 )      
Proceeds from borrowings under DIP financing
    5,173       19,827  
Proceeds from related party borrowings
          2,000  
Proceeds from other borrowings
    17,522        
Principal payments paid on related party borrowings
    (13,250 )      
Principal payments paid on other borrowings
          (12,821 )
Net cash provided by financing activities